Unassociated Document

APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

141

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

As a public utility, APCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 960,000 retail customers in its service territory in southwestern Virginia and southern West Virginia. APCo consolidates Cedar Coal Company, Central Appalachian Coal Company and Southern Appalachian Coal Company, its wholly-owned subsidiaries. APCo sells power at wholesale to municipalities.

The Interconnection Agreement permits the AEP East Companies to pool their generation assets on a cost basis. It establishes an allocation method for generating capacity among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. Members of the Interconnection Agreement are compensated for their costs of energy delivered and charged for energy received. The capacity reserve relationship of the Interconnection Agreement members changes as generating assets are added, retired or sold and relative peak demand changes. The Interconnection Agreement calculates each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the MLR, which determines each member’s percentage share of revenues and costs. The addition of the Dresden Plant in January 2012 and removal of OPCo’s Sporn Plant, Unit 5 in September 2011 changed the capacity reserve relationship of the members.

Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and gas risk management activities based upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East Companies and trading and marketing activities originating in SPP generally accruing to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among the AEP East Companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months.

AEPSC conducts power, gas, coal and emission allowance risk management activities on APCo’s behalf. APCo shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the other AEP East Companies, PSO and SWEPCo. Power and gas risk management activities are allocated based on the Interconnection Agreement and the SIA. APCo shares in coal and emission allowance risk management activities based on its proportion of fossil fuels burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and, to a lesser extent, gas, coal and emission allowances. The electricity, gas, coal and emission allowance contracts include physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.

To minimize the credit requirements and operating constraints when operating within PJM, the AEP East Companies, as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East Companies against all balances due to the AEP East Companies and to hold PJM harmless from actions that any one or more AEP East Companies may take with respect to PJM.

APCo is jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East Companies related to power purchase and sale activity pursuant to the SIA.

142

Regulatory Activity

Plant Transfers and Termination of Interconnection Agreement

Based upon the PUCO’s approval of OPCo’s corporate separation plan in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations. The AEP East Companies also requested FERC approval to transfer at net book value OPCo’s current two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer at net book value OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests (780 MW each). Additionally, the AEP East Companies asked the FERC to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate their respective power supply resources. Under the PCA, APCo, I&M and KPCo would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. Intervenors have opposed several of these filings. The AEP East Companies have responded and continue to pursue approvals from the FERC. A decision from the FERC is expected in mid-2013.

In December 2012, APCo filed requests with the Virginia SCC and the WVPSC for approval of the Amos Plant and Mitchell Plant transfers discussed above. Hearings at the Virginia SCC and the WVPSC are scheduled for April 2013 and July 2013, respectively. If the transfers are approved, APCo anticipates seeking cost recovery when it filed its next base rate case.

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

Securitization of Regulatory Asset

In March 2012, West Virginia passed securitization legislation which allows the WVPSC to establish a regulatory framework to securitize certain deferred ENEC balances and other ENEC related assets. In August 2012, APCo and WPCo filed with the WVPSC a request for a financing order to securitize $422 million related to APCo’s December 2011 under-recovered ENEC deferral balance, other ENEC-related assets and related financing costs. In January 2013, intervenors filed testimony that recommended securitization of approximately $370 million. The differences between APCo’s and WPCo’s request and the intervenors’ testimony represent previously approved ENEC-related deferred amounts being recovered in the ENEC over extended periods, various amounts deferred subsequent to the 2011 securitization period and related securitization financing costs. APCo and WPCo are currently in settlement discussions with intervenors.

WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting approval to merge WPCo into APCo. In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC. A hearing at the Virginia SCC is scheduled for April 2013.

Litigation and Environmental Issues

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

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 353 for additional discussion of relevant factors.

143

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

		Years Ended December 31,
		2012		2011		2010
		(in millions of KWhs)
Retail:
	Residential		11,395		12,011		13,127
	Commercial		6,794		6,915		7,208
	Industrial		10,778		10,811		10,774
	Miscellaneous		820		828		869
Total Retail			29,787		30,565		31,978

Wholesale			8,153		8,376		6,578

Total KWhs			37,940		38,941		38,556

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

Summary of Heating and Cooling Degree Days

		Years Ended December 31,
		2012		2011		2010
		(in degree days)
Actual - Heating (a)			1,783		1,996		2,636
Normal - Heating (b)			2,265		2,267		2,272

Actual - Cooling (c)			1,354		1,432		1,530
Normal - Cooling (b)			1,201		1,186		1,170

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

144

2012 Compared to 2011

Reconciliation of Year Ended December 31, 2011 to Year Ended December 31, 2012
Net Income
(in millions)

Year Ended December 31, 2011	$	163

Changes in Gross Margin:
Retail Margins		279
Off-system Sales		(9	)
Transmission Revenues		13
Other Revenues		(15	)
Total Change in Gross Margin		268

Changes in Expenses and Other:
Other Operation and Maintenance		(31	)
Depreciation and Amortization		(74	)
Taxes Other Than Income Taxes		5
Carrying Costs Income		11
Other Income		(11	)
Interest Expense		3
Total Change in Expenses and Other		(97	)

Income Tax Expense		(76	)

Year Ended December 31, 2012	$	258

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 $279 million primarily due to the following:
	·	A $130 million increase due to lower capacity settlement expenses under the Interconnection Agreement, net of recovery in West Virginia and environmental deferrals in Virginia. This increase was primarily as a result of a mild winter in 2012 and its impact on APCo’s winter peak, APCo’s completion of the Dresden Plant in January 2012 and the removal of Sporn Plant Unit 5 from the Interconnection Agreement in September 2011.
	·	An $87 million increase due to higher rates in Virginia and West Virginia. Of this increase, $59 million have corresponding increases in Depreciation and Amortization expenses below.
	·	A $24 million decrease in other variable electric generation expenses.
	·	A $24 million write-off in 2011 related to the disallowance of certain Virginia environmental costs incurred in 2009 and 2010 as a result of the November 2011 Virginia SCC order.
	·	A $9 million deferral of additional wind purchase costs as a result of the June 2012 Virginia SCC fuel factor order.
	·	A $9 million increase due to adjustments for previously disallowed environmental costs by the November 2011 Virginia SCC order subsequently determined in 2012 to be appropriate for recovery by the Supreme Court of Virginia.
	·	A $6 million decrease in PJM expenses.
	These increases were partially offset by:
	·	A $24 million decrease in weather-related usage primarily due to an 11% decrease in heating degree days.
	·	A $15 million decrease in residential margins primarily due to lower non-weather related usage.
·	Margins from Off-system Sales decreased $9 million primarily due to lower market prices, lower PJM capacity payments and reduced trading and marketing margins.
·	Transmission Revenues increased $13 million primarily due to increased Network Integration Transmission Service (NITS) revenue requirements beginning in July 2011. These NITS revenues are offset in Other Operation and Maintenance expenses below.
·	Other Revenues decreased $15 million primarily due to decreased gains on affiliated emission allowances.

145

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

·	Other Operation and Maintenance expenses increased $31 million primarily due to the following:
	·	A $32 million increase due to the 2011 deferral of 2009 storm costs and the 2010 cost reduction initiatives as allowed by the WVPSC.
	·	A $27 million increase due to the favorable 2011 asset retirement obligation adjustment related to the early closure and previous write-off of the Mountaineer Carbon Capture and Storage Product Validation Facility.
	·	A $16 million increase in transmission expenses due to higher NITS expenses. These expenses are offset in Transmission Revenues above.
	·	A $10 million increase in provisions for uncollectible accounts.
	·	An $8 million increase due to expenses related to the 2012 sustainable cost reductions.
	These increases were partially offset by:
	·	A $41 million decrease due to the 2011 write-off of a portion of the West Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC.
	·	A $13 million decrease due to the deferral of transmission costs for the Virginia Transmission Rate Adjustment Clause as allowed by the Virginia SCC recovered dollar-for-dollar within Gross Margin.
	·	A $10 million decrease in generation plant maintenance expenses in 2012.
·	Depreciation and Amortization expenses increased $74 million primarily due to:
	·	A $35 million increase as a result of increased depreciation rates in Virginia effective February 2012. The majority of this increase in depreciation is offset within Gross Margin.
	·	An $18 million increase in amortization primarily as a result of the Virginia Environmental Rate Adjustment Clause and the Virginia E&R surcharge, both effective February 2012. This increase in amortization is offset within Gross Margin.
	·	A $9 million increase in depreciation due to adjustments for disallowed environmental costs as approved in the November 2011 Virginia SCC order and 2012 adjustments for certain costs subsequently determined by the Supreme Court of Virginia to be appropriate for recovery.
	·	A $7 million increase in depreciation as a result of Dresden Plant being placed in service in January 2012.
·	Taxes Other Than Income Taxes expenses decreased $5 million primarily due to an $8 million decrease in the Virginia Minimum Tax, partially offset by a $3 million increase in real and personal property taxes.
·	Carrying Costs Income increased $11 million primarily due to adjustments for disallowed environmental costs as approved in the November 2011 Virginia SCC order and 2012 adjustments for certain costs subsequently determined by the Supreme Court of Virginia to be appropriate for recovery.
·	Other Income decreased $11 million primarily due to:
	·	An $8 million decrease in the equity component of AFUDC as a result of the completion of the Dresden Plant in January 2012.
	·	A $3 million decrease due to interest income recorded in 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
·	Interest Expense decreased $3 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·	Income Tax Expense increased $76 million primarily due to an increase in pretax book income and by the recording of state income tax adjustments.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 353 for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 353 for a discussion of accounting pronouncements.

146

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Appalachian Power Company:

We have audited the accompanying consolidated balance sheets of Appalachian Power Company and subsidiaries (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income (loss), changes in common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 Appalachian Power Company and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 26, 2013

147

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Appalachian Power Company and subsidiaries (APCo) 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. APCo’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 APCo’s internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, APCo’s internal control over financial reporting was effective as of December 31, 2012.

This annual report does not include an attestation report of APCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit APCo to provide only management’s report in this annual report.

148

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

	Years Ended December 31,
	2012			2011			2010
REVENUES
Electric Generation, Transmission and Distribution	$	2,948,762		$	2,835,481		$	2,950,183
Sales to AEP Affiliates		318,199			359,802			316,207
Other Revenues		9,970			9,942			8,713
TOTAL REVENUES		3,276,931			3,205,225			3,275,103

EXPENSES
Fuel and Other Consumables Used for Electric Generation		815,979			759,684			663,422
Purchased Electricity for Resale		211,133			305,647			257,349
Purchased Electricity from AEP Affiliates		661,238			819,182			917,616
Other Operation		332,936			316,995			429,107
Maintenance		211,702			197,002			211,486
Depreciation and Amortization		344,293			270,529			304,192
Taxes Other Than Income Taxes		102,190			106,606			110,908
TOTAL EXPENSES		2,679,471			2,775,645			2,894,080

OPERATING INCOME		597,460			429,580			381,023

Other Income (Expense):
Interest Income		1,358			5,016			1,477
Carrying Costs Income		24,602			13,433			33,080
Allowance for Equity Funds Used During Construction		1,684			9,212			2,967
Interest Expense		(202,074	)		(204,623	)		(207,649	)

INCOME BEFORE INCOME TAX EXPENSE		423,030			252,618			210,898

Income Tax Expense		165,527			89,860			74,230

NET INCOME		257,503			162,758			136,668

Preferred Stock Dividend Requirements Including Capital
Stock Expense		-			1,745			900

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	257,503		$	161,013		$	135,768

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

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

149

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

	Years Ended December 31,
	2012		2011			2010
Net Income	$	257,503	$	162,758		$	136,668

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $925, $123 and $3,843 in 2012, 2011 and 2010,
Respectively		1,718		(229	)		7,137
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,937, $1,674
and $2,247 in 2012, 2011 and 2010, Respectively		3,597		3,109			4,172
Pension and OPEB Funded Status, Net of Tax of $12,562, $7,215 and $4,888 in 2012,
2011 and 2010, Respectively		23,330		(13,400	)		(9,078	)

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		28,645		(10,520	)		2,231

TOTAL COMPREHENSIVE INCOME	$	286,148	$	152,238		$	138,899

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

150

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

									Accumulated
									Other
	Common		Paid-in			Retained			Comprehensive
	Stock		Capital			Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S EQUITY –
DECEMBER 31, 2009	$	260,458	$	1,475,393		$	1,085,980		$	(50,254	)	$	2,771,577

Common Stock Dividends							(88,000	)					(88,000	)
Preferred Stock Dividends							(799	)					(799	)
Capital Stock Expense				103			(101	)					2
Subtotal – Common Shareholder's Equity													2,682,780

Net Income							136,668						136,668
Other Comprehensive Income										2,231			2,231
TOTAL COMMON SHAREHOLDER'S EQUITY –
DECEMBER 31, 2010		260,458		1,475,496			1,133,748			(48,023	)		2,821,679

Capital Contribution from Parent				100,000									100,000
Common Stock Dividends							(135,000	)					(135,000	)
Preferred Stock Dividends							(732	)					(732	)
Loss on Reacquired Preferred Stock				(1,770	)								(1,770	)
Capital Stock Expense				26			(27	)					(1	)
Subtotal – Common Shareholder's Equity													2,784,176

Net Income							162,758						162,758
Other Comprehensive Loss										(10,520	)		(10,520	)
TOTAL COMMON SHAREHOLDER'S EQUITY –
DECEMBER 31, 2011		260,458		1,573,752			1,160,747			(58,543	)		2,936,414

Common Stock Dividends							(170,000	)					(170,000	)
Subtotal – Common Shareholder's Equity													2,766,414

Net Income							257,503						257,503
Other Comprehensive Income										28,645			28,645
TOTAL COMMON SHAREHOLDER'S EQUITY –
DECEMBER 31, 2012	$	260,458	$	1,573,752		$	1,248,250		$	(29,898	)	$	3,052,562

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

151

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2012 and 2011
(in thousands)

			December 31,
			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	3,576	$	2,317
Advances to Affiliates				23,024		22,008
Accounts Receivable:
	Customers			158,380		158,382
	Affiliated Companies			96,213		136,194
	Accrued Unbilled Revenues			70,825		68,427
	Miscellaneous			1,344		5,505
	Allowance for Uncollectible Accounts			(6,087)		(5,289)
		Total Accounts Receivable		320,675		363,219
Fuel				185,813		143,931
Materials and Supplies				105,208		101,724
Risk Management Assets				30,960		39,645
Accrued Tax Benefits				50,032		7,715
Regulatory Asset for Under-Recovered Fuel Costs				74,906		41,105
Prepayments and Other Current Assets				18,690		21,745
TOTAL CURRENT ASSETS				812,884		743,409

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			5,632,665		5,194,967
	Transmission			2,042,144		1,943,969
	Distribution			2,991,898		2,845,405
Other Property, Plant and Equipment				373,327		357,326
Construction Work in Progress				266,247		565,841
Total Property, Plant and Equipment				11,306,281		10,907,508
Accumulated Depreciation and Amortization				3,196,639		2,994,016
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				8,109,642		7,913,492

OTHER NONCURRENT ASSETS
Regulatory Assets				1,435,704		1,481,193
Long-term Risk Management Assets				34,360		39,226
Deferred Charges and Other Noncurrent Assets				115,078		122,187
TOTAL OTHER NONCURRENT ASSETS				1,585,142		1,642,606

TOTAL ASSETS			$	10,507,668	$	10,299,507

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

152

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
December 31, 2012 and 2011

		December 31,
		2012		2011
			(in thousands)
CURRENT LIABILITIES
Advances from Affiliates		$	173,965	$	198,248
Accounts Payable:
	General		195,203		186,612
	Affiliated Companies		137,088		137,376
Long-term Debt Due Within One Year – Nonaffiliated			574,679		594,525
Risk Management Liabilities			16,698		26,606
Customer Deposits			67,339		61,690
Deferred Income Taxes			11,715		14,255
Accrued Taxes			74,967		63,422
Accrued Interest			51,442		57,230
Other Current Liabilities			110,657		105,646
TOTAL CURRENT LIABILITIES			1,413,753		1,445,610

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			3,127,763		3,131,726
Long-term Risk Management Liabilities			18,476		12,923
Deferred Income Taxes			1,928,683		1,736,180
Regulatory Liabilities and Deferred Investment Tax Credits			607,680		576,792
Employee Benefits and Pension Obligations			204,207		302,182
Deferred Credits and Other Noncurrent Liabilities			154,544		157,680
TOTAL NONCURRENT LIABILITIES			6,041,353		5,917,483

TOTAL LIABILITIES			7,455,106		7,363,093

Rate Matters (Note 2)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
	Authorized – 30,000,000 Shares
	Outstanding – 13,499,500 Shares		260,458		260,458
Paid-in Capital			1,573,752		1,573,752
Retained Earnings			1,248,250		1,160,747
Accumulated Other Comprehensive Income (Loss)			(29,898)		(58,543)
TOTAL COMMON SHAREHOLDER’S EQUITY			3,052,562		2,936,414

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY		$	10,507,668	$	10,299,507

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

153

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

	Years Ended December 31,
	2012			2011			2010
OPERATING ACTIVITIES
Net Income	$	257,503		$	162,758		$	136,668
Adjustments to Reconcile Net Income to Net Cash Flows from
Operating Activities:
Depreciation and Amortization		344,293			270,529			304,192
Deferred Income Taxes		138,460			107,565			144,413
Carrying Costs Income		(24,602	)		(13,433	)		(33,080	)
Deferral of Storm Costs		(87,992	)		(16,324	)		(25,225	)
Allowance for Equity Funds Used During Construction		(1,684	)		(9,212	)		(2,967	)
Mark-to-Market of Risk Management Contracts		10,130			(26	)		29,182
Pension Contributions to Qualified Plan Trust		(25,199	)		(60,312	)		(36,784	)
Fuel Over/Under-Recovery, Net		96,774			(9,589	)		(13,356	)
Change in Regulatory Assets		(31,104	)		(3,031	)		63,700
Change in Other Noncurrent Assets		(21,724	)		(2,402	)		(15,668	)
Change in Other Noncurrent Liabilities		24,206			10,392			1,757
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		42,161			59,352			(63,426	)
Fuel, Materials and Supplies		(40,268	)		80,191			116,530
Accounts Payable		12,547			(60,843	)		(16,823	)
Accrued Taxes, Net		(14,396	)		71,610			76,881
Other Current Assets		3,706			15,570			1,287
Other Current Liabilities		7,234			3,933			(11,717	)
Net Cash Flows from Operating Activities		690,045			606,728			655,564

INVESTING ACTIVITIES
Construction Expenditures		(469,052	)		(463,077	)		(534,334	)
Change in Advances to Affiliates, Net		(1,016	)		(22,008	)		-
Acquisitions of Assets		(1,183	)		(302,512	)		(2,485	)
Other Investing Activities		8,392			15,096			12,871
Net Cash Flows Used for Investing Activities		(462,859	)		(772,501	)		(523,948	)

FINANCING ACTIVITIES
Capital Contribution from Parent		-			100,000			-
Issuance of Long-term Debt – Nonaffiliated		339,374			739,393			363,726
Change in Advances from Affiliates, Net		(24,283	)		69,917			(101,215	)
Retirement of Long-term Debt – Nonaffiliated		(364,875	)		(579,672	)		(200,019	)
Retirement of Long-term Debt – Affiliated		-			-			(100,000	)
Retirement of Cumulative Preferred Stock		-			(19,517	)		(4	)
Principal Payments for Capital Lease Obligations		(6,496	)		(7,447	)		(7,001	)
Dividends Paid on Common Stock		(170,000	)		(135,000	)		(88,000	)
Dividends Paid on Cumulative Preferred Stock		-			(732	)		(799	)
Other Financing Activities		353			197			641
Net Cash Flows from (Used for) Financing Activities		(225,927	)		167,139			(132,671	)

Net Increase (Decrease) in Cash and Cash Equivalents		1,259			1,366			(1,055	)
Cash and Cash Equivalents at Beginning of Period		2,317			951			2,006
Cash and Cash Equivalents at End of Period	$	3,576		$	2,317		$	951

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	200,383		$	198,465		$	202,884
Net Cash Paid (Received) for Income Taxes		31,418			(66,520	)		(153,205	)
Noncash Acquisitions Under Capital Leases		3,366			2,692			22,772
Government Grants Included in Accounts Receivable as of December 31,		-			1,048			1,049
Construction Expenditures Included in Current Liabilities as of December 31,		62,177			65,308			66,048

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

154

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to APCo’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to APCo. The footnotes begin on page 217.

	Footnote Reference

Organization and Summary of Significant Accounting Policies	Note 1
Rate Matters	Note 2
Effects of Regulation	Note 3
Commitments, Guarantees and Contingencies	Note 4
Acquisitions and Impairments	Note 5
Benefit Plans	Note 6
Business Segments	Note 7
Derivatives and Hedging	Note 8
Fair Value Measurements	Note 9
Income Taxes	Note 10
Leases	Note 11
Financing Activities	Note 12
Related Party Transactions	Note 13
Variable Interest Entities	Note 14
Property, Plant and Equipment	Note 15
Cost Reduction Programs	Note 16
Unaudited Quarterly Financial Information	Note 17

155

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

156

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

As a public utility, I&M engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 584,000 retail customers in its service territory in northern and eastern Indiana and a portion of southwestern Michigan. I&M consolidates Blackhawk Coal Company and Price River Coal Company, its wholly-owned subsidiaries. I&M also consolidates DCC Fuel. I&M sells power at wholesale to municipalities and electric cooperatives. I&M’s River Transportation Division provides barging services to affiliates and nonaffiliated companies. The revenues from barging represent the majority of other revenues.

The Interconnection Agreement permits the AEP East Companies to pool their generation assets on a cost basis. It establishes an allocation method for generating capacity among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. Members of the Interconnection Agreement are compensated for their costs of energy delivered and charged for energy received. The capacity reserve relationship of the Interconnection Agreement members changes as generating assets are added, retired or sold and relative peak demand changes. The Interconnection Agreement calculates each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the MLR, which determines each member’s percentage share of revenues and costs. The addition of APCo’s Dresden Plant in January 2012 and removal of OPCo’s Sporn Plant, Unit 5 in September 2011 changed the capacity reserve relationship of the members.

The AEP East Companies are parties to a Transmission Agreement defining how they share the revenues and costs associated with their relative ownership of transmission assets. This sharing was based upon each company’s MLR until the FERC approved a new Transmission Agreement effective November 2010. The new Transmission Agreement will be phased in for retail rates over periods of up to four years, added KGPCo and WPCo as parties to the agreement and changed the allocation method. I&M’s recovery mechanism for transmission costs is through its base rates. Changes in allocation under the new Transmission Agreement and state regulatory phase-in of the new agreement will limit I&M’s ability to fully recover its transmission costs.

Under a unit power agreement, I&M purchases AEGCo’s 50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities. AEGCo is an affiliate that is not a member of the Interconnection Agreement. Another unit power agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo’s Rockport Plant capacity to KPCo through 2022. Under these agreements, I&M purchases 910 MW of AEGCo’s 50% share of Rockport Plant capacity.

AEPSC conducts power, gas, coal and emission allowance risk management activities on I&M’s behalf. I&M shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the other AEP East Companies, PSO and SWEPCo. Power and gas risk management activities are allocated based on the Interconnection Agreement and the SIA. I&M shares in coal and emission allowance risk management activities based on its proportion of fossil fuels burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and, to a lesser extent, gas, coal and emission allowances. The electricity, gas, coal and emission allowance contracts include physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.

157

I&M is jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East Companies related to power purchase and sale activity pursuant to the SIA.

Regulatory Activity

Termination of Interconnection Agreement

Based upon the PUCO’s approval of OPCo’s corporate separation plan in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations and transfer at net book value certain plants to APCo and KPCo. Additionally, the AEP East Companies asked the FERC to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate their respective power supply resources. Under the PCA, APCo, I&M and KPCo would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. Intervenors have opposed several of these filings. The AEP East Companies have responded and continue to pursue approvals from the FERC. A decision from the FERC is expected in mid-2013.

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

Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on common equity of 11.15%. The $149 million net annual increase reflects an increase in base rates of $178 million offset by proposed corresponding reductions of $13 million to the off-system sales sharing rider, $9 million to the PJM cost rider and $7 million to the clean coal technology rider rates. The request included an increase in depreciation rates that would result in an increase of approximately $25 million in annual depreciation expense. Included in the depreciation rates increase was a decrease in the average remaining life of Tanners Creek Plant to account for the acceleration of the retirement date of Tanners Creek Plant, Units 1-3. I&M filed rebuttal testimony in May 2012 which supported an increase of $170 million in base rates, excluding reductions to certain riders.

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%, effective March 2013. The $85 million annual increase in base rates will be offset by corresponding reductions of $5 million to the off-system sales sharing rider, $11 million to the PJM cost rider and $7 million to the clean coal technology rider rates. The IURC granted the requested increase in depreciation rates, modified the shareholder’s portion of off-system sales margins to 50% below and above the $27 million imbedded in base rates, established a capacity tracker and established a major storm damage restoration reserve. See “2011 Indiana Base Rate Case” section of Note 2.

Michigan Capacity Rate

In April 2012, the FERC issued an order, effective October 2012, which sets I&M's capacity cost to be charged to alternative electric suppliers (AES) serving switching customers in I&M's Michigan service territory at $394/MW day unless a state compensation mechanism is approved by the MPSC. In May 2012, the MPSC issued an order to initiate a proceeding to establish a cost of service state compensation mechanism for the capacity rate to be charged to AES. In September 2012, the MPSC approved I&M’s filed cost of service proposal with a minor adjustment recommended by the MPSC staff. Under Michigan law, switching is limited to 10% of I&M's Michigan load, which was achieved in June 2012, the second month of customer switching.

158

Rockport Plant Environmental Controls

I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit one unit at its Rockport Plant with environmental controls estimated to cost $1.4 billion to comply with new requirements. AEGCo and I&M jointly own Unit 1 and jointly lease Unit 2 of the Rockport Plant. I&M is also evaluating options related to the maturity of the lease for Rockport Plant, Unit 2 in 2022 and continues to investigate alternative compliance technologies for these units as part of its overall compliance strategy. As of December 31, 2012, I&M has incurred $36 million related to these environmental controls, including AFUDC. If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows. In February 2013, I&M filed a motion with the IURC to dismiss its request for approval of a CPCN for environmental controls after modification to the NSR consent decree. See the “Modification of the NSR Litigation Consent Decree” section of the Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries and the “Rockport Plant Environmental Controls” section of Note 2.

Cook Plant

Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant, Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator. Repair of the property damage and replacement of the turbine rotors and other equipment cost approximately $400 million. In February 2013, management signed an agreement and received payment from NEIL, the insurer, to settle the remaining claims. The settlement did not have a material impact on net income, cash flows or financial condition. See “Cook Plant, Unit 1 Fire and Shutdown” section of Note 4.

Cook Plant Life Cycle Management Project

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life. The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. In Indiana, I&M requested recovery of certain project costs, including interest, through a new rider effective January 2013. In Michigan, I&M requested that the MPSC approve a Certificate of Need and authorize I&M to defer, on an interim basis, incremental depreciation and related property tax costs, including interest, along with study, analysis and development costs until the applicable LCM costs are included in I&M’s base rates. As of December 31, 2012, I&M has incurred $176 million related to the LCM Project, including AFUDC. Several intervenors filed testimony in Indiana with various recommendations including caps on expenditures. The IURC held a hearing in January 2013.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project with total costs of $851 million (Michigan jurisdictional share is approximately 15%) for the period 2013 through 2018. The order provided that depreciation, property taxes and a return using the overall rate of return approved in I&M’s last Michigan base rate case related to the 2013 through 2018 LCM Project costs can be deferred until these costs are included in rates. The order excluded from the CON $176 million of LCM costs spent prior to 2013 as $39 million was included in the determination of Michigan base rates, effective April 2012, and the remaining $137 million in CWIP will be requested in a future base rate case. The order also excluded $142 million of future LCM costs, which if incurred, will be requested in a future base rate case. Under Michigan law, the approved CON amount is eligible for a cost increase allowance of 10%, up to $85 million, of the approved project costs in the event project costs exceed the approved level of costs.

If I&M is not ultimately permitted to recover its LCM Project costs, it would reduce future net income and cash flows and impact financial condition. See “Cook Plant Life Cycle Management Project” section of Note 2.

159

Litigation and Environmental Issues

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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

		Years Ended December 31,
		2012		2011		2010
		(in millions of KWhs)
Retail:
	Residential		5,771		5,997		6,083
	Commercial		5,001		5,045		5,121
	Industrial		7,556		7,523		7,445
	Miscellaneous		75		73		72
Total Retail			18,403		18,638		18,721

Wholesale			9,782		9,249		7,839

Total KWhs			28,185		27,887		26,560

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

Summary of Heating and Cooling Degree Days

		Years Ended December 31,
		2012		2011		2010
		(in degree days)
Actual - Heating (a)			3,042		3,659		3,759
Normal - Heating (b)			3,772		3,766		3,774

Actual - Cooling (c)			1,098		1,075		1,165
Normal - Cooling (b)			861		848		832

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

160

2012 Compared to 2011

Reconciliation of Year Ended December 31, 2011 to Year Ended December 31, 2012
Net Income
(in millions)

Year Ended December 31, 2011	$	150

Changes in Gross Margin:
Retail Margins		(23)
FERC Municipals and Cooperatives		(8)
Off-system Sales		(12)
Transmission Revenues		1
Other Revenues		6
Total Change in Gross Margin		(36)

Changes in Expenses and Other:
Other Operation and Maintenance		14
Depreciation and Amortization		(13)
Taxes Other Than Income Taxes		1
Other Income		(5)
Interest Expense		(5)
Total Change in Expenses and Other		(8)

Income Tax Expense		12

Year Ended December 31, 2012	$	118

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

·	Retail Margins decreased $23 million primarily due to the following:
	·	A $54 million decrease in capacity settlements under the Interconnection Agreement, net of sharing with customers in Michigan. The decrease was primarily a result of a mild winter in 2012 and its impact on APCo’s winter peak.
	·	An $8 million decrease in weather-related usage primarily due to a 17% decrease in heating degree days.
	These decreases were partially offset by:
	·	A $24 million increase in rate relief primarily due to higher PJM revenue, Michigan base rate increases and higher Indiana demand side management revenue.
	·	A $14 million increase due to customer credits issued in 2011 for a settlement relating to the Cook Plant Unit 1 fire outage. This increase was offset by an increase in Other Operation and Maintenance expenses as discussed below.
·	Margins from FERC Municipals and Cooperatives decreased $8 million primarily due to the following:
	·	A $14 million decrease due to an annual rate adjustment to actual costs.
	This decrease was offset by:
	·	A $6 million increase due to favorable fuel adjustments.
·	Margins from Off-system Sales decreased $12 million primarily due to lower market prices, lower PJM capacity payments and reduced trading and marketing margins.
·	Other Revenues increased $6 million primarily due to an unfavorable 2011 provision for refund of outage insurance proceeds.

161

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

·	Other Operation and Maintenance expenses decreased $14 million primarily due to the following:
	·	A $19 million decrease in nuclear generation maintenance expenses performed during the 2011 refueling outage.
	·	A $17 million decrease due to an agreement reached to settle an insurance claim.
	·	An $11 million decrease primarily due to maintenance outages at the Tanners Creek and Rockport plants during 2011.
	·	A $7 million decrease in overhead line expenses.
	These decreases were partially offset by:
	·	A $14 million increase in steam power expenses related to credits issued in 2011 associated with the Cook Plant Unit 1 fire outage. This increase was offset by a corresponding increase in Retail Margins as discussed above.
	·	A $9 million increase due to an agreement to modify the NSR consent decree.
	·	An $8 million increase associated with the favorable resolution of a contingency in 2011.
	·	A $6 million increase due to expenses related to the 2012 sustainable cost reductions.
	·	A $6 million increase due to the write off of an investment for possible storage of SNF.
·	Depreciation and Amortization increased $13 million primarily due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant’s estimated life as approved in the Michigan base case settlement effective April 2012. The majority of the increase in depreciation for Tanners Creek Plant’s life is offset within Gross Margin.
·	Other Income decreased $5 million primarily due to lower equity AFUDC related to nuclear fuel preparation for usage.
·	Interest Expense increased $5 million primarily due to lower credits for AFUDC on borrowed funds related to nuclear fuel and higher tax-related interest.
·	Income Tax Expense decreased $12 million primarily due to a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

162

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Indiana Michigan Power Company:

We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company and subsidiaries (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income (loss), changes in common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012. 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.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 26, 2013

163

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Indiana Michigan Power Company and subsidiaries (I&M) 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. I&M’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.

Management assessed the effectiveness of I&M’s internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, I&M’s internal control over financial reporting was effective as of December 31, 2012.

This annual report does not include an attestation report of I&M’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit I&M to provide only management’s report in this annual report.

164

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

	Years Ended December 31,
	2012			2011			2010
REVENUES
Electric Generation, Transmission and Distribution	$	1,810,069		$	1,770,447		$	1,735,338
Sales to AEP Affiliates		268,408			320,184			330,951
Other Revenues - Affiliated		117,052			109,053			114,070
Other Revenues - Nonaffiliated		4,582			15,086			15,368
TOTAL REVENUES		2,200,111			2,214,770			2,195,727

EXPENSES
Fuel and Other Consumables Used for Electric Generation		464,420			472,080			465,482
Purchased Electricity for Resale		117,860			121,375			128,369
Purchased Electricity from AEP Affiliates		386,404			353,484			327,335
Other Operation		583,865			540,595			560,346
Maintenance		172,562			229,883			222,406
Depreciation and Amortization		146,619			133,394			136,443
Taxes Other Than Income Taxes		80,687			82,303			80,431
TOTAL EXPENSES		1,952,417			1,933,114			1,920,812

OPERATING INCOME		247,694			281,656			274,915

Other Income (Expense):
Interest Income		3,122			2,048			3,389
Allowance for Equity Funds Used During Construction		9,724			15,395			15,678
Interest Expense		(102,739	)		(97,665	)		(104,465	)

INCOME BEFORE INCOME TAX EXPENSE		157,801			201,434			189,517

Income Tax Expense		39,344			51,760			63,426

NET INCOME		118,457			149,674			126,091

Preferred Stock Dividend Requirements Including Capital Stock Expense		-			626			339

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	118,457		$	149,048		$	125,752

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

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

165

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

	Years Ended December 31,
		2012			2011			2010
Net Income		$	118,457		$	149,674		$	126,091

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $2,590, $3,553 and $652 in 2012, 2011 and
2010, Respectively			(4,809	)		(6,599	)		1,211
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $598, $510 and
$470 in 2012, 2011 and 2010, Respectively			1,113			948			873
Pension and OPEB Funded Status, Net of Tax of $1,634, $906 and $685 in 2012,
2011 and 2010, Respectively			3,034			(1,681	)		(1,272	)

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			(662	)		(7,332	)		812

TOTAL COMPREHENSIVE INCOME		$	117,795		$	142,342		$	126,903

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

166

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

									Accumulated
									Other
	Common		Paid-in			Retained			Comprehensive
	Stock		Capital			Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S EQUITY –
DECEMBER 31, 2009	$	56,584	$	981,292		$	656,608		$	(21,701	)	$	1,672,783

Common Stock Dividends							(105,000	)					(105,000	)
Preferred Stock Dividends							(339	)					(339	)
Gain on Reacquired Preferred Stock				2									2
Subtotal – Common Shareholder's Equity													1,567,446

Net Income							126,091						126,091
Other Comprehensive Income										812			812
TOTAL COMMON SHAREHOLDER'S EQUITY –
DECEMBER 31, 2010		56,584		981,294			677,360			(20,889	)		1,694,349

Common Stock Dividends							(75,000	)					(75,000	)
Preferred Stock Dividends							(313	)					(313	)
Loss on Reacquired Preferred Stock				(398	)								(398	)
Subtotal – Common Shareholder's Equity													1,618,638

Net Income							149,674						149,674
Other Comprehensive Loss										(7,332	)		(7,332	)
TOTAL COMMON SHAREHOLDER'S EQUITY –
DECEMBER 31, 2011		56,584		980,896			751,721			(28,221	)		1,760,980

Common Stock Dividends							(75,000	)					(75,000	)
Subtotal – Common Shareholder's Equity													1,685,980

Net Income							118,457						118,457
Other Comprehensive Loss										(662	)		(662	)
TOTAL COMMON SHAREHOLDER'S EQUITY –
DECEMBER 31, 2012	$	56,584	$	980,896		$	795,178		$	(28,883	)	$	1,803,775

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

167

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2012 and 2011
(in thousands)

			December 31,
			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	1,562	$	1,020
Advances to Affiliates				116,977		95,714
Accounts Receivable:
	Customers			61,776		72,461
	Affiliated Companies			79,886		90,980
	Accrued Unbilled Revenues			11,218		14,780
	Miscellaneous			12,260		22,685
	Allowance for Uncollectible Accounts			(229)		(1,750)
		Total Accounts Receivable		164,911		199,156
Fuel				53,406		52,979
Materials and Supplies				195,147		175,924
Risk Management Assets				26,974		32,152
Accrued Tax Benefits				20,547		38,425
Deferred Cook Plant Fire Costs				80,000		63,809
Prepayments and Other Current Assets				62,723		35,395
TOTAL CURRENT ASSETS				722,247		694,574

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			4,062,733		3,932,472
	Transmission			1,278,236		1,224,786
	Distribution			1,553,358		1,481,608
Other Property, Plant and Equipment (Including Nuclear Fuel and Coal Mining)				725,313		709,558
Construction Work in Progress				341,063		236,096
Total Property, Plant and Equipment				7,960,703		7,584,520
Accumulated Depreciation, Depletion and Amortization				3,232,135		3,179,920
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				4,728,568		4,404,600

OTHER NONCURRENT ASSETS
Regulatory Assets				540,019		602,979
Spent Nuclear Fuel and Decommissioning Trusts				1,705,772		1,591,732
Long-term Risk Management Assets				23,569		29,362
Deferred Charges and Other Noncurrent Assets				111,364		69,309
TOTAL OTHER NONCURRENT ASSETS				2,380,724		2,293,382

TOTAL ASSETS			$	7,831,539	$	7,392,556

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

168

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
December 31, 2012 and 2011
(dollars in thousands)

		December 31,
		2012		2011
CURRENT LIABILITIES
Accounts Payable:
	General	$	208,701	$	113,063
	Affiliated Companies		104,631		81,102
Long-term Debt Due Within One Year – Nonaffiliated
	(December 31, 2012 and 2011 Amounts Include $119,890 and $101,620,
	Respectively, Related to DCC Fuel)		203,953		279,075
Risk Management Liabilities			31,517		16,980
Customer Deposits			31,142		30,696
Accrued Taxes			67,675		65,233
Accrued Interest			26,859		27,798
Other Current Liabilities			122,053		117,879
TOTAL CURRENT LIABILITIES			796,531		731,826

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			1,853,713		1,778,600
Long-term Risk Management Liabilities			13,898		18,871
Deferred Income Taxes			1,019,160		925,712
Regulatory Liabilities and Deferred Investment Tax Credits			948,292		875,202
Asset Retirement Obligations			1,192,313		1,013,122
Deferred Credits and Other Noncurrent Liabilities			203,857		288,243
TOTAL NONCURRENT LIABILITIES			5,231,233		4,899,750

TOTAL LIABILITIES			6,027,764		5,631,576

Rate Matters (Note 2)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
	Authorized – 2,500,000 Shares
	Outstanding – 1,400,000 Shares		56,584		56,584
Paid-in Capital			980,896		980,896
Retained Earnings			795,178		751,721
Accumulated Other Comprehensive Income (Loss)			(28,883)		(28,221)
TOTAL COMMON SHAREHOLDER’S EQUITY			1,803,775		1,760,980

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	7,831,539	$	7,392,556

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

169

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

				Years Ended December 31,
				2012		2011		2010
OPERATING ACTIVITIES
Net Income				$	118,457	$	149,674	$	126,091
Adjustments to Reconcile Net Income to Net Cash Flows from
	Operating Activities:
		Depreciation and Amortization			146,619		133,394		136,443
		Accretion of Asset Retirement Obligations			11,712		11,668		11,905
		Deferred Income Taxes			53,067		141,015		63,947
		Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net			13,899		13,244		(31,939)
		Allowance for Equity Funds Used During Construction			(9,724)		(15,395)		(15,678)
		Mark-to-Market of Risk Management Contracts			12,164		(1,590)		4,592
		Amortization of Nuclear Fuel			135,905		136,707		139,438
		Pension Contributions to Qualified Plan Trust			(22,285)		(52,588)		(71,681)
		Fuel Over/Under-Recovery, Net			4,175		(13,885)		(12,589)
		Change in Other Noncurrent Assets			(2,347)		(22,977)		(12,597)
		Change in Other Noncurrent Liabilities			47,097		50,371		56,592
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		34,431		57,661		(85,072)
			Fuel, Materials and Supplies		(19,321)		40,239		(16,564)
			Accounts Payable		15,959		(52,175)		46,579
			Accrued Taxes, Net		16,897		15,508		77,075
			Cook Plant Fire Costs, Net		(8,465)		18,282		87,347
			Other Current Assets		(2,039)		6,409		5,056
			Other Current Liabilities		11,717		6,167		4,149
Net Cash Flows from Operating Activities					557,918		621,729		513,094

INVESTING ACTIVITIES
Construction Expenditures					(317,284)		(301,242)		(333,238)
Change in Advances to Affiliates, Net					(21,263)		(95,714)		114,012
Purchases of Investment Securities					(1,045,422)		(1,166,690)		(1,414,473)
Sales of Investment Securities					987,550		1,110,909		1,361,813
Acquisitions of Nuclear Fuel					(106,714)		(105,703)		(90,903)
Other Investing Activities					29,324		47,169		17,105
Net Cash Flows Used for Investing Activities					(473,809)		(511,271)		(345,684)

FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated					217,900		185,972		152,464
Change in Advances from Affiliates, Net					-		(42,769)		42,769
Retirement of Long-term Debt - Nonaffiliated					(220,212)		(160,645)		(202,011)
Retirement of Long-term Debt - Affiliated					-		-		(25,000)
Retirement of Cumulative Preferred Stock					-		(8,470)		(3)
Principal Payments for Capital Lease Obligations					(6,536)		(8,652)		(31,180)
Dividends Paid on Common Stock					(75,000)		(75,000)		(105,000)
Dividends Paid on Cumulative Preferred Stock					-		(313)		(339)
Other Financing Activities					281		78		472
Net Cash Flows Used for Financing Activities					(83,567)		(109,799)		(167,828)

Net Increase (Decrease) in Cash and Cash Equivalents					542		659		(418)
Cash and Cash Equivalents at Beginning of Period					1,020		361		779
Cash and Cash Equivalents at End of Period				$	1,562	$	1,020	$	361

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	98,130	$	95,124	$	100,617
Net Cash Paid (Received) for Income Taxes					(21,196)		(96,452)		(71,268)
Noncash Acquisitions Under Capital Leases					6,243		3,454		10,000
Construction Expenditures Included in Current Liabilities as of December 31,					112,622		42,992		21,757
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,					35,493		715		308
Noncash Increase in Long-term Debt Through the Fort Wayne Lease Settlement					-		26,802		-
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage					30,332		-		-

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

170

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to I&M’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to I&M. The footnotes begin on page 217.

	Footnote Reference

Organization and Summary of Significant Accounting Policies	Note 1
Rate Matters	Note 2
Effects of Regulation	Note 3
Commitments, Guarantees and Contingencies	Note 4
Benefit Plans	Note 6
Business Segments	Note 7
Derivatives and Hedging	Note 8
Fair Value Measurements	Note 9
Income Taxes	Note 10
Leases	Note 11
Financing Activities	Note 12
Related Party Transactions	Note 13
Variable Interest Entities	Note 14
Property, Plant and Equipment	Note 15
Cost Reduction Programs	Note 16
Unaudited Quarterly Financial Information	Note 17

171

OHIO POWER COMPANY AND SUBSIDIARY

172

OHIO POWER COMPANY AND SUBSIDIARY

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

As a public utility, OPCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 1,459,000 retail customers in the northwestern, central, eastern and southern sections of Ohio. OPCo consolidates Conesville Coal Preparation Company, its wholly-owned subsidiary.

The Interconnection Agreement permits the AEP East Companies to pool their generation assets on a cost basis. It establishes an allocation method for generating capacity among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. Members of the Interconnection Agreement are compensated for their costs of energy delivered and charged for energy received. The capacity reserve relationship of the Interconnection Agreement members changes as generating assets are added, retired or sold and relative peak demand changes. The Interconnection Agreement calculates each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the MLR, which determines each member’s percentage share of revenues and costs. The addition of APCo’s Dresden Plant in January 2012 and removal of OPCo’s Sporn Plant, Unit 5 in September 2011 changed the capacity reserve relationship of the members.

In 2007, OPCo and AEGCo entered into a 10-year unit power agreement for the entire output from the Lawrenceburg Plant with an option for an additional 2-year period. OPCo pays AEGCo for the capacity, depreciation, fuel, operation, maintenance and tax expenses. These payments are due regardless of whether the plant operates.

AEPSC conducts power, gas, coal and emission allowance risk management activities on OPCo’s behalf. OPCo shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the other AEP East Companies, PSO and SWEPCo. Power and gas risk management activities are allocated based on the Interconnection Agreement and the SIA. OPCo shares in coal and emission allowance risk management activities based on its proportion of fossil fuels burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and, to a lesser extent, gas, coal and emission allowances. The electricity, gas, coal and emission allowance contracts include physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.

To minimize the credit requirements and operating constraints of operating within PJM, the AEP East Companies, as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East Companies against all balances due to the AEP East Companies and to hold PJM harmless from actions that any one or more AEP East Companies may take with respect to PJM.

173

OPCo is jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East Companies related to power purchase and sale activity pursuant to the SIA.

Ohio Plant Impairments

In October 2012, management filed applications with the FERC proposing to terminate the Interconnection Agreement and complete the corporate separation of OPCo's generation assets. Based on the intention to terminate the Interconnection Agreement, management performed an evaluation of the recoverability of generation assets using generating unit specific estimated future cash flows and concluded that OPCo had a material impairment of certain generation assets. In the fourth quarter of 2012, OPCo recorded a pretax impairment of $287 million ($185 million, net of tax) in Asset Impairments and Other Related Charges on the statement of income related to Beckjord Plant Unit 6, Conesville Plant Unit 3, Kammer Plant Units 1-3, Muskingum River Plant Units 1-4, Sporn Plant Units 2 and 4 and Picway Plant Unit 5 generating units and related material and supplies inventory.

Ohio Customer Choice

In OPCo’s service territory, various CRES providers are targeting retail customers by offering alternative generation service. As a result, OPCo lost approximately $235 million of gross margin in 2012 as compared to 2011. This reduction in gross margin is partially offset by (a) collection of capacity revenues from CRES providers, (b) off-system sales, (c) deferral of unrecovered capacity costs and (d) Retail Stability Rider collections. As of December 31, 2012, based upon an average annual load, approximately 51% of OPCo’s load had switched to CRES providers.

Regulatory Activity

June 2012 – May 2015 Ohio ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP through May 2015. The ESP allowed the continuation of the fuel adjustment clause, adopted a 12% earnings threshold for the SEET and established a non-bypassable Distribution Investment Rider (DIR) effective September 2012 through May 2015 to recover, with certain caps, post-August 2010 distribution investment. The DIR is capped at $86 million in 2012, $104 million in 2013, $124 million in 2014 and $52 million for the period January through May 2015, for a total of $366 million. The ESP also maintained recovery of several previous ESP riders and required OPCo to contribute $2 million per year during the ESP to the Ohio Growth Fund. In addition, the PUCO approved a storm damage recovery mechanism.

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

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The RPM price is approximately $20/MW day through May 2013. As part of the August 2012 PUCO ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012. The RSR is intended to provide approximately $500 million over the ESP period and will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the deferred capacity costs. As of December 31, 2012, OPCo recorded $66 million of incurred deferred capacity costs, including debt carrying costs, in Regulatory Assets on the balance sheet. The capacity order, including collection of capacity costs, has been appealed to the Supreme Court of Ohio.

174

deferred to a separate docket. If OPCo is ultimately not permitted to fully collect its deferred capacity costs and ESP rates, including the RSR, it would reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filing” section of Note 2.

Corporate Separation, Plant Transfers and Termination of Interconnection Agreement

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets at net book value to AEPGenCo. AEPGenCo will also assume the associated generation liabilities. In December 2012, the PUCO granted the IEU and the Ohio Consumers’ Counsel requests for rehearing for the purpose of further consideration and those requests remain pending.

Also in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations. The filings requested approval to transfer at net book value approximately 9,200 MW of OPCo-owned generation assets to AEPGenCo. The AEP East Companies also requested FERC approval to transfer at net book value OPCo’s current two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer at net book value OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests (780 MW each). Additionally, the AEP East Companies asked the FERC to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate their respective power supply resources. Under the PCA, APCo, I&M and KPCo would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. Intervenors have opposed several of these filings. The AEP East Companies have responded and continue to pursue approvals from the FERC. A decision from the FERC is expected in mid-2013.

Significantly Excessive Earnings Test

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order. In the fourth quarter of 2012, the Supreme Court of Ohio upheld the PUCO decision on the 2009 SEET filing. Subsequent testimony and legal briefs from intervenors recommended refunds of a portion of 2010 earnings. OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO ordered SEET refund. OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo and in 2012 for OPCo. See “Ohio Electric Security Plan Filing” section of Note 2.

Securitization of Regulatory Asset

In August 2012, OPCo filed an application with the PUCO requesting securitization of the Deferred Asset Recovery Rider (DARR) balance. As of December 31, 2012, OPCo’s DARR balance was $287 million, including $135 million of unrecognized equity carrying costs. Currently, the DARR is being recovered through 2018 by a non-bypassable rider. If the application is approved and the securitization bonds are issued, the DARR will cease and will be replaced by the Deferred Asset Phase-in Rider, which will recover the securitized asset over seven years.

Litigation and Environmental Issues

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

175

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

	Years Ended December 31,
	2012	2011		2010
	(in millions of KWhs)
Retail:
Residential	14,485		15,082	15,386
Commercial	14,176		14,269	14,454
Industrial	18,122		18,946	17,455
Miscellaneous	120		123	129
Total Retail	46,903		48,420	47,424

Wholesale	13,221		12,229	8,466

Total KWhs	60,124		60,649	55,890

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

Summary of Heating and Cooling Degree Days

		Years Ended December 31,
		2012		2011		2010
		(in degree days)
Actual - Heating (a)			2,610		3,107		3,488
Normal - Heating (b)			3,276		3,266		3,267

Actual - Cooling (c)			1,248		1,112		1,189
Normal - Cooling (b)			948		936		921

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

176

2012 Compared to 2011

Reconciliation of Year Ended December 31, 2011 to Year Ended December 31, 2012
Net Income
(in millions)

Year Ended December 31, 2011	$	465

Changes in Gross Margin:
Retail Margins		(201	)
Off-system Sales		5
Transmission Revenues		43
Other Revenues		6
Total Change in Gross Margin		(147	)

Changes in Expenses and Other:
Other Operation and Maintenance		159
Asset Impairments and Other Related Charges		(197	)
Depreciation and Amortization		34
Taxes Other Than Income Taxes		(6	)
Carrying Costs Income		(36	)
Other Income		(6	)
Interest Expense		9
Total Change in Expenses and Other		(43	)

Income Tax Expense		69

Year Ended December 31, 2012	$	344

·	Retail Margins decreased $201 million primarily due to the following:
	·	A $289 million decrease attributable to customers switching to alternative CRES providers. This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
	·	A $165 million decrease in capacity settlement revenues under the Interconnection Agreement. This decrease was primarily as a result of a mild winter in 2012 and its impact on APCo’s winter peak, APCo’s completion of the Dresden Plant in January 2012 and the removal of Sporn Plant Unit 5 from the Interconnection Agreement in September 2011.
	·	An $85 million net decrease in regulated revenue due to the elimination of POLR charges, effective June 2011, partially offset by the 2011 provision for refund of POLR charges. The refund provision was recorded as a result of the October 2011 PUCO remand order.
	These decreases were partially offset by:
	·	A $177 million increase in revenues associated with the Retail Stability Rider, Deferred Asset Recovery Rider and Distribution Investment Recovery Rider. A portion of these increases have corresponding increases in other expense items below.
	·	A $35 million increase due to a decrease in consumable and allowance expenses not recovered in the FAC.
	·	A $35 million increase due to the 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
	·	A $33 million decrease in recoverable PJM expenses.
·	Margins from Off-system Sales increased $5 million primarily due to higher CRES capacity revenues, partially offset by lower market prices, lower PJM capacity payments and reduced trading and marketing margins.
·	Transmission Revenues increased $43 million primarily due to increased transmission revenues related to customers who have switched to alternative CRES providers. The increase in transmission revenues related to CRES providers offsets the lost transmission revenues included in Retail Margins above.

177

Other Revenues increased $6 million primarily due to increased revenues for coal transit from OPCo’s Cook Coal Terminal. This increase in revenues was offset by a corresponding increase in Other Operation and Maintenance as discussed below.

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

·	Other Operation and Maintenance expenses decreased $159 million primarily due to:
	·	An $88 million decrease in plant maintenance expenses at various plants.
	·	A $70 million decrease related to the 2011 recording and subsequent 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of the Ohio modified stipulation.
	·	An $11 million decrease in transmission expenses related to the Transmission Agreement as a result of decreased load and customer switching.
	·	A $10 million decrease due to the deferral of capacity-related costs as a result of the PUCO's July 2012 approval of the capacity deferral mechanism.
	·	A $9 million decrease due to the 2011 asset retirement obligation write-offs for fully depreciated units at the Sporn, Conesville and Tidd plants.
	·	A $6 million decrease due to the 2011 write-off of allocated Front-End Engineering and Design study costs related to the Mountaineer Carbon Capture Project.
	·	A $3 million decrease as a result of a legal proceeding in 2011.
	These decreases were partially offset by:
	·	A $13 million increase due to expenses related to the 2012 sustainable cost reductions.
	·	An $11 million gain from the sale of land in January 2011.
	·	An $8 million increase in advertising expenses.
	·	An $8 million increase in expenses related to Cook Coal Terminal. This increase in expenses was offset by a corresponding increase in Other Revenues as discussed above.
·	Asset Impairments and Other Related Charges increased $197 million due to the following:
	·	A 2012 impairment of $287 million for certain Ohio generation plants which includes $13 million of related materials and supplies inventory.
	This increase was offset by:
	·	A 2011 plant impairment of $48 million for Sporn Plant Unit 5.
	·	A 2011 plant impairment of $42 million for the FGD project at Muskingum River Plant Unit 5.
·	Depreciation and Amortization decreased $34 million primarily due to:
	·	A $39 million decrease due to an amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
	·	A $28 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of the capacity rate.
	·	A $23 million decrease due to the amortization of carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances. The equity amortization was offset by amounts recognized in Carrying Costs Income as discussed below.
	·	A $13 million decrease in depreciation due to the 2011 plant impairment of Sporn Plant Unit 5.
	These decreases were partially offset by:
	·	A $58 million increase due to shortened depreciable lives for certain generating plants effective December 2011. The book value of these plants was fully impaired in November 2012.
	·	An $11 million increase in amortization of the Deferred Asset Recovery Rider assets as approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012. This increase in amortization is offset within Gross Margin.
·	Taxes Other Than Income Taxes increased $6 million primarily due to increased property taxes as a result of increased capital investments and increased tax rates.
·	Carrying Costs Income decreased $36 million primarily due to the following:
	·	A $12 million decrease due to the recognition of carrying costs income on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances. The carrying costs income was offset by amounts in Depreciation and Amortization discussed above.

178

	·	An $11 million decrease in FAC deferrals due to the implementation of the Phase-In Recovery Rider in 2012. A portion of the deferred charges are recorded in Retail Margins above.
	·	A $6 million decrease due to line extension carrying charges recorded in 2011.
	·	A $5 million reduction in debt carrying charges associated with the 2008 coal contract settlement for the period January 2009 through March 2012 as ordered by the PUCO in April 2012 related to the 2009 FAC audit.
·	Interest Expense decreased $9 million primarily as a result of a net increase in capitalized interest.
·	Income Tax Expense decreased $69 million primarily due to a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

179

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Ohio Power Company:

We have audited the accompanying consolidated balance sheets of Ohio Power Company and subsidiary (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income (loss), changes in common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012. 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.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Ohio Power Company and subsidiary as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 26, 2013

180

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Ohio Power Company and Subsidiary (OPCo) 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. OPCo’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.

Management assessed the effectiveness of OPCo’s internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, OPCo’s internal control over financial reporting was effective as of December 31, 2012.

This annual report does not include an attestation report of OPCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit OPCo to provide only management’s report in this annual report.

181

OHIO POWER COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

	Years Ended December 31,
	2012			2011			2010
REVENUES
Electric Generation, Transmission and Distribution	$	4,022,116		$	4,406,814		$	4,222,461
Sales to AEP Affiliates		847,294			977,999			991,285
Other Revenues - Affiliated		39,401			27,903			21,069
Other Revenues - Nonaffiliated		19,385			18,395			20,301
TOTAL REVENUES		4,928,196			5,431,111			5,255,116

EXPENSES
Fuel and Other Consumables Used for Electric Generation		1,471,316			1,597,410			1,488,474
Purchased Electricity for Resale		205,845			300,653			286,835
Purchased Electricity from AEP Affiliates		380,706			515,613			386,618
Other Operation		669,981			754,109			795,129
Maintenance		319,324			393,943			346,745
Asset Impairments and Other Related Charges		287,031			89,824			-
Depreciation and Amortization		511,070			545,376			513,168
Taxes Other Than Income Taxes		405,976			399,479			393,537
TOTAL EXPENSES		4,251,249			4,596,407			4,210,506

OPERATING INCOME		676,947			834,704			1,044,610

Other Income (Expense):
Interest Income		3,536			7,069			2,567
Carrying Costs Income		16,942			53,345			31,796
Allowance for Equity Funds Used During Construction		3,492			5,549			5,949
Interest Expense		(213,100	)		(221,977	)		(242,000	)

INCOME BEFORE INCOME TAX EXPENSE		487,817			678,690			842,922

Income Tax Expense		144,283			213,697			301,306

NET INCOME		343,534			464,993			541,616

Preferred Stock Dividend Requirements Including
Capital Stock Expense		-			1,259			881

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	343,534		$	463,734		$	540,735

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

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

182

OHIO POWER COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

		Years Ended December 31,
		2012		2011		2010
Net Income		$	343,534	$	464,993	$	541,616

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $282, $1,477 and $529 in 2012, 2011
	and 2010, Respectively		(523)		(2,743)		(981)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $6,979, $5,894 and
	$5,128 in 2012, 2011 and 2010, Respectively		12,961		10,946		9,522
Pension and OPEB Funded Status, Net of Tax of $10,533, $13,876 and
	$10,901 in 2012, 2011 and 2010, Respectively		19,559		(25,770)		(20,245)

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			31,997		(17,567)		(11,704)

TOTAL COMPREHENSIVE INCOME		$	375,531	$	447,426	$	529,912

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

183

OHIO POWER COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

									Accumulated
									Other
	Common		Paid-in			Retained			Comprehensive
	Stock		Capital			Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	321,201	$	1,744,838		$	2,696,942		$	(168,451	)	$	4,594,530

Common Stock Dividends							(469,075	)					(469,075	)
Preferred Stock Dividends							(732	)					(732	)
Gain on Reacquired Preferred Stock				4									4
Capital Stock Expense				149			(149	)					-
Subtotal – Common Shareholder's Equity													4,124,727

Net Income							541,616						541,616
Other Comprehensive Loss										(11,704	)		(11,704	)
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2010		321,201		1,744,991			2,768,602			(180,155	)		4,654,639

Common Stock Dividends							(650,000	)					(650,000	)
Preferred Stock Dividends							(671	)					(671	)
Loss on Reacquired Preferred Stock				(1,216	)								(1,216	)
Capital Stock Expense				324			(324	)					-
Subtotal – Common Shareholder's Equity													4,002,752

Net Income							464,993						464,993
Other Comprehensive Loss										(17,567	)		(17,567	)
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2011		321,201		1,744,099			2,582,600			(197,722	)		4,450,178

Common Stock Dividends							(300,000	)					(300,000	)
Subtotal – Common Shareholder's Equity													4,150,178

Net Income							343,534						343,534
Other Comprehensive Income										31,997			31,997
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2012	$	321,201	$	1,744,099		$	2,626,134		$	(165,725	)	$	4,525,709

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

184

OHIO POWER COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2012 and 2011
(in thousands)

			December 31,
			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	3,640	$	2,095
Advances to Affiliates				116,422		219,458
Accounts Receivable:
	Customers			135,954		146,432
	Affiliated Companies			176,590		162,830
	Accrued Unbilled Revenues			57,887		19,012
	Miscellaneous			9,327		16,994
	Allowance for Uncollectible Accounts			(129)		(3,563)
		Total Accounts Receivable		379,629		341,705
Fuel				328,840		262,886
Materials and Supplies				186,269		201,325
Risk Management Assets				44,313		54,293
Accrued Tax Benefits				17,785		11,975
Prepayments and Other Current Assets				26,807		41,560
TOTAL CURRENT ASSETS				1,103,705		1,135,297

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			8,673,296		9,502,614
	Transmission			2,013,737		1,948,329
	Distribution			3,722,745		3,545,574
Other Property, Plant and Equipment				571,154		546,642
Construction Work in Progress				354,497		354,465
Total Property, Plant and Equipment				15,335,429		15,897,624
Accumulated Depreciation and Amortization				5,242,805		5,742,561
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				10,092,624		10,155,063

OTHER NONCURRENT ASSETS
Regulatory Assets				1,420,966		1,370,504
Long-term Risk Management Assets				48,288		53,614
Deferred Charges and Other Noncurrent Assets				320,026		309,775
TOTAL OTHER NONCURRENT ASSETS				1,789,280		1,733,893

TOTAL ASSETS			$	12,985,609	$	13,024,253

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

185

OHIO POWER COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
December 31, 2012 and 2011

		December 31,
		2012		2011
		(in thousands)
CURRENT LIABILITIES
Accounts Payable:
	General	$	276,220	$	293,730
	Affiliated Companies		153,222		183,898
Long-term Debt Due Within One Year – Nonaffiliated			856,000		244,500
Risk Management Liabilities			24,155		36,561
Accrued Taxes			467,309		450,570
Accrued Interest			63,560		66,441
Other Current Liabilities			263,638		238,275
TOTAL CURRENT LIABILITIES			2,104,104		1,513,975

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			2,804,440		3,609,648
Long-term Debt – Affiliated			200,000		200,000
Long-term Risk Management Liabilities			25,965		17,890
Deferred Income Taxes			2,345,850		2,245,380
Regulatory Liabilities and Deferred Investment Tax Credits			451,071		301,124
Employee Benefits and Pension Obligations			178,620		335,029
Deferred Credits and Other Noncurrent Liabilities			349,850		351,029
TOTAL NONCURRENT LIABILITIES			6,355,796		7,060,100

TOTAL LIABILITIES			8,459,900		8,574,075

Rate Matters (Note 2)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER'S EQUITY
Common Stock – No Par Value:
	Authorized – 40,000,000 Shares
	Outstanding – 27,952,473 Shares		321,201		321,201
Paid-in Capital			1,744,099		1,744,099
Retained Earnings			2,626,134		2,582,600
Accumulated Other Comprehensive Income (Loss)			(165,725)		(197,722)
TOTAL COMMON SHAREHOLDER’S EQUITY			4,525,709		4,450,178

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	12,985,609	$	13,024,253

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

186

OHIO POWER COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

				Years Ended December 31,
				2012		2011		2010
OPERATING ACTIVITIES
Net Income				$	343,534	$	464,993	$	541,616
Adjustments to Reconcile Net Income to Net Cash Flows from
	Operating Activities:
		Depreciation and Amortization			511,070		545,376		513,168
		Deferred Income Taxes			45,685		119,184		292,831
		Asset Impairments and Other Related Charges			287,031		89,824		-
		Carrying Costs Income			(16,942)		(53,345)		(31,796)
		Deferral of Storm Costs			(53,453)		(8,375)		-
		Allowance for Equity Funds Used During Construction			(3,492)		(5,549)		(5,949)
		Mark-to-Market of Risk Management Contracts			12,143		(3,695)		25,251
		Pension Contributions to Qualified Plan Trust			(43,189)		(127,884)		(58,639)
		Property Taxes			(3,849)		(5,722)		(19,324)
		Fuel Over/Under-Recovery, Net			10,598		(727)		(131,850)
		Change in Other Noncurrent Assets			(68,924)		(64,867)		3,797
		Change in Other Noncurrent Liabilities			(27,039)		85,173		(17,079)
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		(37,787)		116,197		(126,071)
			Fuel, Materials and Supplies		(54,945)		79,787		66,700
			Accounts Payable		(63,450)		(17,059)		72,694
			Accrued Taxes, Net		41,475		36,466		131,441
			Other Current Assets		9,977		7,789		924
			Other Current Liabilities		17,669		(15,821)		53,985
Net Cash Flows from Operating Activities					906,112		1,241,745		1,311,699

INVESTING ACTIVITIES
Construction Expenditures					(517,744)		(454,873)		(504,702)
Change in Advances to Affiliates, Net					103,036		(64,756)		283,650
Acquisitions of Assets					(2,915)		(2,229)		(5,801)
Proceeds from Sales of Assets					7,320		47,463		14,382
Other Investing Activities					10,014		29,014		26,400
Net Cash Flows Used for Investing Activities					(400,289)		(445,381)		(186,071)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated					-		49,748		351,824
Change in Advances from Affiliates, Net					-		-		(24,202)
Retirement of Long-term Debt – Nonaffiliated					(194,500)		(165,000)		(868,580)
Retirement of Long-term Debt – Affiliated					-		-		(100,000)
Retirement of Cumulative Preferred Stock					-		(17,831)		(7)
Principal Payments for Capital Lease Obligations					(10,072)		(11,854)		(11,617)
Dividends Paid on Common Stock					(300,000)		(650,000)		(469,075)
Dividends Paid on Cumulative Preferred Stock					-		(671)		(732)
Other Financing Activities					294		390		(5,370)
Net Cash Flows Used for Financing Activities					(504,278)		(795,218)		(1,127,759)

Net Increase (Decrease) in Cash and Cash Equivalents					1,545		1,146		(2,131)
Cash and Cash Equivalents at Beginning of Period					2,095		949		3,080
Cash and Cash Equivalents at End of Period				$	3,640	$	2,095	$	949

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	212,753	$	226,711	$	239,984
Net Cash Paid (Received) for Income Taxes					69,771		81,740		(78,268)
Noncash Acquisitions Under Capital Leases					8,602		5,766		33,369
Government Grants Included in Accounts Receivable as of December 31,					660		1,383		9,260
Construction Expenditures Included in Current Liabilities as of December 31,					84,321		61,428		31,939

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

187

OHIO POWER COMPANY AND SUBSIDIARY

INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to OPCo’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to OPCo. The footnotes begin on page 217.

	Footnote Reference

Organization and Summary of Significant Accounting Policies	Note 1
Rate Matters	Note 2
Effects of Regulation	Note 3
Commitments, Guarantees and Contingencies	Note 4
Acquisitions and Impairments	Note 5
Benefit Plans	Note 6
Business Segments	Note 7
Derivatives and Hedging	Note 8
Fair Value Measurements	Note 9
Income Taxes	Note 10
Leases	Note 11
Financing Activities	Note 12
Related Party Transactions	Note 13
Variable Interest Entities	Note 14
Property, Plant and Equipment	Note 15
Cost Reduction Programs	Note 16
Unaudited Quarterly Financial Information	Note 17

188

PUBLIC SERVICE COMPANY OF OKLAHOMA

189

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

As a public utility, PSO engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 535,000 retail customers in its service territory in eastern and southwestern Oklahoma. PSO sells electric power at wholesale to other utilities, municipalities and electric cooperatives.

PSO, as a party to the CSW Operating Agreement, is compensated for energy delivered to the other member based upon the delivering member’s incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives. PSO and SWEPCo share the revenues and costs of sales to neighboring utilities and power marketers made by AEPSC on their behalf based upon the relative magnitude of the energy each company provides to make such sales. PSO shares off-system sales margins, if positive on an annual basis, with its customers.

AEPSC conducts power, gas, coal and emission allowance risk management activities on PSO’s behalf. PSO shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the AEP East Companies and SWEPCo. Power and gas risk management activities are allocated based on the CSW Operating Agreement and the SIA. PSO shares in coal and emission allowance risk management activities based on its proportion of fossil fuels burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and, to a lesser extent, gas, coal and emission allowances. The electricity, gas, coal and emission allowance contracts include physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.

PSO is jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA.

Regulatory Activity

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES) Unit 4 in 2016 and additional environmental controls on NES Unit 3 to continue operations through 2026. The plan requested approval for (a) cost recovery through base rates by 2026 of an estimated $256 million of new environmental investment that will be incurred prior to 2016 at NES Unit 3, (b) cost recovery through 2026 of NES Units 3 and 4 net book value (combined net book value of the two units is $234 million as of December 31, 2012), (c) cost recovery through base rates of an estimated $83 million of new investment incurred through 2016 at various gas units and (d) a new 15-year purchase power agreement (PPA) with Calpine Oneta Power, effective in 2016, with cost recovery through a rider, including an annual earnings component of $3 million. Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery when filing its next base rate case, which is expected to occur no later than 2014. In January 2013, several parties filed testimony with various recommendations. A hearing is scheduled for April 2013. See “Oklahoma Environmental Compliance Plan” section of Note 2.

190

Litigation and Environmental Issues

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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

		Years Ended December 31,
		2012		2011		2010
		(in millions of KWhs)
Retail:
	Residential		6,393		6,741		6,595
	Commercial		5,178		5,190		5,136
	Industrial		5,066		4,956		4,921
	Miscellaneous		1,326		1,310		1,265
Total Retail			17,963		18,197		17,917

Wholesale			1,492		1,113		1,190

Total KWhs			19,455		19,310		19,107

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

Summary of Heating and Cooling Degree Days

		Years Ended December 31,
		2012		2011		2010
		(in degree days)
Actual - Heating (a)			1,271		1,879		1,993
Normal - Heating (b)			1,803		1,796		1,784

Actual - Cooling (c)			2,663		2,788		2,380
Normal - Cooling (b)			2,119		2,102		2,095

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

191

2012 Compared to 2011

Reconciliation of Year Ended December 31, 2011 to Year Ended December 31, 2012
Net Income
(in millions)

Year Ended December 31, 2011	$	125

Changes in Gross Margin:
Retail Margins (a)		7
Off-system Sales		(1	)
Transmission Revenues		(1	)
Total Change in Gross Margin		5

Changes in Expenses and Other:
Other Operation and Maintenance		(14	)
Depreciation and Amortization		1
Taxes Other Than Income Taxes		(2	)
Other Income		(1	)
Interest Expense		(1	)
Total Change in Expenses and Other		(17	)

Income Tax Expense		1

Year Ended December 31, 2012	$	114

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

·	Retail Margins increased $7 million primarily due to the following:
	·	A $13 million increase primarily due to revenue increases from rate riders. This increase in retail margins has corresponding increases to riders/trackers recognized in other expense items below.
	·	A $7 million increase primarily due to higher commercial non-weather related usage.
	These increases were partially offset by:
	·	A $12 million decrease in weather-related usage primarily due to a 4% decrease in cooling degree days and a 32% decrease in heating degree days.

Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $14 million primarily due to the following:
	·	A $16 million increase in transmission expenses primarily due to increased SPP transmission services.
	·	A $4 million increase due to expenses related to the 2012 sustainable cost reductions.
	·	A $4 million increase in plant maintenance expenses due to the deferral of generation maintenance expenses in 2011 as a result of PSO’s base rate case.
	These increases were partially offset by:
	·	A $6 million decrease in general and administrative expenses.
	·	A $3 million decrease in demand side management programs.
	·	A $2 million decrease in distribution expenses primarily due to decreased overhead line expenses.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

192

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Public Service Company of Oklahoma:

We have audited the accompanying balance sheets of Public Service Company of Oklahoma (the "Company") as of December 31, 2012 and 2011, and the related statements of income, comprehensive income (loss), changes in common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012. 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.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Public Service Company of Oklahoma as of December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 26, 2013

193

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Public Service Company of Oklahoma (PSO) 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. PSO’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.

Management assessed the effectiveness of PSO’s internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, PSO’s internal control over financial reporting was effective as of December 31, 2012.

This annual report does not include an attestation report of PSO’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit PSO to provide only management’s report in this annual report.

194

PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF INCOME
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

	Years Ended December 31,
	2012			2011			2010
REVENUES
Electric Generation, Transmission and Distribution	$	1,206,583		$	1,345,551		$	1,246,916
Sales to AEP Affiliates		22,603			14,192			23,528
Other Revenues		3,752			3,645			3,218
TOTAL REVENUES		1,232,938			1,363,388			1,273,662

EXPENSES
Fuel and Other Consumables Used for Electric Generation		310,296			465,546			373,317
Purchased Electricity for Resale		208,676			163,550			187,106
Purchased Electricity from AEP Affiliates		24,378			50,092			46,013
Other Operation		213,195			201,247			222,396
Maintenance		106,835			104,732			115,788
Depreciation and Amortization		95,180			95,915			104,929
Taxes Other Than Income Taxes		43,428			41,295			42,121
TOTAL EXPENSES		1,001,988			1,122,377			1,091,670

OPERATING INCOME		230,950			241,011			181,992

Other Income (Expense):
Interest Income		1,308			596			308
Carrying Costs Income		1,856			4,033			3,145
Allowance for Equity Funds Used During Construction		2,007			1,317			804
Interest Expense		(55,286	)		(54,700	)		(63,362	)

INCOME BEFORE INCOME TAX EXPENSE		180,835			192,257			122,887

Income Tax Expense		66,694			67,629			50,100

NET INCOME		114,141			124,628			72,787

Preferred Stock Dividend Requirements Including Capital Stock
Expense		-			434			200

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	114,141		$	124,194		$	72,587

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

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

195

PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

		Years Ended December 31,
		2012		2011		2010
Net Income		$	114,141	$	124,628	$	72,787

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $360, $724 and $4,896 in 2012, 2011 and 2010,
	Respectively		(668)		(1,345)		9,093

TOTAL COMPREHENSIVE INCOME		$	113,473	$	123,283	$	81,880

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

196

PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

									Accumulated
									Other
	Common		Paid-in			Retained			Comprehensive
	Stock		Capital			Earnings			Income (Loss)			Total

TOTAL COMMON SHAREHOLDER'S EQUITY –
DECEMBER 31, 2009	$	157,230	$	364,231		$	290,880		$	(599	)	$	811,742

Common Stock Dividends							(51,026	)					(51,026	)
Preferred Stock Dividends							(200	)					(200	)
Gain on Reacquired Preferred Stock				76									76
Subtotal – Common Shareholder's Equity													760,592

Net Income							72,787						72,787
Other Comprehensive Income										9,093			9,093
TOTAL COMMON SHAREHOLDER'S EQUITY –
DECEMBER 31, 2010		157,230		364,307			312,441			8,494			842,472

Common Stock Dividends							(72,500	)					(72,500	)
Preferred Stock Dividends							(180	)					(180	)
Loss on Reacquired Preferred Stock				(270	)								(270	)
Subtotal – Common Shareholder's Equity													769,522

Net Income							124,628						124,628
Other Comprehensive Loss										(1,345	)		(1,345	)
TOTAL COMMON SHAREHOLDER'S EQUITY –
DECEMBER 31, 2011		157,230		364,037			364,389			7,149			892,805

Common Stock Dividends							(90,000	)					(90,000	)
Subtotal – Common Shareholder's Equity													802,805

Net Income							114,141						114,141
Other Comprehensive Loss										(668	)		(668	)
TOTAL COMMON SHAREHOLDER'S EQUITY –
DECEMBER 31, 2012	$	157,230	$	364,037		$	388,530		$	6,481		$	916,278

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

197

PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
ASSETS
December 31, 2012 and 2011
(in thousands)

			December 31,
			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	1,367	$	1,413
Advances to Affiliates				10,558		39,876
Accounts Receivable:
	Customers			31,047		39,977
	Affiliated Companies			24,751		23,079
	Miscellaneous			6,216		8,993
	Allowance for Uncollectible Accounts			(872)		(777)
		Total Accounts Receivable		61,142		71,272
Fuel				22,085		20,854
Materials and Supplies				52,183		50,347
Risk Management Assets				509		565
Deferred Income Tax Benefits				7,183		7,013
Accrued Tax Benefits				11,812		6,733
Regulatory Asset for Under-Recovered Fuel Costs				-		4,313
Prepayments and Other Current Assets				7,633		6,440
TOTAL CURRENT ASSETS				174,472		208,826

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			1,346,530		1,317,948
	Transmission			706,917		692,644
	Distribution			1,859,557		1,762,110
Other Property, Plant and Equipment				210,549		214,626
Construction Work in Progress				95,170		70,371
Total Property, Plant and Equipment				4,218,723		4,057,699
Accumulated Depreciation and Amortization				1,278,941		1,266,816
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				2,939,782		2,790,883

OTHER NONCURRENT ASSETS
Regulatory Assets				202,328		266,545
Long-term Risk Management Assets				31		314
Deferred Charges and Other Noncurrent Assets				8,560		13,536
TOTAL OTHER NONCURRENT ASSETS				210,919		280,395

TOTAL ASSETS			$	3,325,173	$	3,280,104

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

198

PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
December 31, 2012 and 2011

		December 31,
		2012		2011
			(in thousands)
CURRENT LIABILITIES
Accounts Payable:
	General	$	87,050	$	76,607
	Affiliated Companies		36,189		45,029
Long-term Debt Due Within One Year – Nonaffiliated			764		311
Risk Management Liabilities			5,848		1,280
Customer Deposits			46,533		47,493
Accrued Taxes			28,024		21,660
Accrued Interest			12,654		12,637
Regulatory Liability for Over-Recovered Fuel Costs			7,945		-
Other Current Liabilities			50,684		43,586
TOTAL CURRENT LIABILITIES			275,691		248,603

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			949,107		947,053
Long-term Risk Management Liabilities			31		1,330
Deferred Income Taxes			740,676		726,463
Regulatory Liabilities and Deferred Investment Tax Credits			344,817		334,812
Employee Benefits and Pension Obligations			34,906		84,548
Deferred Credits and Other Noncurrent Liabilities			63,667		44,490
TOTAL NONCURRENT LIABILITIES			2,133,204		2,138,696

TOTAL LIABILITIES			2,408,895		2,387,299

Rate Matters (Note 2)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
	Authorized – 11,000,000 Shares
	Issued – 10,482,000 Shares
	Outstanding – 9,013,000 Shares		157,230		157,230
Paid-in Capital			364,037		364,037
Retained Earnings			388,530		364,389
Accumulated Other Comprehensive Income (Loss)			6,481		7,149
TOTAL COMMON SHAREHOLDER’S EQUITY			916,278		892,805

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	3,325,173	$	3,280,104

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

199

PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

				Years Ended December 31,
				2012		2011		2010
OPERATING ACTIVITIES
Net Income				$	114,141	$	124,628	$	72,787
Adjustments to Reconcile Net Income to Net Cash Flows from
	Operating Activities:
		Depreciation and Amortization			95,180		95,915		104,929
		Deferred Income Taxes			48,916		61,581		92,695
		Carrying Costs Income			(1,856)		(4,033)		(3,145)
		Allowance for Equity Funds Used During Construction			(2,007)		(1,317)		(804)
		Mark-to-Market of Risk Management Contracts			3,740		1,290		160
		Pension Contributions to Qualified Plan Trust			(12,306)		(33,189)		(12,848)
		Fuel Over/Under-Recovery, Net			12,258		32,949		(88,349)
		Change in Other Noncurrent Assets			7,436		14,883		(19,279)
		Change in Other Noncurrent Liabilities			4,762		32,196		16,612
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		4,422		44,414		(10,094)
			Fuel, Materials and Supplies		(3,067)		(4,778)		(617)
			Accounts Payable		3,158		(20,068)		(20,601)
			Accrued Taxes, Net		5,006		19,535		(23,605)
			Other Current Assets		(970)		4,855		4,446
			Other Current Liabilities		5,538		10,628		(18,341)
Net Cash Flows from Operating Activities					284,351		379,489		93,946

INVESTING ACTIVITIES
Construction Expenditures					(224,295)		(140,327)		(194,896)
Change in Advances to Affiliates, Net					29,318		(39,876)		62,695
Other Investing Activities					1,723		1,126		(368)
Net Cash Flows Used for Investing Activities					(193,254)		(179,077)		(132,569)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated					2,395		248,909		2,240
Change in Advances from Affiliates, Net					-		(91,382)		91,382
Retirement of Long-term Debt – Nonaffiliated					(229)		(275,000)		-
Retirement of Cumulative Preferred Stock					-		(5,152)		(300)
Principal Payments for Capital Lease Obligations					(3,481)		(4,189)		(3,991)
Dividends Paid on Common Stock					(90,000)		(72,500)		(51,026)
Dividends Paid on Cumulative Preferred Stock					-		(180)		(200)
Other Financing Activities					172		25		192
Net Cash Flows from (Used for) Financing Activities					(91,143)		(199,469)		38,297

Net Increase (Decrease) in Cash and Cash Equivalents					(46)		943		(326)
Cash and Cash Equivalents at Beginning of Period					1,413		470		796
Cash and Cash Equivalents at End of Period				$	1,367	$	1,413	$	470

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	52,403	$	37,573	$	57,970
Net Cash Paid (Received) for Income Taxes					27,229		(16,043)		(16,770)
Noncash Acquisitions Under Capital Leases					1,542		1,078		13,794
Construction Expenditures Included in Current Liabilities as of December 31,					27,118		28,427		6,842

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

200

PUBLIC SERVICE COMPANY OF OKLAHOMA

INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to PSO’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to PSO. The footnotes begin on page 217.

	Footnote Reference

Organization and Summary of Significant Accounting Policies	Note 1
Rate Matters	Note 2
Effects of Regulation	Note 3
Commitments, Guarantees and Contingencies	Note 4
Benefit Plans	Note 6
Business Segments	Note 7
Derivatives and Hedging	Note 8
Fair Value Measurements	Note 9
Income Taxes	Note 10
Leases	Note 11
Financing Activities	Note 12
Related Party Transactions	Note 13
Variable Interest Entities	Note 14
Property, Plant and Equipment	Note 15
Cost Reduction Programs	Note 16
Unaudited Quarterly Financial Information	Note 17

201

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

202

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

As a public utility, SWEPCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 524,000 retail customers in its service territory in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas. SWEPCo consolidates its wholly-owned subsidiary, Southwest Arkansas Utilities Corporation. SWEPCo also consolidates Sabine Mining Company, a variable interest entity. SWEPCo sells electric power at wholesale to other utilities, municipalities and electric cooperatives.

SWEPCo, as a party to the CSW Operating Agreement, is compensated for energy delivered to the other member based upon the delivering member’s incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives. PSO and SWEPCo share the revenues and costs for sales to neighboring utilities and power marketers made by AEPSC on their behalf based upon the relative magnitude of the energy each company provides to make such sales. SWEPCo shares these margins with its customers.

AEPSC conducts power, gas, coal and emission allowance risk management activities on SWEPCo’s behalf. SWEPCo shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the AEP East Companies and PSO. Power and gas risk management activities are allocated based on the CSW Operating Agreement and the SIA. SWEPCo shares in coal and emission allowance risk management activities based on its proportion of fossil fuels burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and, to a lesser extent, gas, coal and emission allowances. The electricity, gas, coal and emission allowance contracts include physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.

SWEPCo is jointly and severally liable for activity conducted by AEPSC on the behalf of PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA.

Regulatory Activity

Turk Plant

Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million, primarily due to the Turk Plant, based upon an 11.25% return on common equity to be effective January 2013. The requested base rate increase included a return on and of the Texas jurisdictional share (approximately 33%) of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs. In September 2012, an Administrative Law Judge issued an order that granted the establishment of SWEPCo’s existing rates as temporary rates beginning in late January 2013, subject to

203

true-up to the final PUCT-approved rates. In December 2012, several intervenors filed opposing testimony with various recommendations. A decision from the PUCT is expected in the second quarter of 2013. See “2012 Texas Base Rate Case” section of Note 2.

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 a hearing was conducted. The settlement provided that SWEPCo would increase Louisiana total rates by approximately $2 million annually, effective March 2013, consisting of an increase in base rates of approximately $85 million annually offset by a decrease in fuel rates of approximately $83 million annually. The proposed March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund based on the staff review of the cost of service and prudence review of the Turk Plant to be initiated by SWEPCo no later than May 2013. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover all non-fuel Turk Plant costs and a full weighted-average cost of capital return on the Turk Plant portion of rate base beginning January 2013. A decision from the LPSC is expected in the first quarter of 2013.

Flint Creek Plant Environmental Controls

In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA. The estimated cost of the project is $408 million, excluding AFUDC and company overheads. As a joint owner of the Flint Creek Plant, SWEPCo’s portion of those costs is estimated at $204 million. As of December 31, 2012, SWEPCo has incurred $11 million related to this project, including AFUDC and company overheads. The APSC staff and the Sierra Club filed testimony that recommended the APSC deny the requested declaratory order. A hearing is scheduled for March 2013. If SWEPCo is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

Litigation and Environmental Issues

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

204

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

		Years Ended December 31,
		2012		2011		2010
		(in millions of KWhs)
Retail:
	Residential		6,301		6,908		6,361
	Commercial		6,103		6,280		6,117
	Industrial		5,661		5,408		5,254
	Miscellaneous		81		82		81
Total Retail			18,146		18,678		17,813

Wholesale			7,762		7,947		7,333

Total KWhs			25,908		26,625		25,146

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

Summary of Heating and Cooling Degree Days

		Years Ended December 31,
		2012		2011		2010
		(in degree days)
Actual - Heating (a)			860		1,271		1,543
Normal - Heating (b)			1,259		1,260		1,253

Actual - Cooling (c)			2,605		2,874		2,592
Normal - Cooling (b)			2,256		2,231		2,213

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

205

2012 Compared to 2011

Reconciliation of Year Ended December 31, 2011 to Year Ended December 31, 2012
Net Income
(in millions)

Year Ended December 31, 2011	$	165

Changes in Gross Margin:
Retail Margins (a)		(18	)
Off-system Sales		1
Transmission Revenues		4
Other Revenues		(2	)
Total Change in Gross Margin		(15	)

Changes in Expenses and Other:
Other Operation and Maintenance		18
Asset Impairment and Other Related Charges		36
Depreciation and Amortization		(5	)
Taxes Other Than Income Taxes		(7	)
Interest Income		(1	)
Allowance for Equity Funds Used During Construction		8
Interest Expense		(7	)
Total Change in Expenses and Other		42

Income Tax Expense		11

Year Ended December 31, 2012	$	203

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

·	Retail Margins decreased $18 million primarily due to the following:
	·	A $23 million decrease in weather-related usage primarily due to a 9% decrease in cooling degree days and a 32% decrease in heating degree days.
	·	A $14 million decrease primarily due to fuel expense adjustments.
	These decreases were partially offset by:
	·	An $18 million increase in municipal and cooperative revenues due to higher rates and formula rate adjustments.
·	Transmission Revenues increased $4 million due to higher rates in the SPP region.

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

·	Other Operation and Maintenance expenses decreased $18 million primarily due to the following:
	·	A $12 million decrease in generation maintenance expenses primarily due to higher 2011 planned and unplanned plant outages.
	·	An $11 million decrease in distribution maintenance expenses primarily due to decreased vegetation management expenses.
	·	A $5 million decrease related to 2011 litigation expenses.
	These decreases were partially offset by:
	·	A $6 million increase due to expenses related to the 2012 sustainable cost reductions.
	·	A $5 million increase in employee-related expenses.
·	Asset Impairment and Other Related Charges decreased $36 million due to the 2011 write-off of $49 million related to the expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap as a result of the November 2011 Texas Court of Appeals decision. This was partially offset by the 2012 write-off of an additional $13 million related to the Texas capital cost cap.

206

·	Depreciation and Amortization expenses increased $5 million primarily due to a greater depreciable base.
·	Taxes Other Than Income Taxes increased $7 million primarily due to favorable property tax adjustments made in 2011.
·	Allowance for Equity Funds Used During Construction increased $8 million primarily due to construction of the Turk Plant.
·	Interest Expense increased $7 million primarily due to the issuance of Senior Unsecured Notes, partially offset by an increase in the debt component of AFUDC due to construction of the Turk Plant.
·	Income Tax Expense decreased $11 million primarily due to state book/tax differences which are accounted for on a flow-through basis, partially offset by an increase in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

207

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Southwestern Electric Power Company:

We have audited the accompanying consolidated balance sheets of Southwestern Electric Power Company Consolidated (the "Company") as of December 31, 2012 and 2011, 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, 2012. 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.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southwestern Electric Power Company Consolidated as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 26, 2013

208

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Southwestern Electric Power Company Consolidated (SWEPCo) 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. SWEPCo’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.

Management assessed the effectiveness of SWEPCo’s internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, SWEPCo’s internal control over financial reporting was effective as of December 31, 2012.

This annual report does not include an attestation report of SWEPCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit SWEPCo to provide only management’s report in this annual report.

209

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

	Years Ended December 31,
	2012			2011			2010
REVENUES
Electric Generation, Transmission and Distribution	$	1,538,533		$	1,594,192		$	1,469,514
Sales to AEP Affiliates		37,441			57,615			51,870
Other Revenues		1,860			2,019			2,150
TOTAL REVENUES		1,577,834			1,653,826			1,523,534

EXPENSES
Fuel and Other Consumables Used for Electric Generation		579,721			626,599			587,058
Purchased Electricity for Resale		131,706			152,645			125,064
Purchased Electricity from AEP Affiliates		19,229			11,808			23,707
Other Operation		230,078			224,068			245,504
Maintenance		117,415			140,981			103,352
Asset Impairment and Other Related Charges		13,000			49,000			-
Depreciation and Amortization		138,778			133,229			126,901
Taxes Other Than Income Taxes		72,011			65,239			63,151
TOTAL EXPENSES		1,301,938			1,403,569			1,274,737

OPERATING INCOME		275,896			250,257			248,797

Other Income (Expense):
Interest Income		1,230			2,076			579
Allowance for Equity Funds Used During Construction		57,054			48,731			45,646
Interest Expense		(88,318	)		(81,781	)		(86,538	)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY
EARNINGS		245,862			219,283			208,484

Income Tax Expense		45,858			56,903			64,214
Equity Earnings of Unconsolidated Subsidiary		2,509			2,746			2,414

NET INCOME		202,513			165,126			146,684

Net Income Attributable to Noncontrolling Interest		3,622			3,841			4,093

NET INCOME ATTRIBUTABLE TO SWEPCo SHAREHOLDERS		198,891			161,285			142,591

Preferred Stock Dividend Requirements Including Capital Stock
Expense		-			579			229

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON
SHAREHOLDER	$	198,891		$	160,706		$	142,362

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

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

210

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

		Years Ended December 31,
		2012		2011		2010
Net Income		$	202,513	$	165,126	$	146,684

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $13, $6,103 and $401 in 2012, 2011 and 2010,
	Respectively		(25)		(11,334)		745
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $358, $275 and
	$505 in 2012, 2011 and 2010, Respectively		665		511		937
Pension and OPEB Funded Status, Net of Tax of $4,477, $1,885 and $636 in 2012,
	2011 and 2010, Respectively		8,315		(3,501)		(1,182)

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			8,955		(14,324)		500

TOTAL COMPREHENSIVE INCOME			211,468		150,802		147,184

Total Comprehensive Income Attributable to Noncontrolling Interest			3,622		3,841		4,093

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo
	SHAREHOLDERS	$	207,846	$	146,961	$	143,091

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

211

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

	SWEPCo Common Shareholder
									Accumulated
									Other
	Common		Paid-in			Retained			Comprehensive			Noncontrolling
	Stock		Capital			Earnings			Income (Loss)			Interest			Total

TOTAL EQUITY – DECEMBER 31, 2009	$	135,660	$	674,979		$	726,478		$	(12,991	)	$	31		$	1,524,157

Common Stock Dividends – Nonaffiliated													(3,763	)		(3,763	)
Preferred Stock Dividends							(229	)								(229	)
Subtotal – Equity																1,520,165

Net Income							142,591						4,093			146,684
Other Comprehensive Income										500						500
TOTAL EQUITY – DECEMBER 31, 2010		135,660		674,979			868,840			(12,491	)		361			1,667,349

Common Stock Dividends – Nonaffiliated													(3,811	)		(3,811	)
Preferred Stock Dividends							(210	)								(210	)
Loss on Reacquired Preferred Stock				(373	)											(373	)
Subtotal – Equity																1,662,955

Net Income							161,285						3,841			165,126
Other Comprehensive Loss										(14,324	)					(14,324	)
TOTAL EQUITY – DECEMBER 31, 2011		135,660		674,606			1,029,915			(26,815	)		391			1,813,757

Common Stock Dividends – Nonaffiliated													(3,752	)		(3,752	)
Subtotal – Equity																1,810,005

Net Income							198,891						3,622			202,513
Other Comprehensive Income										8,955						8,955
TOTAL EQUITY – DECEMBER 31, 2012	$	135,660	$	674,606		$	1,228,806		$	(17,860	)	$	261		$	2,021,473

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

212

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2012 and 2011
(in thousands)

			December 31,
			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	2,036	$	801
Advances to Affiliates				153,829		-
Accounts Receivable:
	Customers			39,349		35,054
	Affiliated Companies			26,288		23,730
	Miscellaneous			35,514		19,370
	Allowance for Uncollectible Accounts			(2,041)		(989)
		Total Accounts Receivable		99,110		77,165
Fuel
	(December 31, 2012 and 2011 Amounts Include $42,084 and
	$32,651, Respectively, Related to Sabine)			134,234		102,015
Materials and Supplies				69,212		55,325
Risk Management Assets				695		445
Deferred Income Tax Benefits				101,403		8,195
Accrued Tax Benefits				9,616		1,541
Regulatory Asset for Under-Recovered Fuel Costs				8,527		10,843
Prepayments and Other Current Assets				16,489		16,827
TOTAL CURRENT ASSETS				595,151		273,157

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			3,888,230		2,326,102
	Transmission			1,115,795		988,534
	Distribution			1,758,988		1,675,764
Other Property, Plant and Equipment
	(December 31, 2012 and 2011 Amounts include $287,032 and
	$232,948, Respectively, Related to Sabine)			688,254		637,019
Construction Work in Progress				99,783		1,443,569
Total Property, Plant and Equipment				7,551,050		7,070,988
Accumulated Depreciation and Amortization
	(December 31, 2012 and 2011 Amounts Include $116,597 and
	$103,586, Respectively, Related to Sabine)			2,284,258		2,211,912
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				5,266,792		4,859,076

OTHER NONCURRENT ASSETS
Regulatory Assets				403,278		394,276
Long-term Risk Management Assets				-		282
Deferred Charges and Other Noncurrent Assets				76,432		74,992
TOTAL OTHER NONCURRENT ASSETS				479,710		469,550

TOTAL ASSETS			$	6,341,653	$	5,601,783

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

213

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2012 and 2011

		December 31,
		2012		2011

			(in thousands)
CURRENT LIABILITIES
Advances from Affiliates		$	-	$	132,473
Accounts Payable:
	General		126,768		181,268
	Affiliated Companies		62,835		59,201
Short-term Debt – Nonaffiliated			2,603		17,016
Long-term Debt Due Within One Year – Nonaffiliated			3,250		20,000
Risk Management Liabilities			1,128		24,359
Customer Deposits			69,393		52,095
Accrued Taxes			31,532		44,404
Accrued Interest			43,950		39,629
Obligations Under Capital Leases			17,599		15,058
Regulatory Liability for Over-Recovered Fuel Costs			16,761		5,032
Other Current Liabilities			64,997		64,413
TOTAL CURRENT LIABILITIES			440,816		654,948

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			2,042,978		1,708,637
Long-term Risk Management Liabilities			-		221
Deferred Income Taxes			1,075,551		665,668
Regulatory Liabilities and Deferred Investment Tax Credits			476,471		428,571
Asset Retirement Obligations			78,017		65,673
Employee Benefits and Pension Obligations			38,240		87,159
Obligations Under Capital Leases			114,161		112,802
Deferred Credits and Other Noncurrent Liabilities			53,946		64,347
TOTAL NONCURRENT LIABILITIES			3,879,364		3,133,078

TOTAL LIABILITIES			4,320,180		3,788,026

Rate Matters (Note 2)
Commitments and Contingencies (Note 4)

EQUITY
Common Stock – Par Value – $18 Per Share:
	Authorized – 7,600,000 Shares
	Outstanding – 7,536,640 Shares		135,660		135,660
Paid-in Capital			674,606		674,606
Retained Earnings			1,228,806		1,029,915
Accumulated Other Comprehensive Income (Loss)			(17,860)		(26,815)
TOTAL COMMON SHAREHOLDER’S EQUITY			2,021,212		1,813,366

Noncontrolling Interest			261		391

TOTAL EQUITY			2,021,473		1,813,757

TOTAL LIABILITIES AND EQUITY		$	6,341,653	$	5,601,783

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

214

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2012, 2011 and 2010
(in thousands)

				Years Ended December 31,
				2012		2011		2010
OPERATING ACTIVITIES
Net Income				$	202,513	$	165,126	$	146,684
Adjustments to Reconcile Net Income to Net Cash Flows from
	Operating Activities:
		Depreciation and Amortization			138,778		133,229		126,901
		Deferred Income Taxes			260,761		16,726		81,764
		Asset Impairment and Other Related Charges			13,000		49,000		-
		Allowance for Equity Funds Used During Construction			(57,054)		(48,731)		(45,646)
		Mark-to-Market of Risk Management Contracts			(4,159)		1,732		4,826
		Pension Contributions to Qualified Plan Trust			(13,192)		(31,263)		(29,065)
		Fuel Over/Under-Recovery, Net			14,045		(21,485)		(6,089)
		Change in Regulatory Liabilities			37,955		28,031		26,671
		Change in Other Noncurrent Assets			21,309		24,519		(15,207)
		Change in Other Noncurrent Liabilities			14,594		20,904		21,958
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		(21,919)		20,751		(21,507)
			Fuel, Materials and Supplies		(46,106)		(15,168)		21,498
			Accounts Payable		3,813		1,168		(23,004)
			Accrued Taxes, Net		(16,057)		40,189		(18,788)
			Accrued Interest		4,294		(910)		6,570
			Other Current Assets		(387)		2,983		(3,182)
			Other Current Liabilities		(7,905)		340		(1,433)
Net Cash Flows from Operating Activities					544,283		387,141		272,951

INVESTING ACTIVITIES
Construction Expenditures					(542,427)		(551,163)		(420,485)
Change in Advances to Affiliates, Net					(153,829)		86,222		(34,405)
Acquisitions of Assets					(1,091)		(8,045)		(103,225)
Other Investing Activities					2,696		2,102		4,945
Net Cash Flows Used for Investing Activities					(694,651)		(470,884)		(553,170)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated					336,418		-		399,394
Credit Facility Borrowings					25,123		58,435		99,688
Change in Advances from Affiliates, Net					(132,473)		132,473		-
Retirement of Long-term Debt – Nonaffiliated					(21,625)		(41,135)		(53,500)
Retirement of Long-term Debt – Affiliated					-		-		(50,000)
Retirement of Cumulative Preferred Stock					-		(5,069)		(1)
Credit Facility Repayments					(39,536)		(47,636)		(100,361)
Principal Payments for Capital Lease Obligations					(16,537)		(13,675)		(12,183)
Dividends Paid on Common Stock – Nonaffiliated					(3,752)		(3,811)		(3,763)
Dividends Paid on Cumulative Preferred Stock					-		(210)		(229)
Other Financing Activities					3,985		3,658		1,027
Net Cash Flows from Financing Activities					151,603		83,030		280,072

Net Increase (Decrease) in Cash and Cash Equivalents					1,235		(713)		(147)
Cash and Cash Equivalents at Beginning of Period					801		1,514		1,661
Cash and Cash Equivalents at End of Period				$	2,036	$	801	$	1,514

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	68,918	$	71,713	$	70,729
Net Cash Paid (Received) for Income Taxes					(191,638)		(336)		8,350
Noncash Acquisitions Under Capital Leases					20,547		13,334		1,593
Construction Expenditures Included in Current Liabilities as of December 31,					55,767		109,600		94,836
Noncash Assumption of Liabilities Related to Acquisitions					-		-		8,400

See Notes to Financial Statements of Registrant Subsidiaries beginning on page 217.

215

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to SWEPCo’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to SWEPCo. The footnotes begin on page 217.

	Footnote Reference

Organization and Summary of Significant Accounting Policies	Note 1
Rate Matters	Note 2
Effects of Regulation	Note 3
Commitments, Guarantees and Contingencies	Note 4
Acquisitions and Impairments	Note 5
Benefit Plans	Note 6
Business Segments	Note 7
Derivatives and Hedging	Note 8
Fair Value Measurements	Note 9
Income Taxes	Note 10
Leases	Note 11
Financing Activities	Note 12
Related Party Transactions	Note 13
Variable Interest Entities	Note 14
Property, Plant and Equipment	Note 15
Cost Reduction Programs	Note 16
Unaudited Quarterly Financial Information	Note 17

216

INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to financial statements that follow are a combined presentation for the Registrant Subsidiaries. The following list indicates the registrants to which the footnotes apply:

1.	Organization and Summary of Significant Accounting Policies	APCo, I&M, OPCo, PSO, SWEPCo
2.	Rate Matters	APCo, I&M, OPCo, PSO, SWEPCo
3.	Effects of Regulation	APCo, I&M, OPCo, PSO, SWEPCo
4.	Commitments, Guarantees and Contingencies	APCo, I&M, OPCo, PSO, SWEPCo
5.	Acquisitions and Impairments	APCo, OPCo, SWEPCo
6.	Benefit Plans	APCo, I&M, OPCo, PSO, SWEPCo
7.	Business Segments	APCo, I&M, OPCo, PSO, SWEPCo
8.	Derivatives and Hedging	APCo, I&M, OPCo, PSO, SWEPCo
9.	Fair Value Measurements	APCo, I&M, OPCo, PSO, SWEPCo
10.	Income Taxes	APCo, I&M, OPCo, PSO, SWEPCo
11.	Leases	APCo, I&M, OPCo, PSO, SWEPCo
12.	Financing Activities	APCo, I&M, OPCo, PSO, SWEPCo
13.	Related Party Transactions	APCo, I&M, OPCo, PSO, SWEPCo
14.	Variable Interest Entities	APCo, I&M, OPCo, PSO, SWEPCo
15.	Property, Plant and Equipment	APCo, I&M, OPCo, PSO, SWEPCo
16.	Cost Reduction Programs	APCo, I&M, OPCo, PSO, SWEPCo
17.	Unaudited Quarterly Financial Information	APCo, I&M, OPCo, PSO, SWEPCo

217

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

The principal business conducted by the Registrant Subsidiaries is the generation, transmission and distribution of electric power. These companies are subject to regulation 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. These companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.

The Registrant Subsidiaries also engage in wholesale electricity marketing and risk management activities in the United States. 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.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

The Registrant Subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the nine state operating territories in which they operate. The FERC also regulates the Registrant Subsidiaries’ 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 that a nonregulated affiliate can bill an affiliated public utility company 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 Registrant Subsidiaries’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when the Registrant Subsidiaries negotiate and file a cost-based contract with the FERC or the FERC determines that the Registrant Subsidiaries have “market power” in the region where the transaction occurs. The Registrant Subsidiaries have entered into wholesale power supply contracts 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. PSO’s and SWEPCo’s wholesale power transactions in the SPP region are cost-based due to the FERC’s finding that PSO and SWEPCo have market power in the SPP region.

The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrant Subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio. The ESP rates in Ohio continue the process of aligning generation/power supply rates over time with market rates.

The FERC also regulates the Registrant Subsidiaries’ wholesale transmission operations and rates. The FERC claims jurisdiction over retail transmission rates when retail rates are unbundled in connection with restructuring. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are unbundled and are based on formula rates included in the PJM OATT that are cost-based. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions.

In addition, the FERC regulates the SIA, the Interconnection Agreement, the CSW Operating Agreement, the System Transmission Integration Agreement, the Transmission Agreement, the Transmission Coordination Agreement and the AEP System Interim Allowance Agreement, all of which allocate shared system costs and revenues to the Registrant Subsidiaries that are parties to each agreement. In October 2012, the AEP East Companies asked the FERC to terminate the existing Interconnection Agreement and the AEP System Interim Allowance Agreement and approve a new Power Coordination Agreement among APCo, I&M and KPCo. A decision is expected from the FERC in mid-2013.

218

Principles of Consolidation

The consolidated financial statements for APCo include the Registrant Subsidiary and its wholly-owned subsidiaries. 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 a wholly-owned subsidiary. The consolidated financial statements for SWEPCo include the Registrant Subsidiary, a wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The Registrant Subsidiaries use the equity method of accounting for equity investments where they exercise significant influence but do not hold a controlling financial interest. Such investments are recorded as Deferred Charges and Other Noncurrent Assets on the balance sheets; equity earnings are included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. OPCo, PSO and SWEPCo have ownership interests in generating units that are jointly-owned with nonaffiliated companies. 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 14 − Variable Interest Entities.

Accounting for the Effects of Cost-Based Regulation

As rate-regulated electric public utility companies, the Registrant Subsidiaries’ 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,” the Registrant Subsidiaries record regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) 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. Due to the passage of legislation requiring restructuring and a transition to customer choice and market-based rates, OPCo applies “Regulated Operations” accounting treatment only to specifically approved portions of its generation business consisting of fuel and capacity costs.

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, 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.

Inventory

Fossil fuel inventories are carried at average cost. Materials and supplies inventories are carried at average cost.

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 Registrant Subsidiaries accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

219

AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, 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. See “Sale of Receivables – AEP Credit” section of Note 12 for additional information.

Allowance for Uncollectible Accounts

Generally, AEP Credit records bad debt expense related to receivables purchased from the Registrant Subsidiaries under a sale of receivables agreement. 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 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

The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues as of December 31, 2012.

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

The Registrant Subsidiaries in regulated jurisdictions including Ohio through December 31, 2014, record emission allowances at cost, including the annual SO2 and NOx emission allowance entitlements received at no cost from the Federal EPA. OPCo records allowances expected to be consumed subsequent to December 31, 2014 at the lower of cost or market when allowances are no longer included in the FAC due to energy auctions of SSO load. The Registrant Subsidiaries follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets. 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. Allowances held for speculation are included in Prepayments and Other Current Assets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. The net margin on sales of emission allowances is included in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates Revenues for affiliated transactions because of its integral nature to the production process of energy and the Registrant Subsidiaries’ 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 and Equity Investments

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 the original cost, 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 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 plants are included in operating expenses.

220

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. Equity investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value.

The fair value of an asset or investment is the amount at which that asset or investment 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 or investments in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Nonregulated

The generation operations of OPCo and the mining operations of SWEPCo generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations and equity investments (included in Deferred Charges and Other Noncurrent Assets) are stated at fair value at acquisition (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 (AFUDC) and Interest Capitalization

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. For nonregulated operations, including generating assets owned by OPCo and mining operations at SWEPCo, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” The Registrant Subsidiaries 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.

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 for I&M 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 AEP System’s market risk oversight staff independently monitors its valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer.

221

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 and 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 significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service 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.

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

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 revenues billed to customers over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel revenues billed to customers) 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 Registrant Subsidiaries’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. When a fuel cost disallowance becomes probable, the Registrant Subsidiaries adjust their FAC deferrals and record provisions for estimated refunds to recognize these probable outcomes.

222

Changes in fuel costs, including purchased power in Indiana and Michigan for I&M, in Ohio (beginning in 2012 through the ESP related to non-auction standard service offer load served) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO and in Virginia for APCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (beginning in 2009 through 2011) for OPCo and in West Virginia for APCo are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales. In West Virginia for APCo, all of the profits from off-system sales are given to customers through the FAC. None of the profits from off-system sales are given to customers through the FAC in Ohio for OPCo. A portion of profits 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, Virginia for APCo and in Indiana and Michigan (all areas of Michigan beginning in December 2010) 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 impacted earnings.

Revenue Recognition

Regulatory Accounting

The financial statements of the Registrant Subsidiaries 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, the Registrant Subsidiaries record them as assets on the balance sheets. The Registrant Subsidiaries test 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 Registrant Subsidiaries write off that regulatory asset as a charge against income.

Electricity Supply and Delivery Activities

The Registrant Subsidiaries recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrant Subsidiaries recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue.

Most of the power produced at the generation plants of the AEP East Companies is sold to PJM, the RTO operating in the east service territory. The AEP East Companies purchase power from PJM to supply power to their 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, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. Other RTOs in which the Registrant Subsidiaries participate do not function in the same manner as PJM. They function as balancing organizations and not as exchanges.

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 economic substance. 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 Registrant Subsidiaries record expenses when purchased electricity is received and when expenses are incurred. For certain power purchase contracts that are derivatives and accounted for using MTM accounting, OPCo records these contracts on a net basis in revenues. In other 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).

223

Energy Marketing and Risk Management Activities

AEPSC, on behalf of the Registrant Subsidiaries, engages in wholesale electricity, coal, natural gas and emission allowances marketing and risk management activities focused on wholesale 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.

The Registrant Subsidiaries recognize revenues and expenses from wholesale marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrant Subsidiaries use MTM accounting for wholesale marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or a normal purchase or sale. The Registrant Subsidiaries include realized gains and losses on wholesale marketing and risk management transactions in revenues on a net basis. For OPCo, unrealized gains and losses on wholesale marketing and risk management transactions that are accounted for using MTM are included in revenues on a net basis. For APCo, I&M, PSO and SWEPCo, who are 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 wholesale 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 Registrant Subsidiaries 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 Registrant Subsidiaries 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. For OPCo, the ineffective portion of the gain or loss is recognized in revenues or expense on the income statements immediately. APCo, I&M, PSO and SWEPCo, who are subject to cost-based regulation, defer the ineffective portion as regulatory assets (for losses) and regulatory liabilities (for gains). See “Accounting for Cash Flow Hedging Strategies” section of Note 8.

Levelization of Nuclear Refueling Outage Costs

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 Registrant Subsidiaries expense maintenance costs as incurred. If it becomes probable that the Registrant Subsidiaries 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 regulatory jurisdictions, the Registrant Subsidiaries defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.

Income Taxes and Investment Tax Credits

The Registrant Subsidiaries 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.

224

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 Registrant Subsidiaries account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrant Subsidiaries 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 Registrant Subsidiaries collect from customers certain excise taxes levied by those state or local governments on customers. The Registrant Subsidiaries do not record these taxes as revenue or expense.

Government Grants

For APCo’s commercial scale carbon capture and sequestration facility at the Mountaineer Plant and OPCo’s gridSMART® demonstration program, APCo and OPCo are reimbursed by the Department of Energy for allowable costs incurred during the billing period. In addition, AEP built a cyber security operations center that will be used to enhance the capabilities for identifying cyber risks or threats, which was also partially funded by the gridSMART® demonstration grant for OPCo’s incurred costs. These reimbursements result in the reduction of Other Operation and Maintenance expenses on the statements of income or a reduction in Construction Work in Progress on the balance sheets.

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. Some jurisdictions require that these costs be expensed upon reacquisition. The Registrant Subsidiaries report gains and losses on the reacquisition of debt for operations that are not subject to cost-based rate regulation in Interest Expense.

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.

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 trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the interest rate sensitivity 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.

225

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 investment policy for the pension fund allocates assets based on the funded status of the pension plan. The objective of the asset allocation policy is to reduce the investment volatility of the plan over time. Generally, more of the investment mix will be allocated to fixed income investments as the plan becomes better funded. Assets will be transferred away from equity investments into fixed income investments based on the market value of plan assets compared to the plan’s projected benefit obligation. The current target asset allocations are as follows:

Pension Plan Assets	Target
Equity	40.0	%
Fixed Income	50.0	%
Other Investments	10.0	%

OPEB Plans Assets	Target
Equity	66.0	%
Fixed Income	33.0	%
Cash	1.0	%

The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities. Investment policies prohibit the benefit trust funds from purchasing 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. Each investment manager's portfolio is compared to a diversified benchmark index.

For equity investments, the 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% 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, 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.

226

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 (REITs), which are publicly traded real estate securities classified as Level 1.

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 cash collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the cash collateral is invested. The difference between the rebate owed to the borrower and the cash 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.

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 (VEBA) 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

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. The trust assets may not be used for another jurisdiction’s liabilities. 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.

227

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 equity and debt 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 4 for additional discussion of nuclear matters. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 9 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).

Accumulated Other Comprehensive Income (Loss) (AOCI)

AOCI is included on the balance sheets in the equity section. Components of AOCI for the Registrant Subsidiaries as of December 31, 2012 and 2011 are shown in the following table:

	December 31,
	2012			2011
	(in thousands)
Cash Flow Hedges, Net of Tax
APCo	$	1,433		$	(285	)
I&M		(20,093	)		(15,284	)
OPCo		7,183			7,706
PSO		6,481			7,149
SWEPCo		(15,549	)		(15,524	)

Amortization of Pension and OPEB Deferred Costs, Net of Tax
APCo	$	19,118		$	15,521
I&M		4,201			3,088
OPCo		45,938			32,977
SWEPCo		4,778			4,113

Pension and OPEB Funded Status, Net of Tax
APCo	$	(50,449	)	$	(73,779	)
I&M		(12,991	)		(16,025	)
OPCo		(218,846	)		(238,405	)
SWEPCo		(7,089	)		(15,404	)

Earnings Per Share (EPS)

The Registrant Subsidiaries are wholly-owned subsidiaries of AEP. Therefore, none are required to report EPS.

OPCo Revised Depreciation Rates

Effective December 1, 2011, OPCo revised book depreciation rates for certain of OPCo’s generating plants consistent with shortened depreciable lives for the generating units. This change in depreciable lives resulted in a $52 million increase in depreciation expense in 2012.

In the fourth quarter of 2012, OPCo impaired the generating units discussed above (see Note 6). As a result of this impairment of the full book value of these assets, OPCo ceased depreciation on these generating units effective December 1, 2012.

228

2. RATE MATTERS

The Registrant Subsidiaries 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 Registrant Subsidiaries' recent significant rate orders and pending rate filings are addressed in this note.

OPCo Rate Matters

Ohio Electric Security Plan Filing

2009 – 2011 ESP

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

In October 2011, the PUCO issued an order in the remand proceeding. As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011. In February 2012, the Ohio Consumers’ Counsel and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance. As of December 31, 2012, OPCo’s net deferred fuel balance was $519 million, excluding unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending.

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

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

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

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

January 2012 – May 2016 ESP as Rejected by the PUCO

In December 2011, the PUCO approved an ESP modified stipulation which established a SSO pricing for generation. Various parties filed for rehearing with the PUCO requesting that the PUCO reconsider adoption of the modified stipulation. In February 2012, the PUCO issued an entry on rehearing which rejected the modified stipulation and ordered a return to the 2011 ESP rates. Those rates remained in effect until the new ESP was approved in August 2012. See the “June 2012 – May 2015 ESP Including Capacity Charge” section below.

229

As a result of the PUCO’s rejection of the modified stipulation, OPCo reversed a $35 million obligation to contribute to the Partnership with Ohio and the Ohio Growth Fund and an $8 million regulatory asset for 2011 storm damage, both originally recorded in 2011.

As directed by the February 2012 order, OPCo filed revised tariffs with the PUCO to implement the provisions of the 2011 ESP. Included in the revised tariffs was the Phase-In Recovery Rider (PIRR) to recover deferred fuel costs as authorized under the 2009 – 2011 ESP order. In March 2012, the PUCO issued an order that directed OPCo to file new revised tariffs removing the PIRR and stated that its recovery would be addressed in a future proceeding. OPCo implemented the new revised tariffs in March 2012. In March 2012, OPCo resumed recording a weighted average cost of capital return on the deferred fuel balance in accordance with the 2009 - 2011 ESP order. OPCo also filed a request for rehearing of the March 2012 order relating to the PIRR, which the PUCO denied but provided that all of the substantive concerns and issues raised would be addressed in a separate PIRR docket.

In August 2012, the PUCO ordered implementation of PIRR 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. The August 2012 order was upheld on rehearing by the PUCO in October 2012. In November 2012, OPCo filed an appeal at the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated ESP order, which granted a weighted average cost of capital rate. The IEU and the Ohio Consumers’ Counsel also filed appeals at the Supreme Court of Ohio in November 2012 arguing that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues and reduced carrying costs due to an accumulated deferred income tax credit. See the “2009 – 2011 ESP” section above. These appeals could reduce OPCo’s net deferred fuel balance up to the total balance, which would reduce future net income and cash flows. A decision from the Supreme Court of Ohio is pending.

June 2012 – May 2015 ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015, adopted a 12% earnings threshold for the SEET and allowed the continuation of the fuel adjustment clause. Further, the ESP established a non-bypassable Distribution Investment Rider effective September 2012 through May 2015 to recover, with certain caps, post-August 2010 distribution investment. The ESP also maintained recovery of several previous ESP riders and required OPCo to contribute $2 million per year during the ESP to the Ohio Growth Fund. In addition, the PUCO approved a storm damage recovery mechanism.

As part of the August 2012 PUCO ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012. The RSR is intended to provide approximately $500 million over the ESP period and will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the deferred capacity costs. As of December 31, 2012, OPCo recorded $66 million of incurred deferred capacity costs, including debt carrying costs, in Regulatory Assets on the balance sheet. In August 2012, the IEU filed an action with the Supreme Court of Ohio stating, among other things, that OPCo’s collection of its capacity costs is illegal. In September 2012, OPCo and the PUCO filed motions to dismiss the IEU’s action. If OPCo is ultimately not permitted to fully collect its deferred capacity costs, it would reduce future net income and cash flows and impact financial condition. A decision from the Supreme Court of Ohio is pending.

230

In January 2013, the PUCO issued its Order on Rehearing for the ESP which generally upheld its August 2012 order including the implementation of the RSR. The PUCO clarified that a final reconciliation of revenues and costs would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket. If OPCo is ultimately not permitted to fully collect its ESP rates, including the RSR, it would reduce future net income and cash flows and impact financial condition.

Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets at net book value to AEPGenCo. AEPGenCo will also assume the associated generation liabilities. In December 2012, the PUCO granted the IEU and Ohio Consumers’ Counsel requests for rehearing for the purpose of further consideration and those requests remain pending.

Also in October 2012, filings at the FERC were submitted related to corporate separation. See the “Corporate Separation and Termination of Interconnection Agreement” section below under FERC Rate Matters.

2011 Ohio Distribution Base Rate Case

In December 2011, the PUCO approved a stipulation which provided for no change in distribution rates and a new rider for a $15 million annual credit to residential ratepayers due principally to the inclusion of the rate base distribution investment in the Distribution Investment Rider (DIR) as approved in December 2011 by the modified stipulation in the ESP proceeding. However, when the February 2012 PUCO order rejected the ESP modified stipulation, collection of the DIR terminated. In August 2012, the PUCO approved a new DIR as part of the June 2012 – May 2015 ESP proceeding. The DIR is capped at $86 million in 2012, $104 million in 2013, $124 million in 2014 and $52 million for the period January through May 2015, for a total of $366 million.

Storm Damage Recovery Rider (SDRR)

In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates. The SDRR seeks recovery of 2012 incremental storm distribution expenses over twelve months starting with the effective date of the SDRR as approved by the PUCO. If the PUCO extends recovery beyond twelve months and/or does not commence cost recovery by April 2013, OPCo requested approval of a weighted average cost of capital carrying charge, effective April 2013. As of December 31, 2012, OPCo recorded $62 million in Regulatory Assets on the balance sheet related to 2012 storm damage. If OPCo is not ultimately permitted to recover these storm costs, it would reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

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

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

231

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes. As of December 31, 2012, the amount of OPCo’s carrying costs that could potentially be reduced due to the accumulated income tax issue is estimated to be approximately $36 million, including $19 million of unrecognized equity carrying costs. These amounts include the carrying costs exposure of the 2009 FAC audit, which has been appealed by an intervenor to the Supreme Court of Ohio. Decisions from the PUCO are pending. Management is unable to predict the outcome of these proceedings. If the PUCO orders result in a reduction to the FAC deferral, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet. This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009. In March 2009, the PUCO approved a FAC in the ESP filing and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio. The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record a regulatory asset for the difference between the approved market price and the rate paid by Ormet. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. In November 2009, OPCo requested that the PUCO approve recovery of the deferral under the interim agreement plus a weighted average cost of capital carrying charge. The deferral amount is included in OPCo’s FAC phase-in deferral balance. In the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related regulatory asset and requested that the PUCO prevent OPCo from collecting the Ormet-related revenues in the future. The PUCO did not take any action on this request. The intervenors raised the issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. This issue remains pending before the PUCO. If OPCo is not ultimately permitted to fully recover its requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Special Rate Mechanism for Ormet

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

Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. As of December 31, 2012, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting all collected pre-construction costs be refunded to Ohio ratepayers with interest.

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

232

SWEPCo Rate Matters

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the completed facility. As of December 31, 2012, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital costs cap, SWEPCo has capitalized approximately $1.7 billion of expenditures, including AFUDC and capitalized interest of $328 million and related transmission costs of $120 million.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the 88 MW SWEPCo Arkansas jurisdictional share of the Turk Plant. 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 the Arkansas Supreme Court’s decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the SPP market.

The PUCT approved a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers. SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful. The Texas Industrial Energy Consumers (TIEC) filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers. The Texas District Court and the Texas Court of Appeals affirmed the PUCT’s order in all respects. In April 2012, SWEPCo and TIEC filed petitions for review at the Supreme Court of Texas. The Supreme Court of Texas has requested full briefing from the parties.

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

2012 Texas Base Rate Case

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

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

In December 2012, several intervenors, including the PUCT staff, filed testimony that recommended an annual base rate increase between $16 million and $51 million based upon a return on common equity between 9.0% and 9.55%. In addition, two intervenors recommended that the Turk Plant be excluded from rate base. A decision from the PUCT is expected in the second quarter of 2013. If the PUCT does not approve full cost recovery of SWEPCo’s assets, it would reduce future net income and cash flows and impact financial condition.

233

Louisiana 2012 Formula Rate Filing

Flint Creek Plant Environmental Controls

Louisiana 2010 Formula Rate Filing

In April 2010, SWEPCo filed its formula rate plan (FRP) which decreased annual Louisiana retail rates by $3 million effective August 2010, subject to refund. A settlement agreement was reached by the parties and orally approved by the LPSC in September 2012. A reserve recorded in the second quarter of 2012 was increased by an immaterial amount to cover the $3 million refund approved by the LPSC in the settlement agreement. The refund began in October 2012 and will occur over a twelve-month period.

APCo Rate Matters

Plant Transfers

In October 2012, the AEP East Companies submitted several filings with the FERC. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant, comprising 1,647 MW of average annual generating capacity presently owned by OPCo. Hearings at the Virginia SCC and the WVPSC are scheduled for April 2013 and July 2013, respectively. If the transfers are approved, APCo and WPCo anticipate seeking cost recovery when they file their next base rate cases.

Virginia Fuel Filing

In April 2012, APCo filed an application with the Virginia SCC for an annual increase in fuel revenues of $117 million to be effective June 2012. The filing included forecasted costs for the 15-month period ended August 2013 and requested recovery of APCo's anticipated unrecovered fuel balance as of May 2012 over a two-year period commencing in June 2012. The non-incremental portion of APCo's forecasted and deferred wind purchased power costs were reflected in APCo's filing. In June 2012, the Virginia SCC approved the application as filed.

234

Environmental Rate Adjustment Clause (Environmental RAC)

In November 2011, the Virginia SCC issued an order which approved APCo’s Environmental RAC recovery of $30 million to be collected over one year beginning in February 2012 but denied recovery of certain environmental costs. As a result, in 2011, APCo recorded a pretax write-off of $31 million on the statement of income related to environmental compliance costs incurred from January 2009 through December 2010. APCo appealed the Virginia SCC decision to the Supreme Court of Virginia. In November 2012, the Supreme Court of Virginia issued an order which allowed APCo to recover an additional $6 million of 2009 and 2010 actual Environmental RAC costs and affirmed the portion of the November 2011 order that denied recovery of certain environmental costs. The Virginia SCC issued an order in December 2012 which permitted APCo to extend the current Environmental RAC surcharge for the months of February and March 2013 in order to collect the $6 million.

Generation Rate Adjustment Clause (Generation RAC)

In January 2012, the Virginia SCC issued a Generation RAC order which allowed APCo to recover $26 million annually, effective March 2012, related to recovery of the Dresden Plant. APCo filed with the Virginia SCC to continue the current Generation RAC rate to recover costs of the Dresden Plant through February 2014. In December 2012, the Virginia SCC granted APCo’s application as filed and required APCo to submit a new Generation RAC filing in March 2013.

APCo IGCC Plant

As of December 31, 2012, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction. If the costs are not recoverable, it would reduce future net income and cash flows and impact financial condition.

APCo’s and WPCo’s Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation, which allows the WVPSC to establish a regulatory framework to securitize certain deferred ENEC balances and other ENEC related assets. Also in March 2012, APCo and WPCo filed their ENEC application with the WVPSC for the fourth year of a four-year phase-in plan which requested no change in ENEC rates if the WVPSC issues a financing order allowing securitization of the under-recovered ENEC deferral and other ENEC-related assets. If the financing order is not issued, APCo and WPCo requested that recovery of these costs be allowed in current rates.

In July 2012, the WVPSC issued an order that approved a settlement agreement which recommended no change in total ENEC rates but reflected a $24 million increase in the construction surcharge and a $24 million decrease in ENEC rates. In August 2012, APCo and WPCo filed with the WVPSC a request for a financing order to securitize a total of $422 million related to the December 2011 under-recovered ENEC deferral balance including other ENEC-related assets of $13 million and related future financing costs of $7 million. Upon completion of the securitization, APCo would offset its current ENEC rates by an amount to recover the securitized balance over the securitization period. In January 2013, intervenors filed testimony that recommended securitization of approximately $370 million. The differences between APCo’s and WPCo’s request and the intervenors’ testimony represent previously approved ENEC-related deferred amounts being recovered in the ENEC over extended periods, various amounts deferred subsequent to the 2011 securitization period and related future securitization financing costs. As of December 31, 2012, APCo’s ENEC under-recovery balance of $299 million, net of 2012 over-recovery, was recorded in Regulatory Assets on the balance sheet, excluding $4 million of unrecognized equity carrying costs and $12 million of other ENEC-related assets. APCo and WPCo are currently in settlement discussions with intervenors.

WPCo Merger with APCo

235

PSO Rate Matters

PSO 2008 Fuel and Purchased Power

In 2009, the OCC initiated a proceeding to review PSO’s fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudence review of the related costs. In October 2012, the OCC issued a final order that found PSO’s fuel and purchased power costs were prudently incurred without any disallowance and that PSO’s shareholder’s portion of off-system sales margins would remain at 25%.

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES) Unit 4 in 2016 and additional environmental controls on NES Unit 3 to continue operations through 2026. The plan requested approval for (a) cost recovery through base rates by 2026 of an estimated $256 million of new environmental investment that will be incurred prior to 2016 at NES Unit 3, (b) cost recovery through 2026 of NES Units 3 and 4 net book value (combined net book value of the two units is $234 million as of December 31, 2012), (c) cost recovery through base rates of an estimated $83 million of new investment incurred through 2016 at various gas units and (d) a new 15-year purchase power agreement (PPA) with a nonaffiliated entity, effective in 2016, with cost recovery through a rider, including an annual earnings component of $3 million. Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery when filing its next base rate case, which is expected to occur no later than 2014.

In January 2013, testimony filed by the OCC staff and the Oklahoma Office of the Attorney General generally agreed with PSO’s plan, although they recommended no earnings component on the PPA and to delay final decisions on parts of the plan including cost recovery of NES Unit 3 and any increases in fuel costs due to reductions in the output of energy from NES Unit 3 beginning in 2021. The testimony recommended that cost recovery could extend past 2026 on parts of the plan and recommended a $175 million cost cap on NES Unit 3 environmental investment.

Also, an intervenor representing some of PSO’s large industrial users opposed virtually all of PSO’s plan, including recommending no cost recovery of NES Units 3 and 4 book value amounts not recovered at the time of their retirement and no recovery of the PPA costs, including earnings on the PPA. A hearing is scheduled for April 2013.

I&M Rate Matters

2011 Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on common equity of 11.15%. The $149 million net annual increase reflects an increase in base rates of $178 million offset by proposed corresponding reductions of $13 million to the off-system sales sharing rider, $9 million to the PJM cost rider and $7 million to the clean coal technology rider rates. The request included an increase in depreciation rates that would result in an increase of approximately $25 million in annual depreciation expense. Included in the depreciation rates increase was a decrease in the average remaining life of Tanners Creek Plant to account for the change in the retirement date of Tanners Creek Plant, Units 1-3 from 2020 to 2014. In May 2012, I&M filed rebuttal testimony which changed the retirement date for Tanners Creek Plant, Units 1-3 to 2015 and supported an increase of $170 million in base rates, excluding reductions to certain riders.

236

Cook Plant Life Cycle Management Project

In Indiana, I&M requested recovery of certain project costs, including interest, through a new rider effective January 2013. In Michigan, I&M requested that the MPSC approve a Certificate of Need and authorize I&M to defer, on an interim basis, incremental depreciation and related property tax costs, including interest, along with study, analysis and development costs until the applicable LCM costs are included in I&M’s base rates. As of December 31, 2012, I&M has incurred $176 million related to the LCM Project, including AFUDC.

In August 2012, intervenors filed testimony in Indiana. The Indiana Michigan Power Company Industrial Group recommended that I&M recover $229 million in a rider with the remaining costs to be requested in future base rate cases. The Indiana Office of Utility Consumer Counselor (OUCC) recommended a maximum of $408 million of LCM project costs be recovered in a rider, and a maximum of $299 million for projects the OUCC believes are not related to LCM to be recovered in future base rates. The IURC held a hearing in January 2013.

If I&M is not ultimately permitted to recover its LCM Project costs, it would reduce future net income and cash flows and impact financial condition.

Rockport Plant Environmental Controls

In February 2013, I&M filed a motion with the IURC to dismiss its request for approval of a CPCN for environmental controls after modification to the NSR consent decree. Under the terms of the NSR consent decree modification, the units of Rockport Plant will be equipped with dry sorbent injection systems in 2015 and have options to retrofit additional SO2 controls, refuel, repower or retire in 2025 and 2028.

237

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund – Affecting APCo, I&M and OPCo

In 2004, AEP eliminated transaction-based through-and-out transmission service charges and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA through March 2006. Intervenors objected and the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund. The AEP East Companies recognized gross SECA revenues of $220 million. APCo’s, I&M’s and OPCo’s portions of recognized gross SECA revenues are as follows:

Company	(in millions)
APCo	$	70.2
I&M		41.3
OPCo		92.1

In 2006, a FERC Administrative Law Judge issued an initial decision finding that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.

AEP filed briefs jointly with other affected companies asking the FERC to reverse the decision. In May 2010, the FERC issued an order that generally supported AEP’s position and required a compliance filing. In August 2010, the affected companies, including the AEP East Companies, filed a compliance filing with the FERC. The AEP East Companies provided reserves for net refunds for SECA settlements. The AEP East Companies settled with various parties prior to the FERC compliance filing and entered into additional settlements subsequent to the compliance filing being filed at the FERC. Based on the analysis of the May 2010 order, the compliance filing and recent settlements, management believes that the reserve is adequate to pay the refunds, including interest, and any remaining exposure beyond the reserve is immaterial.

Corporate Separation and Termination of Interconnection Agreement – Affecting APCo, I&M and OPCo

In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations. The filings requested approval to transfer at net book value approximately 9,200 MW of OPCo-owned generation assets to a new wholly-owned company, AEPGenCo. The AEP East Companies also requested FERC approval to transfer at net book value OPCo’s current two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer at net book value OPCo’s Mitchell Plant to APCo and KPCo in equal one-half interests (780 MW each). Additionally, the AEP East Companies asked the FERC to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement among APCo, I&M and KPCo. Intervenors have opposed several of these filings. The AEP East Companies have responded and continue to pursue approvals from the FERC. A decision from the FERC is expected in mid-2013. Similar filings have been made at the Virginia SCC and the WVPSC. See the “Plant Transfers” section of APCo Rate Matters.

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

238

3. EFFECTS OF REGULATION

Regulatory assets and liabilities are comprised of the following items:

	APCo					I&M
					Remaining					Remaining
	December 31,				Recovery	December 31,				Recovery
Regulatory Assets:	2012		2011		Period	2012		2011		Period
	(in thousands)					(in thousands)
Current Regulatory Assets
Under-recovered Fuel Costs - earns a return	$	74,906	$	41,105	1 year	$	3,029	$	-	1 year
Under-recovered Fuel Costs - does not earn a return		-		-			1,647		8,876	1 year
Total Current Regulatory Assets	$	74,906	$	41,105		$	4,676	$	8,876

Noncurrent Regulatory Assets
Regulatory assets not yet being recovered pending
future proceedings to determine the recovery
method and timing:

Regulatory Assets Currently Not Earning a Return
Storm Related Costs	$	94,458	$	-		$	-	$	-
Virginia Environmental Rate Adjustment Clause		29,320		17,950			-		-
Mountaineer Carbon Capture and Storage
Product Validation Facility		14,155		14,155			-		-
Dresden Plant Operating Costs		8,758		-			-		-
Deferred Wind Power Costs		5,143		38,192			-		-
Transmission Agreement Phase-In		2,992		1,925			-		-
Mountaineer Carbon Capture and Storage
Commercial Scale Facility		1,287		1,335			1,380		1,680
Special Rate Mechanism for Century Aluminum		-		12,811			-		-
Litigation Settlement		-		-			11,098		10,803
Other Regulatory Assets Not Yet Being Recovered		1,447		1,010			786		-
Total Regulatory Assets Not Yet Being Recovered		157,560		87,378			13,264		12,483

Regulatory assets being recovered:

Regulatory Assets Currently Earning a Return
West Virginia Expanded Net Energy Charge		272,783		326,766	(a)		-		-
Storm Related Costs		21,371		25,225	6 years		-		-
Unamortized Loss on Reacquired Debt		12,969		13,592	30 years		15,871		17,355	20 years
RTO Formation/Integration Costs		4,370		5,194	7 years		3,229		3,858	7 years
Customer Choice Implementation Costs		-		-			1,493		4,680	1 year
Regulatory Assets Currently Not Earning a Return
Income Taxes, Net		525,549		512,025	26 years		222,252		188,749	36 years
Pension and OPEB Funded Status		312,645		362,322	12 years		220,797		291,392	12 years
Virginia Transmission Rate Adjustment Clause		32,992		19,553	2 years		-		-
West Virginia Expanded Net Energy Charge		25,932		31,979	(a)		-		-
Postemployment Benefits		22,663		22,645	5 years		8,897		9,137	5 years
Storm Related Costs		13,712		16,324	6 years		-		-
Deferred Restructuring Costs		10,531		12,537	6 years		3,688		4,952	3 years
Asset Retirement Obligation		8,489		10,524	5 years		808		3,396	8 years
Virginia Environmental Rate Adjustment Clause		8,347		23,844	1 year		-		-
Virginia Generation Rate Adjustment Clause		3,469		-	1 year		-		-
Deferred Wind Power Costs		915		6,284	1 year		-		-
Virginia Environmental and Reliability Costs		560		3,838	1 year		-		-
Cook Nuclear Plant Refueling Outage Levelization		-		-			26,652		40,551	3 years
Deferred PJM Fees		-		-			13,998		21,746	2 years
River Transportation Division Expenses		-		-			4,576		1,899	1 year
Peak Demand Reduction/Energy Efficiency		-		-			2,608		1,387	1 year
Other Regulatory Assets Being Recovered		847		1,163	various		1,886		1,394	various
Total Regulatory Assets Being Recovered		1,278,144		1,393,815			526,755		590,496

Total Noncurrent Regulatory Assets	$	1,435,704	$	1,481,193		$	540,019	$	602,979

(a) Request for securitization is pending from the WVPSC to recover $422 million as securitized transition assets from ratepayers over the securitization bond period.

239

	APCo					I&M
					Remaining					Remaining
	December 31,				Refund	December 31,				Refund
Regulatory Liabilities:	2012		2011		Period	2012		2011		Period
	(in thousands)					(in thousands)
Current Regulatory Liabilities
Over-recovered Fuel Costs - pays a return	$	-	$	-		$	-	$	25
Total Current Regulatory Liabilities	$	-	$	-		$	-	$	25

Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits
Regulatory liabilities not yet being paid:

Regulatory Liabilities Currently Paying a Return
Other Regulatory Liabilities Not Yet Being Paid	$	-	$	-		$	-	$	318
Regulatory Liabilities Currently Not Paying a Return
Other Regulatory Liabilities Not Yet Being Paid		249		327			124		136
Total Regulatory Liabilities Not Yet Being Paid		249		327			124		454

Regulatory liabilities being paid:

Regulatory Liabilities Currently Paying a Return
Asset Removal Costs		552,590		526,885	(a)		381,116		362,134	(a)
Deferred Investment Tax Credits		2,823		3,231	48 years		-		-
Regulatory Liabilities Currently Not Paying a Return
Deferred State Income Tax Coal Credits		29,296		28,727	10 years		-		-
Unrealized Gain on Forward Commitments		21,433		15,597	5 years		19,872		21,785	5 years
Deferred Investment Tax Credits		382		1,214	3 years		48,130		52,633	25 years
Peak Demand Reduction/Energy Efficiency		907		811	1 year		11,080		11,078	1 year
Excess Asset Retirement Obligations for Nuclear
Decommissioning Liability		-		-			435,717		377,162	(b)
Spent Nuclear Fuel Liability		-		-			42,898		42,603	(b)
Off-system Sales Margin Sharing		-		-			7,611		5,892	1 year
Indiana Clean Coal Technology Rider		-		-			774		1,242	1 year
Other Regulatory Liabilities Being Paid		-		-			970		219	various
Total Regulatory Liabilities Being Paid		607,431		576,465			948,168		874,748

Total Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits	$	607,680	$	576,792		$	948,292	$	875,202

(a) Relieved as removal costs are incurred.
(b) Relieved when plant is decommissioned.

240

	OPCo
					Remaining
	December 31,				Recovery
	2012		2011		Period
Regulatory Assets:	(in thousands)

Noncurrent Regulatory Assets
Regulatory assets not yet being recovered pending future proceedings to
determine the recovery method and timing:

Regulatory Assets Currently Earning a Return
Economic Development Rider	$	13,213	$	12,572
Regulatory Assets Currently Not Earning a Return
Storm Related Costs		61,828		8,375
Ormet Delayed Payment Arrangement		5,453		-
Other Regulatory Assets Not Yet Being Recovered		30		-
Total Regulatory Assets Not Yet Being Recovered		80,524		20,947

Regulatory assets being recovered:

Regulatory Assets Currently Earning a Return
Ohio Fuel Adjustment Clause		518,595		506,607	6 years
Ohio Deferred Asset Recovery Rider		152,039		173,274	6 years
Ohio Capacity Deferral		65,818		-	6 years
Transmission Cost Recovery Rider		49,391		28,404	3 years
Unamortized Loss on Reacquired Debt		13,215		14,552	26 years
RTO Formation/Integration Costs		6,594		7,836	7 years
Economic Development Rider		5,488		11,738	1 year
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status		309,685		389,712	12 years
Income Taxes, Net		190,685		190,981	21 years
Distribution Decoupling		16,198		-	2 years
Postemployment Benefits		7,658		8,669	5 years
Partnership with Ohio Contribution		2,405		3,400	3 years
Distribution Investment Rider		1,304		-	1 year
Unrealized Loss on Forward Commitments		810		9,930	1 year
Enhanced Service Reliability Plan		557		4,454	1 year
Total Regulatory Assets Being Recovered		1,340,442		1,349,557

Total Noncurrent Regulatory Assets	$	1,420,966	$	1,370,504

241

	OPCo
					Remaining
	December 31,				Refund
	2012		2011		Period
Regulatory Liabilities:	(in thousands)

Current Regulatory Liabilities
Over-recovered Fuel Costs - does not pay a return	$	14,848	$	-	1 year
Total Current Regulatory Liabilities	$	14,848	$	-

Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities not yet being paid:

Regulatory Liabilities Currently Paying a Return
IGCC Preconstruction Costs	$	4,411	$	4,196
Regulatory Liabilities Currently Not Paying a Return
Other Regulatory Liabilities Not Yet Being Paid		216		216
Total Regulatory Liabilities Not Yet Being Paid		4,627		4,412

Regulatory liabilities being paid:

Regulatory Liabilities Currently Paying a Return
Asset Removal Costs		416,461		251,100	(a)
Deferred Investment Tax Credits		322		549	9 years
Economic Development Rider		-		2,428
Transmission Cost Recovery Rider		-		542
Regulatory Liabilities Currently Not Paying a Return
Peak Demand Reduction/Energy Efficiency		12,596		19,124	2 years
Deferred Investment Tax Credits		11,321		12,944	12 years
Over-recovery of Costs Related to gridSMART®		3,501		7,504	2 years
Low Income Customers/Economic Recovery		2,243		2,521	3 years
Total Regulatory Liabilities Being Paid		446,444		296,712

Total Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits	$	451,071	$	301,124

(a) Relieved as removal costs are incurred.

242

	PSO					SWEPCo
					Remaining					Remaining
	December 31,				Recovery	December 31,				Recovery
	2012		2011		Period	2012		2011		Period
Regulatory Assets:	(in thousands)					(in thousands)

Current Regulatory Assets
Under-recovered Fuel Costs - earns a return	$	-	$	4,313		$	8,527	$	10,843	1 year
Total Current Regulatory Assets	$	-	$	4,313		$	8,527	$	10,843

Noncurrent Regulatory Assets
Regulatory assets not yet being recovered pending
future proceedings to determine the recovery
method and timing:

Regulatory Assets Currently Not Earning a Return
Rate Case Expense	$	-	$	-		$	4,517	$	-
Mountaineer Carbon Capture and Storage
Commercial Scale Facility		-		-			2,295		2,380
Other Regulatory Assets Not Yet Being Recovered		423		-			2,188		1,699
Total Regulatory Assets Not Yet Being Recovered		423		-			9,000		4,079

Regulatory assets being recovered:

Regulatory Assets Currently Earning a Return
Storm Related Costs		14,172		38,659	1 year		337		965	1 year
Unamortized Loss on Reacquired Debt		10,923		12,538	20 years		9,379		10,768	31 years
Red Rock Generating Facility		9,954		10,180	44 years		-		-
Acquisition of Valley Electric Membership
Corporation (VEMCO)		-		-			6,443		8,789	3 years
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status		133,404		178,295	12 years		143,226		176,587	12 years
Vegetation Management		13,388		11,196	1 year		-		-
Peak Demand Reduction/Energy Efficiency		6,248		4,394	1 year		1,467		1,284	1 year
Unrealized Loss on Forward Commitments		5,347		1,706	1 year		427		4,684	1 year
Deferral of Major Generation Overhauls		4,533		6,133	5 years		-		-
Income Taxes, Net		3,785		2,923	34 years		230,220		178,826	40 years
Rate Case Expense		-		216			1,168		3,602	1 year
Dolet Hills Deferred Fuel		-		-			1,048		1,886	2 years
Storm Related Costs		-		-			400		2,556	1 year
Other Regulatory Assets Being Recovered		151		305	various		163		250	various
Total Regulatory Assets Being Recovered		201,905		266,545			394,278		390,197

Total Noncurrent Regulatory Assets	$	202,328	$	266,545		$	403,278	$	394,276

243

	PSO					SWEPCo
					Remaining					Remaining
	December 31,				Refund	December 31,				Refund
	2012		2011		Period	2012		2011		Period
Regulatory Liabilities:	(in thousands)					(in thousands)

Current Regulatory Liabilities
Over-recovered Fuel Costs - pays a return	$	7,945	$	-	1 year	$	16,761	$	5,032	1 year
Total Current Regulatory Liabilities	$	7,945	$	-		$	16,761	$	5,032

Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits
Regulatory liabilities not yet being paid:

Regulatory Liabilities Currently Paying a Return
Louisiana Refundable Construction Financing Costs	$	-	$	-		$	96,094	$	52,594
Regulatory Liabilities Currently Not Paying a Return
Over-recovery of Costs Related to gridSMART®		3,964		4,232			-		-
Storm Related Costs		3,207		2,248			-		-
Other Regulatory Liabilities Not Yet Being Paid		1,613		-			-		806
Total Regulatory Liabilities Not Yet Being Paid		8,784		6,480			96,094		53,400

Regulatory liabilities being paid:

Regulatory Liabilities Currently Paying a Return
Asset Removal Costs		280,446		280,491	(a)		362,838		353,067	(a)
Excess Earnings		-		-			2,975		3,047	41 years
Other Regulatory Liabilities Being Paid		-		-			838		1,305	various
Regulatory Liabilities Currently Not Paying a Return
Deferred Investment Tax Credits		42,345		40,310	36 years		12,769		13,318	26 years
Base Load Purchase Power Contract		8,484		-	1 year		-		-
Peak Demand Reduction/Energy Efficiency		2,915		6,444	1 year		-		-
Vegetation Management		-		-			130		3,158	1 year
Other Regulatory Liabilities Being Paid		1,843		1,087	various		827		1,276	various
Total Regulatory Liabilities Being Paid		336,033		328,332			380,377		375,171

Total Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits	$	344,817	$	334,812		$	476,471	$	428,571

(a) Relieved as removal costs are incurred.

4. COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements.

COMMITMENTS

Construction and Commitments – Affecting APCo, I&M, OPCo, PSO and SWEPCo

The Registrant Subsidiaries have substantial construction commitments to support their operations and environmental investments. In managing the overall construction program and in the normal course of business, the Registrant Subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. The following table shows the forecasted construction expenditures, excluding equity AFUDC and capitalized interest, by Registrant Subsidiary for 2013:

	Forecasted
	Construction
Company	Expenditures
	(in millions)
APCo	$	370
I&M		484
OPCo		617
PSO		295
SWEPCo		398

244

The Registrant Subsidiaries also purchase fuel, materials, supplies, services and property, plant and equipment under contract as part of their normal course of business. Certain supply contracts contain penalty provisions for early termination.

The following tables summarize the Registrant Subsidiaries’ actual contractual commitments as of December 31, 2012:

	Less Than 1						After
Contractual Commitments - APCo	Year		2-3 Years		4-5 Years		5 Years		Total
	(in thousands)
Fuel Purchase Contracts (a)	$	611,664	$	711,277	$	544,598	$	553,315	$	2,420,854
Energy and Capacity Purchase Contracts (b)		32,293		66,034		67,882		586,336		752,545
Construction Contracts for Capital Assets (c)		13,094		-		-		-		13,094
Total	$	657,051	$	777,311	$	612,480	$	1,139,651	$	3,186,493

	Less Than 1						After
Contractual Commitments - I&M	Year		2-3 Years		4-5 Years		5 Years		Total
	(in thousands)
Fuel Purchase Contracts (a)	$	330,157	$	535,223	$	336,830	$	447,930	$	1,650,140
Energy and Capacity Purchase Contracts (b)		89,128		178,501		178,543		609,371		1,055,543
Construction Contracts for Capital Assets (c)		6,389		-		-		-		6,389
Total	$	425,674	$	713,724	$	515,373	$	1,057,301	$	2,712,072

	Less Than 1						After
Contractual Commitments - OPCo	Year		2-3 Years		4-5 Years		5 Years		Total
	(in thousands)
Fuel Purchase Contracts (a)	$	1,167,631	$	2,012,580	$	1,542,218	$	1,368,019	$	6,090,448
Energy and Capacity Purchase Contracts (b)		45,009		91,997		94,290		920,573		1,151,869
Construction Contracts for Capital Assets (c)		22,407		-		-		-		22,407
Total	$	1,235,047	$	2,104,577	$	1,636,508	$	2,288,592	$	7,264,724

	Less Than 1						After
Contractual Commitments - PSO	Year		2-3 Years		4-5 Years		5 Years		Total
	(in thousands)
Fuel Purchase Contracts (a)	$	119,855	$	140,535	$	113,035	$	197,788	$	571,213
Energy and Capacity Purchase Contracts (b)		69,216		141,389		145,439		528,899		884,943
Construction Contracts for Capital Assets (c)		9,554		-		-		-		9,554
Total	$	198,625	$	281,924	$	258,474	$	726,687	$	1,465,710

	Less Than 1						After
Contractual Commitments - SWEPCo	Year		2-3 Years		4-5 Years		5 Years		Total
	(in thousands)
Fuel Purchase Contracts (a)	$	296,426	$	487,711	$	316,753	$	340,969	$	1,441,859
Energy and Capacity Purchase Contracts (b)		19,714		39,252		40,656		244,199		343,821
Construction Contracts for Capital Assets (c)		21,898		-		-		-		21,898
Total	$	338,038	$	526,963	$	357,409	$	585,168	$	1,807,578

(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 contractual commitments for energy and capacity purchase contracts.

(c)

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 projects costs.

245

GUARANTEES

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

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

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

AEP has two credit facilities totaling $3.25 billion, under which up to $1.35 billion may be issued as letters of credit. In February 2013, AEP increased and extended the $1.5 billion credit facility due in June 2015 to $1.75 billion due in June 2016, extended the $1.75 billion credit facility due in July 2016 to July 2017 and issued a $1 billion interim credit facility due in May 2015 to fund certain OPCo maturities. As of December 31, 2012, the maximum future payments for letters of credit issued under the credit facilities were as follows:

Company	Amount		Maturity
(in thousands)
I&M	$	150	March 2013
OPCo		2,102	June 2013
SWEPCo		4,448	March 2013

The Registrant Subsidiaries have $357 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $361 million detailed in the table below. In February 2013, APCo and I&M extended certain bilateral letters of credit due in March 2013 to March 2015, while OPCo extended its bilateral letter of credit due in March 2013 to July 2014.

				Bilateral		Maturity of
	Pollution			Letters		Bilateral Letters
Company	Control Bonds			of Credit		of Credit
	(in thousands)
APCo		$	229,650	$	232,293	March 2013 to March 2014
I&M			77,000		77,886	March 2013
OPCo			50,000		50,575	March 2013

Guarantees of Third-Party Obligations – Affecting SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million. As of December 31, 2012, SWEPCo has collected approximately $59 million through a rider for final mine closure and reclamation costs, of which $18 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $41 million is recorded in Asset Retirement Obligations on SWEPCo’s balance sheets.

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

246

Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 2012, there were no material liabilities recorded for any indemnifications.

APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East Companies related to power purchase and sale activity pursuant to the SIA. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA.

Lease Obligations

Certain Registrant Subsidiaries lease certain equipment under master lease agreements. See “Master Lease Agreements” and “Railcar Lease” sections of Note 11 for disclosure of lease residual value guarantees.

ENVIRONMENTAL CONTINGENCIES

Carbon Dioxide Public Nuisance Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision. The petition was denied in January 2011. Plaintiffs refiled their complaint in federal district court. The court ordered all defendants to respond to the refiled complaints in October 2011. In March 2012, the court granted the defendants’ motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations. Plaintiffs appealed the decision to the Fifth Circuit Court of Appeals. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Alaskan Villages’ Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million. In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim. The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court. The plaintiffs appealed the decision. In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court’s decision, holding that the CAA displaced Kivalina’s claims for damages. Plaintiffs’ petition for rehearing by the full court was denied in November 2012, but the plaintiffs could seek further review in the U.S. Supreme Court. Management believes the action is without merit and will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

247

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting APCo, I&M, OPCo, PSO and SWEPCo

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

Superfund addresses clean-up of hazardous substances that have been released to the environment. The Federal EPA administers the clean-up programs. Several states have enacted similar laws. As of December 31, 2012, APCo is named as a Potentially Responsible Party (PRP) for two site and OPCo is named a PRP for three sites by the Federal EPA. There are seven additional sites for which APCo, I&M, OPCo, and SWEPCo have 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 the Registrant Subsidiaries have been named a PRP or defendant, 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. I&M’s reserve is approximately $10 million. As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ. Management cannot predict the amount of additional cost, if any.

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 site discussed above.

NUCLEAR CONTINGENCIES – AFFECTING I&M

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (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 generating units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the liability could be substantial.

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 2012. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste ranges from $1.3 billion to $1.7 billion in 2012 nondiscounted dollars. The wide range in estimated costs is caused by variables in assumptions. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $14 million, $14 million and $14 million for the years ended December 31, 2012, 2011 and 2010, respectively. Decommissioning costs recovered from customers are deposited in external trusts.

248

As of December 31, 2012 and 2011, the total decommissioning trust fund balance was $1.4 billion and $1.3 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. As of December 31, 2012 and 2011, fees and related interest of $265 million and $265 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 $308 million and $308 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 $20 million and $14 million in 2012 and 2011, respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2013. The proceeds reduced costs for dry cask storage. As of December 31, 2012, I&M has deferred $32 million in Prepayments and Other Current Assets and $13 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 9 for disclosure of the fair value of assets within the trusts.

Nuclear Incident Liability

I&M carries insurance coverage for property damage, decommissioning and decontamination at the Cook Plant in the amount of $1.8 billion. I&M purchases $1 billion of excess coverage for property damage, decommissioning and decontamination. Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes an industry mutual insurer for the placement of this insurance coverage. Participation in this mutual insurance requires a contingent financial obligation of up to $40 million for I&M which is assessable if the insurer’s financial resources would be inadequate to pay for losses.

The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $12.6 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 $117.5 million on each licensed reactor in the U.S. payable in annual installments of $17.5 million. As a result, I&M could be assessed $235 million per nuclear incident payable in annual installments of $35 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 $12.2 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.

249

Cook Plant, Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant, Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator. This equipment, located in the turbine building, is separate and isolated from the nuclear reactor. The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period. The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship. Repair of the property damage and replacement of the turbine rotors and other equipment cost approximately $400 million. Due to the extensive lead time required to manufacture and install new turbine rotors, I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power. The installation of the new turbine rotors and other equipment occurred as planned during the fall 2011 refueling outage of Unit 1.

I&M maintains insurance through NEIL. In February 2013, management signed an agreement and received payment from NEIL to settle the remaining insurance claims. The settlement did not have a material impact on net income, cash flows or financial condition.

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses – Affecting APCo, I&M, OPCo, PSO and SWEPCo

The Registrant Subsidiaries maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. 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 Registrant Subsidiaries. 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 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.

5. ACQUISITIONS AND IMPAIRMENTS

ACQUISITIONS

2011

Dresden Plant – Affecting APCo

In August 2011, APCo purchased the partially completed Dresden Plant from AEGCo, at cost, for $302 million. The Dresden Plant was completed and placed in service in January 2012. The Dresden Plant is located near Dresden, Ohio and is a natural gas, combined cycle power plant with a generating capacity of 608 MW.

2010

Valley Electric Membership Corporation – Affecting SWEPCo

In October 2010, SWEPCo purchased certain transmission and distribution assets of Valley Electric Membership Corporation (VEMCO) for approximately $102 million and began serving VEMCO’s 30,000 customers in Louisiana.

250

IMPAIRMENTS

2012

Beckjord Plant Unit 6, Conesville Plant Unit 3, Kammer Plant Units 1-3, Muskingum River Plant Units 1-4, Sporn Plant Units 2 and 4 and Picway Plant Unit 5 – Affecting OPCo

In October 2012, management filed applications with the FERC proposing to terminate the Interconnection Agreement and seeking to complete the corporate separation of OPCo's generation assets. Based on the intention to terminate the Interconnection Agreement and the FERC filing, management performed an evaluation of the recoverability of generation assets. As a result, in November 2012, management, using generating unit specific estimated future cash flows, concluded that OPCo had a material impairment of certain generation assets. Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of these generating units was zero based on the lack of installed environmental control equipment and the nature and condition of these generating units. In the fourth quarter of 2012, OPCo recorded a pretax impairment of $287 million in Asset Impairments and Other Related Charges on the statement of income related to Beckjord Plant Unit 6, Conesville Plant Unit 3, Kammer Plant Units 1-3, Muskingum River Plant Units 1-4, Sporn Plant Units 2 and 4 and Picway Plant Unit 5 generating units which includes $13 million of related material and supplies inventory.

Turk Plant – Affecting SWEPCo

In 2012, SWEPCo recorded a pretax write-off of $13 million in Asset Impairments and Other Related Charges on the statement of income related to unrecoverable construction costs subject to the Texas capital costs cap portion of the Turk Plant.

2011

Turk Plant – Affecting SWEPCo

In the fourth quarter of 2011, SWEPCo recorded a pretax write-off of $49 million in Asset Impairments and Other Related Charges on the statement of income related to the Texas jurisdictional portion of the Turk Plant as a result of the November 2011 Texas Court of Appeals decision upholding the Texas capital cost cap.

Muskingum River Plant Unit 5 FGD Project (MR5) – Affecting OPCo

In September 2011, subsequent to the stipulation agreement filed with the PUCO, management determined that OPCo was not likely to complete the previously suspended MR5 project and that the project’s preliminary engineering costs were no longer probable of being recovered. As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $42 million in Asset Impairments and Other Related Charges on the statement of income.

Sporn Plant Unit 5 – Affecting OPCo

In the third quarter of 2011, management decided to no longer offer the output of Sporn Unit 5 into the PJM market. Sporn Unit 5 is not expected to operate in the future, resulting in the removal of Sporn Unit 5 from the Interconnection Agreement. As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $48 million in Asset Impairments and Other Related Charges on the statement of income.

251

6. BENEFIT 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.

The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.

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 Registrant Subsidiaries and the rate of compensation increase for each subsidiary.

The Registrant Subsidiaries recognize the funded status associated with defined benefit pension and OPEB plans in their balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrant Subsidiaries 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 Registrant Subsidiaries 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 Registrant Subsidiaries’ benefit obligations are shown in the following tables:

					Other Postretirement
	Pension Plans				Benefit Plans
Assumption	2012		2011		2012		2011
Discount Rate	3.95	%	4.55	%	3.95	%	4.75	%

	Pension Plans
Assumption - Rate of Compensation Increase (a)	2012			2011
APCo		4.70	%		4.65	%
I&M		5.00	%		4.90	%
OPCo		5.00	%		4.95	%
PSO		4.90	%		4.85	%
SWEPCo		4.75	%		4.70	%

(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 Subsidiary.

For 2012, the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 11.5% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrant Subsidiary’s population participating in the pension plan.

252

Actuarial Assumptions for Net Periodic Benefit Costs

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

										Other Postretirement
	Pension Plans									Benefit Plans
Assumptions	2012			2011			2010			2012			2011			2010
Discount Rate		4.55	%		5.05	%		5.60	%		4.75	%		5.25	%		5.85	%
Expected Return on Plan Assets		7.25	%		7.75	%		8.00	%		7.25	%		7.50	%		8.00	%

	Pension Plans
Assumption - Rate of Compensation Increase	2012			2011			2010
APCo		4.70	%		4.65	%		4.35	%
I&M		5.00	%		4.90	%		4.55	%
OPCo		5.00	%		4.95	%		4.70	%
PSO		4.90	%		4.85	%		4.60	%
SWEPCo		4.75	%		4.70	%		4.45	%

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 Subsidiary.

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	2012			2011
Initial		7.00	%		7.50		%
Ultimate		5.00	%		5.00		%
Year Ultimate Reached		2020				2016

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:

	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Effect on Total Service and Interest Cost
Components of Net Periodic Postretirement
Health Care Benefit Cost:
1% Increase	$	3,845		$	3,017		$	5,347		$	1,336		$	1,547
1% Decrease		(3,029	)		(2,390	)		(4,206	)		(1,059	)		(1,227	)

Effect on the Health Care Component of the
Accumulated Postretirement Benefit
Obligation:
1% Increase	$	26,416		$	12,592		$	34,018		$	5,447		$	6,008
1% Decrease		(20,173	)		(9,529	)		(25,950	)		(4,113	)		(4,537	)

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, 2012, 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.

253

Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2012 and 2011

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.

APCo							Other Postretirement
	Pension Plans						Benefit Plans
	2012			2011			2012			2011
Change in Benefit Obligation	(in thousands)
Benefit Obligation as of January 1	$	681,450		$	652,219		$	395,482		$	383,152
Service Cost		7,565			7,199			5,387			4,983
Interest Cost		30,211			32,293			18,462			19,468
Actuarial Loss		43,341			29,137			31,776			41,306
Plan Amendment Prior Service Credit		-			-			(80,528	)		(31,145	)
Benefit Payments		(44,107	)		(39,398	)		(29,228	)		(30,040	)
Participant Contributions		-			-			5,826			6,005
Medicare Subsidy		-			-			1,813			1,753
Benefit Obligation as of December 31	$	718,460		$	681,450		$	348,990		$	395,482

Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1	$	570,756		$	512,836		$	229,735		$	243,771
Actual Gain (Loss) on Plan Assets		69,686			36,970			44,919			(4,102	)
Company Contributions		25,235			60,348			16,506			14,101
Participant Contributions		-			-			5,826			6,005
Benefit Payments		(44,107	)		(39,398	)		(29,228	)		(30,040	)
Fair Value of Plan Assets as of December 31	$	621,570		$	570,756		$	267,758		$	229,735

Underfunded Status as of December 31	$	(96,890	)	$	(110,694	)	$	(81,232	)	$	(165,747	)

I&M							Other Postretirement
	Pension Plans						Benefit Plans
	2012			2011			2012			2011
Change in Benefit Obligation	(in thousands)
Benefit Obligation as of January 1	$	581,677		$	560,982		$	277,353		$	266,742
Service Cost		9,908			9,447			6,621			6,119
Interest Cost		26,245			27,726			12,785			13,610
Actuarial Loss		44,475			17,289			13,638			28,876
Plan Amendment Prior Service Credit		-			-			(78,851	)		(24,846	)
Benefit Payments		(43,332	)		(33,767	)		(18,394	)		(18,387	)
Participant Contributions		-			-			4,226			4,112
Medicare Subsidy		-			-			1,175			1,127
Benefit Obligation as of December 31	$	618,973		$	581,677		$	218,553		$	277,353

Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1	$	503,926		$	451,688		$	181,237		$	188,690
Actual Gain (Loss) on Plan Assets		69,136			32,773			14,357			(3,946	)
Company Contributions		22,296			53,232			12,702			10,768
Participant Contributions		-			-			4,226			4,112
Benefit Payments		(43,332	)		(33,767	)		(18,394	)		(18,387	)
Fair Value of Plan Assets as of December 31	$	552,026		$	503,926		$	194,128		$	181,237

Underfunded Status as of December 31	$	(66,947	)	$	(77,751	)	$	(24,425	)	$	(96,116	)

254

OPCo							Other Postretirement
	Pension Plans						Benefit Plans
	2012			2011			2012			2011
Change in Benefit Obligation	(in thousands)
Benefit Obligation as of January 1	$	1,020,890		$	984,089		$	519,892		$	506,255
Service Cost		11,003			10,230			8,748			7,827
Interest Cost		45,194			48,350			24,189			25,497
Actuarial Loss		63,571			42,693			42,013			49,132
Plan Amendment Prior Service Credit		-			-			(101,384	)		(42,357	)
Curtailment		-			-			-			605
Benefit Payments		(72,472	)		(64,472	)		(38,269	)		(38,347	)
Participant Contributions		-			-			8,545			8,828
Medicare Subsidy		-			-			2,556			2,452
Benefit Obligation as of December 31	$	1,068,186		$	1,020,890		$	466,290		$	519,892

Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1	$	925,939		$	799,281		$	311,836		$	333,198
Actual Gain (Loss) on Plan Assets		118,395			63,181			65,125			(6,589	)
Company Contributions		43,253			127,949			19,064			14,746
Participant Contributions		-			-			8,545			8,828
Benefit Payments		(72,472	)		(64,472	)		(38,269	)		(38,347	)
Fair Value of Plan Assets as of December 31	$	1,015,115		$	925,939		$	366,301		$	311,836

Underfunded Status as of December 31	$	(53,071	)	$	(94,951	)	$	(99,989	)	$	(208,056	)

PSO							Other Postretirement
	Pension Plans						Benefit Plans
	2012			2011			2012			2011
Change in Benefit Obligation	(in thousands)
Benefit Obligation as of January 1	$	277,448		$	268,180		$	125,164		$	116,935
Service Cost		5,951			5,760			2,836			2,621
Interest Cost		12,301			13,285			5,797			6,046
Actuarial Loss		6,128			7,679			7,511			16,705
Plan Amendment Prior Service Credit		-			-			(35,971	)		(11,612	)
Benefit Payments		(22,143	)		(17,456	)		(8,363	)		(8,110	)
Participant Contributions		-			-			2,024			1,926
Medicare Subsidy		-			-			682			653
Benefit Obligation as of December 31	$	279,685		$	277,448		$	99,680		$	125,164

Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1	$	245,769		$	213,576		$	83,090		$	83,917
Actual Gain on Plan Assets		28,861			16,430			8,089			646
Company Contributions		12,336			33,219			5,681			4,711
Participant Contributions		-			-			2,024			1,926
Benefit Payments		(22,143	)		(17,456	)		(8,363	)		(8,110	)
Fair Value of Plan Assets as of December 31	$	264,823		$	245,769		$	90,521		$	83,090

Underfunded Status as of December 31	$	(14,862	)	$	(31,679	)	$	(9,159	)	$	(42,074	)

255

SWEPCo							Other Postretirement
	Pension Plans						Benefit Plans
	2012			2011			2012			2011
Change in Benefit Obligation	(in thousands)
Benefit Obligation as of January 1	$	277,594		$	267,206		$	145,160		$	129,726
Service Cost		7,099			6,573			3,324			3,029
Interest Cost		12,537			13,331			6,673			6,969
Actuarial Loss		9,752			7,861			7,885			24,547
Plan Amendment Prior Service Credit		-			-			(47,309	)		(13,534	)
Benefit Payments		(21,422	)		(17,377	)		(8,610	)		(8,226	)
Participant Contributions		-			-			2,189			2,041
Medicare Subsidy		-			-			636			608
Benefit Obligation as of December 31	$	285,560		$	277,594		$	109,948		$	145,160

Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1	$	255,861		$	224,618		$	96,364		$	93,097
Actual Gain on Plan Assets		31,992			17,283			3,143			3,797
Company Contributions		13,268			31,337			6,760			5,655
Participant Contributions		-			-			2,189			2,041
Benefit Payments		(21,422	)		(17,377	)		(8,610	)		(8,226	)
Fair Value of Plan Assets as of December 31	$	279,699		$	255,861		$	99,846		$	96,364

Underfunded Status as of December 31	$	(5,861	)	$	(21,733	)	$	(10,102	)	$	(48,796	)

Amounts Recognized on the Registrant Subsidiaries' Balance Sheets as of December 31, 2012 and 2011

									Other Postretirement
	Pension Plans								Benefit Plans
	December 31,
APCo	2012				2011				2012				2011
	(in thousands)
Other Current Liabilities - Accrued Short-term
Benefit Liability		$	(34	)		$	(34	)		$	(2,836	)		$	(2,956	)
Employee Benefits and Pension Obligations -
Accrued Long-term Benefit Liability			(96,856	)			(110,660	)			(78,396	)			(162,791	)
Underfunded Status		$	(96,890	)		$	(110,694	)		$	(81,232	)		$	(165,747	)

									Other Postretirement
	Pension Plans								Benefit Plans
	December 31,
I&M	2012				2011				2012				2011
	(in thousands)
Other Current Liabilities - Accrued Short-term
Benefit Liability		$	(15	)		$	(14	)		$	(290	)		$	(308	)
Deferred Credits and Other Noncurrent Liabilities -
Accrued Long-term Benefit Liability			(66,932	)			(77,737	)			(24,135	)			(95,808	)
Underfunded Status		$	(66,947	)		$	(77,751	)		$	(24,425	)		$	(96,116	)

256

									Other Postretirement
	Pension Plans								Benefit Plans
	December 31,
OPCo	2012				2011				2012				2011
	(in thousands)
Other Current Liabilities - Accrued Short-term
Benefit Liability		$	(64	)		$	(62	)		$	(986	)		$	(991	)
Employee Benefits and Pension Obligations -
Accrued Long-term Benefit Liability			(53,007	)			(94,889	)			(99,003	)			(207,065	)
Underfunded Status		$	(53,071	)		$	(94,951	)		$	(99,989	)		$	(208,056	)

									Other Postretirement
	Pension Plans								Benefit Plans
	December 31,
PSO	2012				2011				2012				2011
	(in thousands)
Other Current Liabilities - Accrued Short-term
Benefit Liability		$	(89	)		$	(88	)		$	-			$	-
Employee Benefits and Pension Obligations -
Accrued Long-term Benefit Liability			(14,773	)			(31,591	)			(9,159	)			(42,074	)
Underfunded Status		$	(14,862	)		$	(31,679	)		$	(9,159	)		$	(42,074	)

									Other Postretirement
	Pension Plans								Benefit Plans
	December 31,
SWEPCo	2012				2011				2012				2011
	(in thousands)
Other Current Liabilities - Accrued Short-term
Benefit Liability		$	(80	)		$	(78	)		$	-			$	-
Employee Benefits and Pension Obligations -
Accrued Long-term Benefit Liability			(5,781	)			(21,655	)			(10,102	)			(48,796	)
Underfunded Status		$	(5,861	)		$	(21,733	)		$	(10,102	)		$	(48,796	)

Amounts Included in AOCI and Regulatory Assets as of December 31, 2012 and 2011

							Other Postretirement
APCo	Pension Plans						Benefit Plans
	December 31,
	2012			2011			2012				2011
Components	(in thousands)
Net Actuarial Loss		$	303,483		$	308,223		$	167,173			$	174,615
Prior Service Cost (Credit)			918			1,393			(110,726	)			(33,060	)
Transition Obligation			-			-			-				780

Recorded as
Regulatory Assets		$	299,456		$	305,558		$	13,189			$	56,764
Deferred Income Taxes			1,732			1,420			15,140				29,951
Net of Tax AOCI			3,213			2,638			28,118				55,620

257

							Other Postretirement
I&M	Pension Plans						Benefit Plans
	December 31,
	2012			2011			2012				2011
Components	(in thousands)
Net Actuarial Loss		$	211,443		$	216,107		$	125,935			$	121,238
Prior Service Cost (Credit)			900			1,307			(103,959	)			(27,491	)
Transition Obligation			-			-			-				132

Recorded as
Regulatory Assets		$	202,821		$	207,237		$	17,976			$	84,155
Deferred Income Taxes			3,332			3,561			1,400				3,403
Net of Tax AOCI			6,190			6,616			2,600				6,321

							Other Postretirement
OPCo	Pension Plans						Benefit Plans
	December 31,
	2012			2011			2012				2011
Components	(in thousands)
Net Actuarial Loss		$	500,318		$	517,180		$	216,350			$	231,189
Prior Service Cost (Credit)			1,282			2,025			(142,253	)			(44,742	)
Transition Obligation			-			-			-				104

Recorded as
Regulatory Assets		$	289,931		$	305,240		$	19,754			$	84,472
Deferred Income Taxes			74,084			74,888			19,020				35,728
Net of Tax AOCI			137,585			139,077			35,323				66,351

							Other Postretirement
PSO	Pension Plans						Benefit Plans
	December 31,
	2012			2011			2012				2011
Components	(in thousands)
Net Actuarial Loss		$	123,132		$	136,056		$	56,493			$	54,516
Prior Service Cost (Credit)			1,129			181			(47,350	)			(12,458	)

Recorded as
Regulatory Assets		$	124,261		$	136,237		$	9,143			$	42,058

							Other Postretirement
SWEPCo	Pension Plans						Benefit Plans
	December 31,
	2012			2011			2012				2011
Components	(in thousands)
Net Actuarial Loss		$	121,839		$	133,542		$	67,223			$	59,541
Prior Service Cost (Credit)			1,353			560			(57,138	)			(10,762	)

Recorded as
Regulatory Assets		$	123,192		$	134,102		$	6,528			$	31,407
Deferred Income Taxes			-			-			1,246				6,081
Net of Tax AOCI			-			-			2,311				11,291

258

Components of the change in amounts included in AOCI and Regulatory Assets by Registrant Subsidiary during the years ended December 31, 2012 and 2011 are as follows:

Pension Plans - Components	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Actuarial Loss (Gain) During the Year	$	15,599		$	12,905		$	13,577		$	(4,718	)	$	(3,373	)
Amortization of Actuarial Loss		(20,339	)		(17,569	)		(30,439	)		(8,206	)		(8,330	)
Amortization of Prior Service Credit (Cost)		(475	)		(407	)		(743	)		948			793
Change for the Year Ended
December 31, 2012	$	(5,215	)	$	(5,071	)	$	(17,605	)	$	(11,976	)	$	(10,910	)

Pension Plans - Components	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Actuarial Loss During the Year	$	33,995		$	21,372		$	44,976		$	8,712		$	8,958
Amortization of Actuarial Loss		(16,570	)		(14,144	)		(24,828	)		(6,757	)		(6,759	)
Amortization of Prior Service Credit (Cost)		(917	)		(744	)		(1,474	)		950			795
Change for the Year Ended
December 31, 2011	$	16,508		$	6,484		$	18,674		$	2,905		$	2,994

Other Postretirement Benefit Plans - Components	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Actuarial Loss (Gain) During the Year	$	3,084		$	11,747		$	(1,170	)	$	5,166		$	11,341
Amortization of Actuarial Loss		(10,526	)		(7,050	)		(13,669	)		(3,189	)		(3,659	)
Prior Service Credit		(80,528	)		(78,851	)		(101,384	)		(35,971	)		(47,309	)
Amortization of Prior Service Credit		2,862			2,383			3,873			1,079			933
Amortization of Transition Obligation		(780	)		(132	)		(104	)		-			-
Change for the Year Ended
December 31, 2012	$	(85,888	)	$	(71,903	)	$	(112,454	)	$	(32,915	)	$	(38,694	)

Other Postretirement Benefit Plans - Components	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Actuarial Loss During the Year	$	65,104		$	46,321		$	79,611		$	22,147		$	23,619
Amortization of Actuarial Loss		(5,839	)		(3,566	)		(7,298	)		(1,553	)		(1,785	)
Prior Service Credit		(31,145	)		(24,846	)		(42,357	)		(11,612	)		(9,409	)
Amortization of Prior Service Credit (Cost)		171			237			212			75			(258	)
Amortization of Transition Obligation		(1,167	)		(188	)		(150	)		-			-
Change for the Year Ended
December 31, 2011	$	27,124		$	17,958		$	30,018		$	9,057		$	12,167

259

Pension and Other Postretirement Plans’ Assets

The following tables present the classification of pension plan assets within the fair value hierarchy by Registrant Subsidiary as of December 31, 2012:

APCo
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	173,149	$	-	$	-	$	-	$	173,149	27.9	%
	International			65,757		-		-		-		65,757	10.5	%
	Real Estate Investment Trusts			11,986		-		-		-		11,986	1.9	%
	Common Collective Trust -
		International		-		574		-		-		574	0.1	%
Subtotal - Equities				250,892		574		-		-		251,466	40.4	%

Fixed Income:
	Common Collective Trust - Debt			-		4,200		-		-		4,200	0.7	%
	United States Government and
		Agency Securities		-		94,682		-		-		94,682	15.2	%
	Corporate Debt			-		163,484		-		-		163,484	26.3	%
	Foreign Debt			-		26,292		-		-		26,292	4.2	%
	State and Local Government			-		5,821		-		-		5,821	0.9	%
	Other - Asset Backed			-		4,714		-		-		4,714	0.8	%
Subtotal - Fixed Income				-		299,193		-		-		299,193	48.1	%

Real Estate				-		-		29,063		-		29,063	4.7	%

Alternative Investments				-		-		25,888		-		25,888	4.2	%
Securities Lending				-		10,633		-		-		10,633	1.7	%
Securities Lending Collateral (a)				-		-		-		(12,025)		(12,025)	(1.9)	%

Cash and Cash Equivalents				-		16,646		-		-		16,646	2.7	%
Other - Pending Transactions and
	Accrued Income (b)			-		-		-		706		706	0.1	%

Total			$	250,892	$	327,046	$	54,951	$	(11,319)	$	621,570	100.0	%

260

I&M
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	153,776	$	-	$	-	$	-	$	153,776	27.9	%
	International			58,400		-		-		-		58,400	10.5	%
	Real Estate Investment Trusts			10,645		-		-		-		10,645	1.9	%
	Common Collective Trust -
		International		-		510		-		-		510	0.1	%
Subtotal - Equities				222,821		510		-		-		223,331	40.4	%

Fixed Income:
	Common Collective Trust - Debt			-		3,730		-		-		3,730	0.7	%
	United States Government and
		Agency Securities		-		84,089		-		-		84,089	15.2	%
	Corporate Debt			-		145,193		-		-		145,193	26.3	%
	Foreign Debt			-		23,350		-		-		23,350	4.2	%
	State and Local Government			-		5,170		-		-		5,170	0.9	%
	Other - Asset Backed			-		4,187		-		-		4,187	0.8	%
Subtotal - Fixed Income				-		265,719		-		-		265,719	48.1	%

Real Estate				-		-		25,811		-		25,811	4.7	%

Alternative Investments				-		-		22,992		-		22,992	4.2	%
Securities Lending				-		9,443		-		-		9,443	1.7	%
Securities Lending Collateral (a)				-		-		-		(10,680)		(10,680)	(1.9)	%

Cash and Cash Equivalents				-		14,783		-		-		14,783	2.7	%
Other - Pending Transactions and
	Accrued Income (b)			-		-		-		627		627	0.1	%

Total			$	222,821	$	290,455	$	48,803	$	(10,053)	$	552,026	100.0	%

261

OPCo
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	282,777	$	-	$	-	$	-	$	282,777	27.9	%
	International			107,391		-		-		-		107,391	10.5	%
	Real Estate Investment Trusts			19,576		-		-		-		19,576	1.9	%
	Common Collective Trust -
		International		-		938		-		-		938	0.1	%
Subtotal - Equities				409,744		938		-		-		410,682	40.4	%

Fixed Income:
	Common Collective Trust - Debt			-		6,858		-		-		6,858	0.7	%
	United States Government and
		Agency Securities		-		154,630		-		-		154,630	15.2	%
	Corporate Debt			-		266,994		-		-		266,994	26.3	%
	Foreign Debt			-		42,938		-		-		42,938	4.2	%
	State and Local Government			-		9,506		-		-		9,506	0.9	%
	Other - Asset Backed			-		7,699		-		-		7,699	0.8	%
Subtotal - Fixed Income				-		488,625		-		-		488,625	48.1	%

Real Estate				-		-		47,464		-		47,464	4.7	%

Alternative Investments				-		-		42,279		-		42,279	4.2	%
Securities Lending				-		17,365		-		-		17,365	1.7	%
Securities Lending Collateral (a)				-		-		-		(19,639)		(19,639)	(1.9)	%

Cash and Cash Equivalents				-		27,185		-		-		27,185	2.7	%
Other - Pending Transactions and
	Accrued Income (b)			-		-		-		1,154		1,154	0.1	%

Total			$	409,744	$	534,113	$	89,743	$	(18,485)	$	1,015,115	100.0	%

262

PSO
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	73,770	$	-	$	-	$	-	$	73,770	27.9	%
	International			28,016		-		-		-		28,016	10.5	%
	Real Estate Investment Trusts			5,107		-		-		-		5,107	1.9	%
	Common Collective Trust -
		International		-		245		-		-		245	0.1	%
Subtotal - Equities				106,893		245		-		-		107,138	40.4	%

Fixed Income:
	Common Collective Trust - Debt			-		1,789		-		-		1,789	0.7	%
	United States Government and
		Agency Securities		-		40,340		-		-		40,340	15.2	%
	Corporate Debt			-		69,653		-		-		69,653	26.3	%
	Foreign Debt			-		11,202		-		-		11,202	4.2	%
	State and Local Government			-		2,480		-		-		2,480	0.9	%
	Other - Asset Backed			-		2,009		-		-		2,009	0.8	%
Subtotal - Fixed Income				-		127,473		-		-		127,473	48.1	%

Real Estate				-		-		12,382		-		12,382	4.7	%

Alternative Investments				-		-		11,030		-		11,030	4.2	%
Securities Lending				-		4,530		-		-		4,530	1.7	%
Securities Lending Collateral (a)				-		-		-		(5,123)		(5,123)	(1.9)	%

Cash and Cash Equivalents				-		7,092		-		-		7,092	2.7	%
Other - Pending Transactions and
	Accrued Income (b)			-		-		-		301		301	0.1	%

Total			$	106,893	$	139,340	$	23,412	$	(4,822)	$	264,823	100.0	%

263

SWEPCo
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	77,915	$	-	$	-	$	-	$	77,915	27.9	%
	International			29,590		-		-		-		29,590	10.5	%
	Real Estate Investment Trusts			5,394		-		-		-		5,394	1.9	%
	Common Collective Trust -
		International		-		258		-		-		258	0.1	%
Subtotal - Equities				112,899		258		-		-		113,157	40.4	%

Fixed Income:
	Common Collective Trust - Debt			-		1,890		-		-		1,890	0.7	%
	United States Government and
		Agency Securities		-		42,606		-		-		42,606	15.2	%
	Corporate Debt			-		73,566		-		-		73,566	26.3	%
	Foreign Debt			-		11,831		-		-		11,831	4.2	%
	State and Local Government			-		2,619		-		-		2,619	0.9	%
	Other - Asset Backed			-		2,121		-		-		2,121	0.8	%
Subtotal - Fixed Income				-		134,633		-		-		134,633	48.1	%

Real Estate				-		-		13,078		-		13,078	4.7	%

Alternative Investments				-		-		11,649		-		11,649	4.2	%
Securities Lending				-		4,785		-		-		4,785	1.7	%
Securities Lending Collateral (a)				-		-		-		(5,411)		(5,411)	(1.9)	%

Cash and Cash Equivalents				-		7,490		-		-		7,490	2.7	%
Other - Pending Transactions and
	Accrued Income (b)			-		-		-		318		318	0.1	%

Total			$	112,899	$	147,166	$	24,727	$	(5,093)	$	279,699	100.0	%

(a) Amounts in "Other" column primarily represent an obligation to repay cash 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 tables set forth a reconciliation of changes in the fair value of assets classified as Level 3 in the fair value hierarchy by Registrant Subsidiary for pension assets:

	Corporate			Real		Alternative		Total
APCo	Debt			Estate		Investments		Level 3
	(in thousands)
Balance as of January 1, 2012	$	846		$	21,666	$	21,269	$	43,781
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		-			3,913		1,319		5,232
Relating to Assets Sold During the Period		(298	)		-		640		342
Purchases and Sales		(548	)		3,484		2,660		5,596
Transfers into Level 3		-			-		-		-
Transfers out of Level 3		-			-		-		-
Balance as of December 31, 2012	$	-		$	29,063	$	25,888	$	54,951

264

	Corporate			Real		Alternative		Total
I&M	Debt			Estate		Investments		Level 3
	(in thousands)
Balance as of January 1, 2012	$	747		$	19,129	$	18,779	$	38,655
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		-			3,535		1,203		4,738
Relating to Assets Sold During the Period		(263	)		-		584		321
Purchases and Sales		(484	)		3,147		2,426		5,089
Transfers into Level 3		-			-		-		-
Transfers out of Level 3		-			-		-		-
Balance as of December 31, 2012	$	-		$	25,811	$	22,992	$	48,803

	Corporate			Real		Alternative		Total
OPCo	Debt			Estate		Investments		Level 3
	(in thousands)
Balance as of January 1, 2012	$	1,372		$	35,148	$	34,505	$	71,025
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		-			6,515		2,220		8,735
Relating to Assets Sold During the Period		(483	)		-		1,077		594
Purchases and Sales		(889	)		5,801		4,477		9,389
Transfers into Level 3		-			-		-		-
Transfers out of Level 3		-			-		-		-
Balance as of December 31, 2012	$	-		$	47,464	$	42,279	$	89,743

	Corporate			Real		Alternative		Total
PSO	Debt			Estate		Investments		Level 3
	(in thousands)
Balance as of January 1, 2012	$	364		$	9,329	$	9,159	$	18,852
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		-			1,615		534		2,149
Relating to Assets Sold During the Period		(128	)		-		259		131
Purchases and Sales		(236	)		1,438		1,078		2,280
Transfers into Level 3		-			-		-		-
Transfers out of Level 3		-			-		-		-
Balance as of December 31, 2012	$	-		$	12,382	$	11,030	$	23,412

	Corporate			Real		Alternative		Total
SWEPCo	Debt			Estate		Investments		Level 3
	(in thousands)
Balance as of January 1, 2012	$	379		$	9,712	$	9,535	$	19,626
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		-			1,780		603		2,383
Relating to Assets Sold During the Period		(134	)		-		293		159
Purchases and Sales		(245	)		1,586		1,218		2,559
Transfers into Level 3		-			-		-		-
Transfers out of Level 3		-			-		-		-
Balance as of December 31, 2012	$	-		$	13,078	$	11,649	$	24,727

265

The following tables present the classification of OPEB plan assets within the fair value hierarchy by Registrant Subsidiary as of December 31, 2012:

APCo
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	72,063	$	-	$	-	$	-	$	72,063	26.9	%
	International			86,158		-		-		-		86,158	32.2	%
Subtotal - Equities				158,221		-		-		-		158,221	59.1	%

Fixed Income:
	Common Collective Trust - Debt			-		12,388		-		-		12,388	4.6	%
	United States Government and
		Agency Securities		-		14,036		-		-		14,036	5.2	%
	Corporate Debt			-		26,437		-		-		26,437	9.9	%
	Foreign Debt			-		4,469		-		-		4,469	1.7	%
	State and Local Government			-		1,242		-		-		1,242	0.5	%
	Other - Asset Backed			-		1,678		-		-		1,678	0.6	%
Subtotal - Fixed Income				-		60,250		-		-		60,250	22.5	%

Trust Owned Life Insurance:
	International Equities			-		8,800		-		-		8,800	3.3	%
	United States Bonds			-		27,762		-		-		27,762	10.3	%

Cash and Cash Equivalents				10,598		1,947		-		-		12,545	4.7	%
Other - Pending Transactions and
	Accrued Income (a)			-		-		-		180		180	0.1	%

Total			$	168,819	$	98,759	$	-	$	180	$	267,758	100.0	%

266

I&M
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	52,245	$	-	$	-	$	-	$	52,245	26.9	%
	International			62,466		-		-		-		62,466	32.2	%
Subtotal - Equities				114,711		-		-		-		114,711	59.1	%

Fixed Income:
	Common Collective Trust - Debt			-		8,982		-		-		8,982	4.6	%
	United States Government and
		Agency Securities		-		10,176		-		-		10,176	5.2	%
	Corporate Debt			-		19,167		-		-		19,167	9.9	%
	Foreign Debt			-		3,240		-		-		3,240	1.7	%
	State and Local Government			-		901		-		-		901	0.5	%
	Other - Asset Backed			-		1,217		-		-		1,217	0.6	%
Subtotal - Fixed Income				-		43,683		-		-		43,683	22.5	%

Trust Owned Life Insurance:
	International Equities			-		6,380		-		-		6,380	3.3	%
	United States Bonds			-		20,128		-		-		20,128	10.3	%

Cash and Cash Equivalents				7,684		1,412		-		-		9,096	4.7	%
Other - Pending Transactions and
	Accrued Income (a)			-		-		-		130		130	0.1	%

Total			$	122,395	$	71,603	$	-	$	130	$	194,128	100.0	%

OPCo
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	98,583	$	-	$	-	$	-	$	98,583	26.9	%
	International			117,867		-		-		-		117,867	32.2	%
Subtotal - Equities				216,450		-		-		-		216,450	59.1	%

Fixed Income:
	Common Collective Trust - Debt			-		16,947		-		-		16,947	4.6	%
	United States Government and
		Agency Securities		-		19,202		-		-		19,202	5.2	%
	Corporate Debt			-		36,166		-		-		36,166	9.9	%
	Foreign Debt			-		6,113		-		-		6,113	1.7	%
	State and Local Government			-		1,700		-		-		1,700	0.5	%
	Other - Asset Backed			-		2,296		-		-		2,296	0.6	%
Subtotal - Fixed Income				-		82,424		-		-		82,424	22.5	%

Trust Owned Life Insurance:
	International Equities			-		12,038		-		-		12,038	3.3	%
	United States Bonds			-		37,980		-		-		37,980	10.3	%

Cash and Cash Equivalents				14,499		2,664		-		-		17,163	4.7	%
Other - Pending Transactions and
	Accrued Income (a)			-		-		-		246		246	0.1	%

Total			$	230,949	$	135,106	$	-	$	246	$	366,301	100.0	%

267

PSO
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	24,362	$	-	$	-	$	-	$	24,362	26.9	%
	International			29,128		-		-		-		29,128	32.2	%
Subtotal - Equities				53,490		-		-		-		53,490	59.1	%

Fixed Income:
	Common Collective Trust - Debt			-		4,188		-		-		4,188	4.6	%
	United States Government and
		Agency Securities		-		4,745		-		-		4,745	5.2	%
	Corporate Debt			-		8,937		-		-		8,937	9.9	%
	Foreign Debt			-		1,511		-		-		1,511	1.7	%
	State and Local Government			-		420		-		-		420	0.5	%
	Other - Asset Backed			-		567		-		-		567	0.6	%
Subtotal - Fixed Income				-		20,368		-		-		20,368	22.5	%

Trust Owned Life Insurance:
	International Equities			-		2,975		-		-		2,975	3.3	%
	United States Bonds			-		9,386		-		-		9,386	10.3	%

Cash and Cash Equivalents				3,583		658		-		-		4,241	4.7	%
Other - Pending Transactions and
	Accrued Income (a)			-		-		-		61		61	0.1	%

Total			$	57,073	$	33,387	$	-	$	61	$	90,521	100.0	%

SWEPCo
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	26,874	$	-	$	-	$	-	$	26,874	26.9	%
	International			32,128		-		-		-		32,128	32.2	%
Subtotal - Equities				59,002		-		-		-		59,002	59.1	%

Fixed Income:
	Common Collective Trust - Debt			-		4,619		-		-		4,619	4.6	%
	United States Government and
		Agency Securities		-		5,234		-		-		5,234	5.2	%
	Corporate Debt			-		9,858		-		-		9,858	9.9	%
	Foreign Debt			-		1,666		-		-		1,666	1.7	%
	State and Local Government			-		463		-		-		463	0.5	%
	Other - Asset Backed			-		626		-		-		626	0.6	%
Subtotal - Fixed Income				-		22,466		-		-		22,466	22.5	%

Trust Owned Life Insurance:
	International Equities			-		3,281		-		-		3,281	3.3	%
	United States Bonds			-		10,352		-		-		10,352	10.3	%

Cash and Cash Equivalents				3,952		726		-		-		4,678	4.7	%
Other - Pending Transactions and
	Accrued Income (a)			-		-		-		67		67	0.1	%

Total			$	62,954	$	36,825	$	-	$	67	$	99,846	100.0	%

(a) Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

268

The following tables present the classification of pension plan assets within the fair value hierarchy by Registrant Subsidiary as of December 31, 2011:

APCo
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	192,957	$	-	$	-	$	-	$	192,957	33.8	%
	International			52,904		-		-		-		52,904	9.3	%
	Real Estate Investment Trusts			13,794		-		-		-		13,794	2.4	%
	Common Collective Trust -
		International		-		17,038		-		-		17,038	3.0	%
Subtotal - Equities				259,655		17,038		-		-		276,693	48.5	%

Fixed Income:
	Common Collective Trust - Debt			-		3,483		-		-		3,483	0.6	%
	United States Government and
		Agency Securities		-		75,042		-		-		75,042	13.2	%
	Corporate Debt			-		130,606		846		-		131,452	23.0	%
	Foreign Debt			-		25,289		-		-		25,289	4.4	%
	State and Local Government			-		6,374		-		-		6,374	1.1	%
	Other - Asset Backed			-		3,449		-		-		3,449	0.6	%
Subtotal - Fixed Income				-		244,243		846		-		245,089	42.9	%

Real Estate				-		-		21,666		-		21,666	3.8	%

Alternative Investments				-		-		21,269		-		21,269	3.7	%
Securities Lending				-		28,488		-		-		28,488	5.0	%
Securities Lending Collateral (a)				-		-		-		(31,276)		(31,276)	(5.5)	%

Cash and Cash Equivalents				-		12,306		-		-		12,306	2.2	%
Other - Pending Transactions and
	Accrued Income (b)			-		-		-		(3,479)		(3,479)	(0.6)	%

Total			$	259,655	$	302,075	$	43,781	$	(34,755)	$	570,756	100.0	%

269

I&M
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	170,364	$	-	$	-	$	-	$	170,364	33.8	%
	International			46,709		-		-		-		46,709	9.3	%
	Real Estate Investment Trusts			12,179		-		-		-		12,179	2.4	%
	Common Collective Trust -
		International		-		15,043		-		-		15,043	3.0	%
Subtotal - Equities				229,252		15,043		-		-		244,295	48.5	%

Fixed Income:
	Common Collective Trust - Debt			-		3,075		-		-		3,075	0.6	%
	United States Government and
		Agency Securities		-		66,255		-		-		66,255	13.2	%
	Corporate Debt			-		115,313		747		-		116,060	23.0	%
	Foreign Debt			-		22,328		-		-		22,328	4.4	%
	State and Local Government			-		5,628		-		-		5,628	1.1	%
	Other - Asset Backed			-		3,045		-		-		3,045	0.6	%
Subtotal - Fixed Income				-		215,644		747		-		216,391	42.9	%

Real Estate				-		-		19,129		-		19,129	3.8	%

Alternative Investments				-		-		18,779		-		18,779	3.7	%
Securities Lending				-		25,153		-		-		25,153	5.0	%
Securities Lending Collateral (a)				-		-		-		(27,614)		(27,614)	(5.5)	%

Cash and Cash Equivalents				-		10,865		-		-		10,865	2.2	%
Other - Pending Transactions and
	Accrued Income (b)			-		-		-		(3,072)		(3,072)	(0.6)	%

Total			$	229,252	$	266,705	$	38,655	$	(30,686)	$	503,926	100.0	%

270

OPCo
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	313,034	$	-	$	-	$	-	$	313,034	33.8	%
	International			85,825		-		-		-		85,825	9.3	%
	Real Estate Investment Trusts			22,379		-		-		-		22,379	2.4	%
	Common Collective Trust -
		International		-		27,641		-		-		27,641	3.0	%
Subtotal - Equities				421,238		27,641		-		-		448,879	48.5	%

Fixed Income:
	Common Collective Trust - Debt			-		5,650		-		-		5,650	0.6	%
	United States Government and
		Agency Securities		-		121,741		-		-		121,741	13.2	%
	Corporate Debt			-		211,883		1,372		-		213,255	23.0	%
	Foreign Debt			-		41,027		-		-		41,027	4.4	%
	State and Local Government			-		10,341		-		-		10,341	1.1	%
	Other - Asset Backed			-		5,595		-		-		5,595	0.6	%
Subtotal - Fixed Income				-		396,237		1,372		-		397,609	42.9	%

Real Estate				-		-		35,148		-		35,148	3.8	%

Alternative Investments				-		-		34,505		-		34,505	3.7	%
Securities Lending				-		46,217		-		-		46,217	5.0	%
Securities Lending Collateral (a)				-		-		-		(50,739)		(50,739)	(5.5)	%

Cash and Cash Equivalents				-		19,964		-		-		19,964	2.2	%
Other - Pending Transactions and
	Accrued Income (b)			-		-		-		(5,644)		(5,644)	(0.6)	%

Total			$	421,238	$	490,059	$	71,025	$	(56,383)	$	925,939	100.0	%

271

PSO
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	83,086	$	-	$	-	$	-	$	83,086	33.8	%
	International			22,781		-		-		-		22,781	9.3	%
	Real Estate Investment Trusts			5,940		-		-		-		5,940	2.4	%
	Common Collective Trust -
		International		-		7,337		-		-		7,337	3.0	%
Subtotal - Equities				111,807		7,337		-		-		119,144	48.5	%

Fixed Income:
	Common Collective Trust - Debt			-		1,500		-		-		1,500	0.6	%
	United States Government and
		Agency Securities		-		32,313		-		-		32,313	13.2	%
	Corporate Debt			-		56,239		364		-		56,603	23.0	%
	Foreign Debt			-		10,890		-		-		10,890	4.4	%
	State and Local Government			-		2,745		-		-		2,745	1.1	%
	Other - Asset Backed			-		1,485		-		-		1,485	0.6	%
Subtotal - Fixed Income				-		105,172		364		-		105,536	42.9	%

Real Estate				-		-		9,329		-		9,329	3.8	%

Alternative Investments				-		-		9,159		-		9,159	3.7	%
Securities Lending				-		12,267		-		-		12,267	5.0	%
Securities Lending Collateral (a)				-		-		-		(13,467)		(13,467)	(5.5)	%

Cash and Cash Equivalents				-		5,299		-		-		5,299	2.2	%
Other - Pending Transactions and
	Accrued Income (b)			-		-		-		(1,498)		(1,498)	(0.6)	%

Total			$	111,807	$	130,075	$	18,852	$	(14,965)	$	245,769	100.0	%

272

SWEPCo
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	86,499	$	-	$	-	$	-	$	86,499	33.8	%
	International			23,716		-		-		-		23,716	9.3	%
	Real Estate Investment Trusts			6,184		-		-		-		6,184	2.4	%
	Common Collective Trust -
		International		-		7,638		-		-		7,638	3.0	%
Subtotal - Equities				116,399		7,638		-		-		124,037	48.5	%

Fixed Income:
	Common Collective Trust - Debt			-		1,561		-		-		1,561	0.6	%
	United States Government and
		Agency Securities		-		33,640		-		-		33,640	13.2	%
	Corporate Debt			-		58,549		379		-		58,928	23.0	%
	Foreign Debt			-		11,337		-		-		11,337	4.4	%
	State and Local Government			-		2,857		-		-		2,857	1.1	%
	Other - Asset Backed			-		1,546		-		-		1,546	0.6	%
Subtotal - Fixed Income				-		109,490		379		-		109,869	42.9	%

Real Estate				-		-		9,712		-		9,712	3.8	%

Alternative Investments				-		-		9,535		-		9,535	3.7	%
Securities Lending				-		12,771		-		-		12,771	5.0	%
Securities Lending Collateral (a)				-		-		-		(14,020)		(14,020)	(5.5)	%

Cash and Cash Equivalents				-		5,517		-		-		5,517	2.2	%
Other - Pending Transactions and
	Accrued Income (b)			-		-		-		(1,560)		(1,560)	(0.6)	%

Total			$	116,399	$	135,416	$	19,626	$	(15,580)	$	255,861	100.0	%

(a) Amounts in "Other" column primarily represent an obligation to repay cash 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 tables set forth a reconciliation of changes in the fair value of assets classified as Level 3 in the fair value hierarchy for pension assets by Registrant Subsidiary:

	Corporate		Real		Alternative		Total
APCo	Debt		Estate		Investments		Level 3
			(in thousands)
Balance as of January 1, 2011	$	-	$	11,060	$	17,281	$	28,341
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		-		2,952		1,142		4,094
Relating to Assets Sold During the Period		-		-		392		392
Purchases and Sales		-		7,654		2,454		10,108
Transfers into Level 3		846		-		-		846
Transfers out of Level 3		-		-		-		-
Balance as of December 31, 2011	$	846	$	21,666	$	21,269	$	43,781

273

	Corporate		Real		Alternative		Total
I&M	Debt		Estate		Investments		Level 3
			(in thousands)
Balance as of January 1, 2011	$	-	$	9,742	$	15,220	$	24,962
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		-		2,612		1,019		3,631
Relating to Assets Sold During the Period		-		-		350		350
Purchases and Sales		-		6,775		2,190		8,965
Transfers into Level 3		747		-		-		747
Transfers out of Level 3		-		-		-		-
Balance as of December 31, 2011	$	747	$	19,129	$	18,779	$	38,655

	Corporate		Real		Alternative		Total
OPCo	Debt		Estate		Investments		Level 3
			(in thousands)
Balance as of January 1, 2011	$	-	$	17,239	$	26,933	$	44,172
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		-		4,985		2,167		7,152
Relating to Assets Sold During the Period		-		-		744		744
Purchases and Sales		-		12,924		4,661		17,585
Transfers into Level 3		1,372		-		-		1,372
Transfers out of Level 3		-		-		-		-
Balance as of December 31, 2011	$	1,372	$	35,148	$	34,505	$	71,025

	Corporate		Real		Alternative		Total
PSO	Debt		Estate		Investments		Level 3
			(in thousands)
Balance as of January 1, 2011	$	-	$	4,606	$	7,197	$	11,803
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		-		1,314		561		1,875
Relating to Assets Sold During the Period		-		-		193		193
Purchases and Sales		-		3,409		1,208		4,617
Transfers into Level 3		364		-		-		364
Transfers out of Level 3		-		-		-		-
Balance as of December 31, 2011	$	364	$	9,329	$	9,159	$	18,852

	Corporate		Real		Alternative		Total
SWEPCo	Debt		Estate		Investments		Level 3
	(in thousands)
Balance as of January 1, 2011	$	-	$	4,844	$	7,569	$	12,413
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		-		1,355		563		1,918
Relating to Assets Sold During the Period		-		-		194		194
Purchases and Sales		-		3,513		1,209		4,722
Transfers into Level 3		379		-		-		379
Transfers out of Level 3		-		-		-		-
Balance as of December 31, 2011	$	379	$	9,712	$	9,535	$	19,626

274

The following tables present the classification of OPEB plan assets within the fair value hierarchy by Registrant Subsidiary as of December 31, 2011:

APCo
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	56,670	$	-	$	-	$	-	$	56,670	24.7	%
	International			61,982		-		-		-		61,982	27.0	%
	Common Collective Trust -
		Global		-		16,159		-		-		16,159	7.0	%
Subtotal - Equities				118,652		16,159		-		-		134,811	58.7	%

Fixed Income:
	Common Collective Trust - Debt			-		11,279		-		-		11,279	4.9	%
	United States Government and
		Agency Securities		-		13,165		-		-		13,165	5.7	%
	Corporate Debt			-		24,792		-		-		24,792	10.8	%
	Foreign Debt			-		5,256		-		-		5,256	2.3	%
	State and Local Government			-		1,371		-		-		1,371	0.6	%
	Other - Asset Backed			-		312		-		-		312	0.1	%
Subtotal - Fixed Income				-		56,175		-		-		56,175	24.4	%

Trust Owned Life Insurance:
	International Equities			-		7,533		-		-		7,533	3.3	%
	United States Bonds			-		25,719		-		-		25,719	11.2	%

Cash and Cash Equivalents				2,739		3,816		-		-		6,555	2.9	%
Other - Pending Transactions and
	Accrued Income (a)			-		-		-		(1,058)		(1,058)	(0.5)	%

Total			$	121,391	$	109,402	$	-	$	(1,058)	$	229,735	100.0	%

275

I&M
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	44,707	$	-	$	-	$	-	$	44,707	24.7	%
	International			48,897		-		-		-		48,897	27.0	%
	Common Collective Trust -
		Global		-		12,748		-		-		12,748	7.0	%
Subtotal - Equities				93,604		12,748		-		-		106,352	58.7	%

Fixed Income:
	Common Collective Trust - Debt			-		8,898		-		-		8,898	4.9	%
	United States Government and
		Agency Securities		-		10,386		-		-		10,386	5.7	%
	Corporate Debt			-		19,558		-		-		19,558	10.8	%
	Foreign Debt			-		4,146		-		-		4,146	2.3	%
	State and Local Government			-		1,082		-		-		1,082	0.6	%
	Other - Asset Backed			-		246		-		-		246	0.1	%
Subtotal - Fixed Income				-		44,316		-		-		44,316	24.4	%

Trust Owned Life Insurance:
	International Equities			-		5,943		-		-		5,943	3.3	%
	United States Bonds			-		20,290		-		-		20,290	11.2	%

Cash and Cash Equivalents				2,161		3,010		-		-		5,171	2.9	%
Other - Pending Transactions and
	Accrued Income (a)			-		-		-		(835)		(835)	(0.5)	%

Total			$	95,765	$	86,307	$	-	$	(835)	$	181,237	100.0	%

276

OPCo
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	76,921	$	-	$	-	$	-	$	76,921	24.7	%
	International			84,133		-		-		-		84,133	27.0	%
	Common Collective Trust -
		Global		-		21,934		-		-		21,934	7.0	%
Subtotal - Equities				161,054		21,934		-		-		182,988	58.7	%

Fixed Income:
	Common Collective Trust - Debt			-		15,310		-		-		15,310	4.9	%
	United States Government and
		Agency Securities		-		17,870		-		-		17,870	5.7	%
	Corporate Debt			-		33,652		-		-		33,652	10.8	%
	Foreign Debt			-		7,134		-		-		7,134	2.3	%
	State and Local Government			-		1,861		-		-		1,861	0.6	%
	Other - Asset Backed			-		424		-		-		424	0.1	%
Subtotal - Fixed Income				-		76,251		-		-		76,251	24.4	%

Trust Owned Life Insurance:
	International Equities			-		10,225		-		-		10,225	3.3	%
	United States Bonds			-		34,910		-		-		34,910	11.2	%

Cash and Cash Equivalents				3,718		5,180		-		-		8,898	2.9	%
Other - Pending Transactions and
	Accrued Income (a)			-		-		-		(1,436)		(1,436)	(0.5)	%

Total			$	164,772	$	148,500	$	-	$	(1,436)	$	311,836	100.0	%

277

PSO
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	20,497	$	-	$	-	$	-	$	20,497	24.7	%
	International			22,417		-		-		-		22,417	27.0	%
	Common Collective Trust -
		Global		-		5,844		-		-		5,844	7.0	%
Subtotal - Equities				42,914		5,844		-		-		48,758	58.7	%

Fixed Income:
	Common Collective Trust - Debt			-		4,079		-		-		4,079	4.9	%
	United States Government and
		Agency Securities		-		4,762		-		-		4,762	5.7	%
	Corporate Debt			-		8,967		-		-		8,967	10.8	%
	Foreign Debt			-		1,901		-		-		1,901	2.3	%
	State and Local Government			-		496		-		-		496	0.6	%
	Other - Asset Backed			-		113		-		-		113	0.1	%
Subtotal - Fixed Income				-		20,318		-		-		20,318	24.4	%

Trust Owned Life Insurance:
	International Equities			-		2,724		-		-		2,724	3.3	%
	United States Bonds			-		9,302		-		-		9,302	11.2	%

Cash and Cash Equivalents				991		1,380		-		-		2,371	2.9	%
Other - Pending Transactions and
	Accrued Income (a)			-		-		-		(383)		(383)	(0.5)	%

Total			$	43,905	$	39,568	$	-	$	(383)	$	83,090	100.0	%

278

SWEPCo
													Year End
Asset Class			Level 1		Level 2		Level 3		Other		Total		Allocation
			(in thousands)
Equities:
	Domestic		$	23,770	$	-	$	-	$	-	$	23,770	24.7	%
	International			25,999		-		-		-		25,999	27.0	%
	Common Collective Trust -
		Global		-		6,778		-		-		6,778	7.0	%
Subtotal - Equities				49,769		6,778		-		-		56,547	58.7	%

Fixed Income:
	Common Collective Trust - Debt			-		4,731		-		-		4,731	4.9	%
	United States Government and
		Agency Securities		-		5,522		-		-		5,522	5.7	%
	Corporate Debt			-		10,399		-		-		10,399	10.8	%
	Foreign Debt			-		2,205		-		-		2,205	2.3	%
	State and Local Government			-		575		-		-		575	0.6	%
	Other - Asset Backed			-		131		-		-		131	0.1	%
Subtotal - Fixed Income				-		23,563		-		-		23,563	24.4	%

Trust Owned Life Insurance:
	International Equities			-		3,160		-		-		3,160	3.3	%
	United States Bonds			-		10,788		-		-		10,788	11.2	%

Cash and Cash Equivalents				1,149		1,601		-		-		2,750	2.9	%
Other - Pending Transactions and
	Accrued Income (a)			-		-		-		(444)		(444)	(0.5)	%

Total			$	50,918	$	45,890	$	-	$	(444)	$	96,364	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.

Accumulated Benefit Obligation	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Qualified Pension Plan		$	708,476		$	603,448		$	1,048,796		$	269,738		$	273,860
Nonqualified Pension Plans			191			200			796			1,287			1,098
Total as of December 31, 2012		$	708,667		$	603,648		$	1,049,592		$	271,025		$	274,958

Accumulated Benefit Obligation	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Qualified Pension Plan		$	672,967		$	569,855		$	1,005,608		$	269,230		$	269,809
Nonqualified Pension Plans			234			168			821			1,368			1,223
Total as of December 31, 2011		$	673,201		$	570,023		$	1,006,429		$	270,598		$	271,032

279

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, 2012 and 2011 were as follows:

	APCo				I&M				OPCo				PSO				SWEPCo
	(in thousands)
Projected Benefit Obligation		$	718,460			$	618,973			$	1,068,186			$	279,685			$	1,098

Accumulated Benefit Obligation		$	708,667			$	603,648			$	1,049,592			$	271,025			$	1,098
Fair Value of Plan Assets			621,570				552,026				1,015,115				264,823				-
Underfunded Accumulated Benefit
Obligation as of December 31, 2012		$	(87,097	)		$	(51,622	)		$	(34,477	)		$	(6,202	)		$	(1,098	)

	APCo				I&M				OPCo				PSO				SWEPCo
	(in thousands)
Projected Benefit Obligation		$	681,450			$	581,677			$	1,020,890			$	277,448			$	277,594

Accumulated Benefit Obligation		$	673,201			$	570,023			$	1,006,429			$	270,598			$	271,032
Fair Value of Plan Assets			570,756				503,926				925,939				245,769				255,861
Underfunded Accumulated Benefit
Obligation as of December 31, 2011		$	(102,445	)		$	(66,097	)		$	(80,490	)		$	(24,829	)		$	(15,171	)

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 Subsidiary for 2013:

				Other Postretirement
Company	Pension Plans			Benefit Plans
	(in thousands)
APCo		$	11,883		$	3,079
I&M			14,867			315
OPCo			8,965			1,027
PSO			6,089			-
SWEPCo			11,345			-

280

The tables below reflect the total benefits expected to be paid from the plan or from the Registrant Subsidiary’s assets. The payments include the participants’ contributions to the plan for their share of the cost. In November 2012, changes to the retiree medical coverage were announced. Effective for retirements after December 2012, contributions to retiree medical coverage will be capped reducing exposure to future medical cost inflation. Effective for employees hired after December 2013, retiree medical coverage will not be provided. In December 2011, the prescription drug plan was amended for certain participants. The impact of the changes is reflected in the Benefit Plan Obligation tables as plan amendments. 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	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
2013		$	45,750		$	36,365		$	72,470		$	20,560		$	21,004
2014			47,455			36,958			73,771			21,772			22,223
2015			46,625			38,694			73,945			22,310			22,352
2016			47,604			39,469			75,347			22,297			22,278
2017			48,367			40,350			75,575			22,347			23,162
Years 2018 to 2022, in Total			245,312			213,444			370,934			110,866			114,257

Other Postretirement Benefit Plans:
Benefit Payments	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
2013		$	26,427		$	17,092		$	34,561		$	7,821		$	8,143
2014			27,549			17,999			35,532			8,169			8,748
2015			28,553			19,150			36,755			8,676			9,233
2016			29,738			20,468			38,435			9,239			9,879
2017			30,834			21,549			39,543			9,712			10,582
Years 2018 to 2022, in Total			172,977			127,047			224,357			56,882			64,145

Other Postretirement Benefit Plans:
Medicare Subsidy Receipts	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
2013		$	243		$	25		$	41		$	-		$	-
2014			257			24			47			-			-
2015			269			23			58			-			-
2016			278			23			65			-			-
2017			283			22			76			-			-
Years 2018 to 2022, in Total			1,452			97			599			-			-

281

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost by Registrant Subsidiary for the years ended December 31, 2012, 2011 and 2010:

										Other Postretirement
APCo	Pension Plans									Benefit Plans
	Years Ended December 31,
	2012			2011			2010			2012			2011			2010
	(in thousands)
Service Cost	$	7,565		$	7,199		$	12,908		$	5,387		$	4,983		$	5,722
Interest Cost		30,211			32,293			33,956			18,462			19,468			20,300
Expected Return on Plan Assets		(41,944	)		(41,833	)		(43,805	)		(16,753	)		(17,985	)		(17,628	)
Amortization of Transition Obligation		-			-			-			780			1,167			5,244
Amortization of Prior Service Cost (Credit)		475			917			917			(2,862	)		(171	)		-
Amortization of Net Actuarial Loss		20,339			16,570			11,842			10,526			5,839			5,410
Net Periodic Benefit Cost		16,646			15,146			15,818			15,540			13,301			19,048
Capitalized Portion		(6,525	)		(5,604	)		(6,058	)		(6,092	)		(4,921	)		(7,295	)
Net Periodic Benefit Cost Recognized as
Expense	$	10,121		$	9,542		$	9,760		$	9,448		$	8,380		$	11,753

										Other Postretirement
I&M	Pension Plans									Benefit Plans
	Years Ended December 31,
	2012			2011			2010			2012			2011			2010
	(in thousands)
Service Cost	$	9,908		$	9,447		$	15,284		$	6,621		$	6,119		$	6,750
Interest Cost		26,245			27,726			29,085			12,785			13,610			14,164
Expected Return on Plan Assets		(37,566	)		(36,856	)		(35,040	)		(12,847	)		(13,886	)		(13,397	)
Amortization of Transition Obligation		-			-			-			132			188			2,814
Amortization of Prior Service Cost (Credit)		407			744			744			(2,383	)		(237	)		-
Amortization of Net Actuarial Loss		17,569			14,144			10,065			7,050			3,566			3,526
Net Periodic Benefit Cost		16,563			15,205			20,138			11,358			9,360			13,857
Capitalized Portion		(3,114	)		(3,163	)		(4,028	)		(2,135	)		(1,947	)		(2,771	)
Net Periodic Benefit Cost Recognized as
Expense	$	13,449		$	12,042		$	16,110		$	9,223		$	7,413		$	11,086

										Other Postretirement
OPCo	Pension Plans									Benefit Plans
	Years Ended December 31,
	2012			2011			2010			2012			2011			2010
	(in thousands)
Service Cost	$	11,003		$	10,230		$	17,254		$	8,748		$	7,827		$	8,187
Interest Cost		45,194			48,350			51,900			24,189			25,497			26,498
Expected Return on Plan Assets		(68,401	)		(65,464	)		(69,077	)		(22,555	)		(24,514	)		(24,092	)
Curtailment		-			-			-			-			605			-
Amortization of Transition Obligation		-			-			-			104			150			6,642
Amortization of Prior Service Cost (Credit)		743			1,474			1,474			(3,873	)		(212	)		-
Amortization of Net Actuarial Loss		30,439			24,828			18,150			13,669			7,298			6,877
Net Periodic Benefit Cost		18,978			19,418			19,701			20,282			16,651			24,112
Capitalized Portion		(7,060	)		(6,932	)		(6,843	)		(7,545	)		(5,944	)		(8,334	)
Net Periodic Benefit Cost Recognized as
Expense	$	11,918		$	12,486		$	12,858		$	12,737		$	10,707		$	15,778

282

										Other Postretirement
PSO	Pension Plans									Benefit Plans
	Years Ended December 31,
	2012			2011			2010			2012			2011			2010
	(in thousands)
Service Cost	$	5,951		$	5,760		$	6,052		$	2,836		$	2,621		$	2,815
Interest Cost		12,301			13,285			14,888			5,797			6,046			6,360
Expected Return on Plan Assets		(18,015	)		(17,464	)		(19,739	)		(5,922	)		(6,264	)		(6,110	)
Amortization of Transition Obligation		-			-			-			-			-			2,805
Amortization of Prior Service Credit		(948	)		(950	)		(950	)		(1,079	)		(75	)		-
Amortization of Net Actuarial Loss		8,206			6,757			5,188			3,189			1,553			1,573
Net Periodic Benefit Cost		7,495			7,388			5,439			4,821			3,881			7,443
Capitalized Portion		(2,533	)		(2,379	)		(1,806	)		(1,629	)		(1,249	)		(2,471	)
Net Periodic Benefit Cost Recognized as
Expense	$	4,962		$	5,009		$	3,633		$	3,192		$	2,632		$	4,972

										Other Postretirement
SWEPCo	Pension Plans									Benefit Plans
	Years Ended December 31,
	2012			2011			2010			2012			2011			2010
	(in thousands)
Service Cost	$	7,099		$	6,573		$	7,046		$	3,324		$	3,029		$	3,108
Interest Cost		12,537			13,331			15,093			6,673			6,969			6,940
Expected Return on Plan Assets		(18,866	)		(18,380	)		(19,489	)		(6,795	)		(7,200	)		(6,646	)
Amortization of Transition Obligation		-			-			-			-			-			2,461
Amortization of Prior Service Cost (Credit)		(793	)		(795	)		(796	)		(933	)		258			-
Amortization of Net Actuarial Loss		8,330			6,759			5,242			3,659			1,785			1,711
Net Periodic Benefit Cost		8,307			7,488			7,096			5,928			4,841			7,574
Capitalized Portion		(2,924	)		(2,636	)		(2,406	)		(2,087	)		(1,704	)		(2,568	)
Net Periodic Benefit Cost Recognized as
Expense	$	5,383		$	4,852		$	4,690		$	3,841		$	3,137		$	5,006

283

Estimated amounts expected to be amortized to net periodic benefit costs (credits) and the impact on each Registrant Subsidiary’s balance sheet during 2013 are shown in the following tables:

	APCo		I&M		OPCo		PSO		SWEPCo
Pension Plan - Components	(in thousands)
Net Actuarial Loss	$	24,305	$	20,939	$	36,137	$	9,464	$	9,662
Prior Service Cost		198		195		283		297		350
Total Estimated 2013 Amortization	$	24,503	$	21,134	$	36,420	$	9,761	$	10,012

Pension Plans -
Expected to be Recorded as
Regulatory Asset	$	24,367	$	19,852	$	19,387	$	9,761	$	10,012
Deferred Income Taxes		48		449		5,962		-		-
Net of Tax AOCI		88		833		11,071		-		-
Total	$	24,503	$	21,134	$	36,420	$	9,761	$	10,012

	APCo			I&M			OPCo			PSO			SWEPCo
Other Postretirement Benefit Plans -	(in thousands)
Components
Net Actuarial Loss	$	12,114		$	7,624		$	16,198		$	3,480		$	3,838
Prior Service Credit		(10,050	)		(9,421	)		(12,922	)		(4,290	)		(5,155	)
Total Estimated 2013 Amortization	$	2,064		$	(1,797	)	$	3,276		$	(810	)	$	(1,317	)

Other Postretirement Benefit Plans - Expected to be Recorded as
Regulatory Asset	$	99	$	(1,767	)	$	599	$	(810	)	$	(899	)
Deferred Income Taxes		688		(10	)		937		-			(146	)
Net of Tax AOCI		1,277		(20	)		1,740		-			(272	)
Total	$	2,064	$	(1,797	)	$	3,276	$	(810	)	$	(1,317	)

American Electric Power System Retirement Savings Plans

The Registrant Subsidiaries participate in an AEP sponsored defined contribution retirement savings plan, the American Electric Power System Retirement Savings Plan, for substantially all employees who are not members 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 Subsidiary for the years ended December 31, 2012, 2011 and 2010:

	Years Ended December 31,
Company	2012			2011			2010
	(in thousands)
APCo		$	7,579		$	7,432		$	7,284
I&M			9,706			9,541			8,969
OPCo			10,798			10,166			9,706
PSO			3,732			3,626			3,505
SWEPCo			4,890			4,438			3,866

284

UMWA Benefits

APCo, I&M and OPCo provide UMWA pension, health and welfare benefits for certain unionized mining employees, retirees and their survivors who meet eligibility requirements. UMWA trustees make final interpretive determinations with regard to all benefits. The pension benefits are administered by UMWA trustees and contributions are made to their trust funds. APCo, I&M and OPCo administer the health and welfare benefits and pay them from their general assets.

The UMWA pension benefits are administered through a multiemployer plan that 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 the unfunded plan obligations, while a withdrawing employer may be subject to a withdrawal liability. UMWA pension benefits are provided through the United Mine Workers of America 1974 Pension Plan (Employer Identification Number: 52-1050282, Plan Number 002), which under the Pension Protection Act of 2006 (PPA) was in Seriously Endangered Status for the plan years ending June 30, 2012 and 2011, without utilization of extended amortization provisions. The Plan adopted a funding improvement plan in May 2012, as required under the PPA. Contributions in 2012, 2011 and 2010 were made under a collective bargaining agreement that is scheduled to expire December 31, 2013, were immaterial and represent less than 5% of the total contributions in the plan’s latest annual report for the years ended June 30, 2012, 2011 and 2010. The contributions did not include a surcharge. There are no minimum contributions for future years.

7. BUSINESS SEGMENTS

The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

8. DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

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

285

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

The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of December 31, 2012 and 2011:

Notional Volume of Derivative Instruments
December 31, 2012

Primary Risk	Unit of
Exposure	Measure	APCo		I&M		OPCo		PSO		SWEPCo

		(in thousands)
Commodity:
Power	MWhs		94,059		64,791		132,188		-		-
Coal	Tons		1,401		2,711		3,033		1,980		1,312
Natural Gas	MMBtus		10,077		6,922		14,163		-		-
Heating Oil and
Gasoline	Gallons		1,050		532		1,260		616		585
Interest Rate	USD	$	24,146	$	16,584	$	33,934	$	-	$	-

Interest Rate and
Foreign Currency	USD	$	-	$	200,000	$	-	$	-	$	-

Notional Volume of Derivative Instruments
December 31, 2011

Primary Risk	Unit of
Exposure	Measure	APCo		I&M		OPCo		PSO		SWEPCo

		(in thousands)
Commodity:
Power	MWhs		169,459		109,326		229,468		39		49
Coal	Tons		3,714		1,920		8,337		3,574		2,974
Natural Gas	MMBtus		7,923		5,081		10,728		115		145
Heating Oil and
Gasoline	Gallons		1,057		525		1,254		618		569
Interest Rate	USD	$	31,029	$	19,890	$	42,093	$	175	$	203

Interest Rate and
Foreign Currency	USD	$	-	$	200,000	$	-	$	-	$	200,069

Fair Value Hedging Strategies

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

286

Cash Flow Hedging Strategies

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

The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. For disclosure purposes, these contracts are included with other hedging activities as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk.

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

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

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

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

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

287

According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the December 31, 2012 and 2011 balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

	December 31,
	2012						2011
	Cash Collateral			Cash Collateral			Cash Collateral			Cash Collateral
	Received			Paid			Received			Paid
	Netted Against			Netted Against			Netted Against			Netted Against
	Risk Management			Risk Management			Risk Management			Risk Management
Company	Assets			Liabilities			Assets			Liabilities
	(in thousands)
APCo		$	1,262		$	11,029		$	4,291		$	28,964
I&M			867			7,576			2,752			18,547
OPCo			1,774			15,500			5,810			39,183
PSO			-			-			53			130
SWEPCo			-			-			66			124

288

The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the balance sheets as of December 31, 2012 and 2011:

Fair Value of Derivative Instruments
December 31, 2012

APCo
		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (d)
		(in thousands)
Current Risk Management Assets		$	127,645	$	338	$	-	$	127,983	$	(97,023)	$	30,960
Long-term Risk Management Assets			60,498		215		-		60,713		(26,353)		34,360
Total Assets			188,143		553		-		188,696		(123,376)		65,320

Current Risk Management Liabilities			119,430		1,182		-		120,612		(103,914)		16,698
Long-term Risk Management Liabilities			47,281		424		-		47,705		(29,229)		18,476
Total Liabilities			166,711		1,606		-		168,317		(133,143)		35,174

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	21,432	$	(1,053)	$	-	$	20,379	$	9,767	$	30,146

Fair Value of Derivative Instruments
December 31, 2011

APCo

		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (c)		Position (d)
		(in thousands)
Current Risk Management Assets		$	232,784	$	1,040	$	-	$	233,824	$	(194,179)	$	39,645
Long-term Risk Management Assets			99,751		90		-		99,841		(60,615)		39,226
Total Assets			332,535		1,130		-		333,665		(254,794)		78,871

Current Risk Management Liabilities			235,354		2,767		-		238,121		(211,515)		26,606
Long-term Risk Management Liabilities			82,058		350		-		82,408		(69,485)		12,923
Total Liabilities			317,412		3,117		-		320,529		(281,000)		39,529

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	15,123	$	(1,987)	$	-	$	13,136	$	26,206	$	39,342

289

Fair Value of Derivative Instruments
December 31, 2012

I&M
		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (d)
		(in thousands)
Current Risk Management Assets		$	93,268	$	220	$	-	$	93,488	$	(66,514)	$	26,974
Long-term Risk Management Assets			41,553		148		-		41,701		(18,132)		23,569
Total Assets			134,821		368		-		135,189		(84,646)		50,543

Current Risk Management Liabilities			82,433		807		19,524		102,764		(71,247)		31,517
Long-term Risk Management Liabilities			33,714		292		-		34,006		(20,108)		13,898
Total Liabilities			116,147		1,099		19,524		136,770		(91,355)		45,415

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	18,674	$	(731)	$	(19,524)	$	(1,581)	$	6,709	$	5,128

Fair Value of Derivative Instruments
December 31, 2011

I&M
		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (c)		Position (d)
		(in thousands)
Current Risk Management Assets		$	154,628	$	667	$	-	$	155,295	$	(123,143)	$	32,152
Long-term Risk Management Assets			68,047		58		-		68,105		(38,743)		29,362
Total Assets			222,675		725		-		223,400		(161,886)		61,514

Current Risk Management Liabilities			149,466		1,747		-		151,213		(134,233)		16,980
Long-term Risk Management Liabilities			52,441		224		10,637		63,302		(44,431)		18,871
Total Liabilities			201,907		1,971		10,637		214,515		(178,664)		35,851

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	20,768	$	(1,246)	$	(10,637)	$	8,885	$	16,778	$	25,663

290

Fair Value of Derivative Instruments
December 31, 2012

OPCo
		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (d)
		(in thousands)
Current Risk Management Assets		$	183,064	$	464	$	-	$	183,528	$	(139,215)	$	44,313
Long-term Risk Management Assets			85,023		303		-		85,326		(37,038)		48,288
Total Assets			268,087		767		-		268,854		(176,253)		92,601

Current Risk Management Liabilities			171,397		1,658		-		173,055		(148,900)		24,155
Long-term Risk Management Liabilities			66,448		596		-		67,044		(41,079)		25,965
Total Liabilities			237,845		2,254		-		240,099		(189,979)		50,120

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	30,242	$	(1,487)	$	-	$	28,755	$	13,726	$	42,481

Fair Value of Derivative Instruments
December 31, 2011

OPCo
		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (c)		Position (d)
		(in thousands)
Current Risk Management Assets		$	325,904	$	1,409	$	-	$	327,313	$	(273,020)	$	54,293
Long-term Risk Management Assets			136,519		122		-		136,641		(83,027)		53,614
Total Assets			462,423		1,531		-		463,954		(356,047)		107,907

Current Risk Management Liabilities			329,307		3,712		-		333,019		(296,458)		36,561
Long-term Risk Management Liabilities			112,454		474		-		112,928		(95,038)		17,890
Total Liabilities			441,761		4,186		-		445,947		(391,496)		54,451

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	20,662	$	(2,655)	$	-	$	18,007	$	35,449	$	53,456

291

Fair Value of Derivative Instruments
December 31, 2012

PSO
		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (d)
		(in thousands)
Current Risk Management Assets		$	1,657	$	42	$	-	$	1,699	$	(1,190)	$	509
Long-term Risk Management Assets			-		-		-		-		31		31
Total Assets			1,657		42		-		1,699		(1,159)		540

Current Risk Management Liabilities			7,021		17		-		7,038		(1,190)		5,848
Long-term Risk Management Liabilities			-		-		-		-		31		31
Total Liabilities			7,021		17		-		7,038		(1,159)		5,879

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(5,364)	$	25	$	-	$	(5,339)	$	-	$	(5,339)

Fair Value of Derivative Instruments
December 31, 2011

PSO
		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (c)		Position (d)
		(in thousands)
Current Risk Management Assets		$	6,980	$	-	$	-	$	6,980	$	(6,415)	$	565
Long-term Risk Management Assets			914		-		-		914		(600)		314
Total Assets			7,894		-		-		7,894		(7,015)		879

Current Risk Management Liabilities			7,665		107		-		7,772		(6,492)		1,280
Long-term Risk Management Liabilities			1,930		-		-		1,930		(600)		1,330
Total Liabilities			9,595		107		-		9,702		(7,092)		2,610

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(1,701)	$	(107)	$	-	$	(1,808)	$	77	$	(1,731)

292

Fair Value of Derivative Instruments
December 31, 2012

SWEPCo
		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (b)		Position (d)
		(in thousands)
Current Risk Management Assets		$	2,804	$	41	$	-	$	2,845	$	(2,150)	$	695
Long-term Risk Management Assets			-		-		-		-		-		-
Total Assets			2,804		41		-		2,845		(2,150)		695

Current Risk Management Liabilities			3,261		17		-		3,278		(2,150)		1,128
Long-term Risk Management Liabilities			-		-		-		-		-		-
Total Liabilities			3,261		17		-		3,278		(2,150)		1,128

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(457)	$	24	$	-	$	(433)	$	-	$	(433)

Fair Value of Derivative Instruments
December 31, 2011

SWEPCo
		Risk						Gross Amounts		Gross		Net Amounts of
		Management						of Risk		Amounts		Assets/Liabilities
		Contracts		Hedging Contracts				Management		Offset in the		Presented in the
						Interest Rate		Assets/		Statement of		Statement of
						and Foreign		Liabilities		Financial		Financial
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Recognized		Position (c)		Position (d)
		(in thousands)
Current Risk Management Assets		$	6,327	$	-	$	3	$	6,330	$	(5,885)	$	445
Long-term Risk Management Assets			818		-		-		818		(536)		282
Total Assets			7,145		-		3		7,148		(6,421)		727

Current Risk Management Liabilities			11,062		97		19,143		30,302		(5,943)		24,359
Long-term Risk Management Liabilities			757		-		-		757		(536)		221
Total Liabilities			11,819		97		19,143		31,059		(6,479)		24,580

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(4,674)	$	(97)	$	(19,140)	$	(23,911)	$	58	$	(23,853)

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

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

293

The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the years ended December 31, 2012, 2011 and 2010:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
Year Ended December 31, 2012

Location of Gain (Loss)		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	(1,149)	$	11,437	$	11,978	$	163	$	398
Sales to AEP Affiliates			-		-		-		-		-
Fuel and Other Consumables Used for
	Electric Generation		-		-		-		-		-
Regulatory Assets (a)			(7,835)		(9,204)		(14,104)		(5,304)		(6,274)
Regulatory Liabilities (a)			7,314		(889)		-		(19)		(13)
Total Gain (Loss) on Risk Management
	Contracts	$	(1,670)	$	1,344	$	(2,126)	$	(5,160)	$	(5,889)

Amount of Gain (Loss) Recognized on
Risk Management Contracts
Year Ended December 31, 2011

Location of Gain (Loss)		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	2,843	$	12,786	$	27,292	$	297	$	547
Sales to AEP Affiliates			154		92		196		3		4
Fuel and Other Consumables Used for
	Electric Generation		-		-		(2)		-		-
Regulatory Assets (a)			373		(1,470)		(17,928)		(1,421)		(1,709)
Regulatory Liabilities (a)			2,552		(5,178)		(105)		708		(118)
Total Gain (Loss) on Risk Management
	Contracts	$	5,922	$	6,230	$	9,453	$	(413)	$	(1,276)

Amount of Gain (Loss) Recognized on
Risk Management Contracts
Year Ended December 31, 2010

Location of Gain (Loss)		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	5,057	$	21,834	$	40,893	$	3,156	$	3,880
Sales to AEP Affiliates			(2,379)		(2,471)		5,043		(794)		(1,523)
Fuel and Other Consumables Used for
	Electric Generation		-		-		-		-		-
Regulatory Assets (a)			(372)		(186)		(5,788)		46		(2,902)
Regulatory Liabilities (a)			27,790		8,217		3,451		878		351
Total Gain (Loss) on Risk Management
	Contracts	$	30,096	$	27,394	$	43,599	$	3,286	$	(194)

(a)

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

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

294

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. However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

Accounting for Fair Value Hedging Strategies

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

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. During 2012, 2011 and 2010, the Registrant Subsidiaries did not employ any fair value hedging strategies.

Accounting for Cash Flow Hedging Strategies

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

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the 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 2012, 2011 and 2010, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the 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 2012, 2011 and 2010, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During 2012, I&M and SWEPCo designated interest rate derivatives as cash flow hedges. During 2011, APCo, I&M and SWEPCo designated interest rate derivatives as cash flow hedges. During 2010, APCo and PSO designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the 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 2012, 2011 and 2010, SWEPCo designated foreign currency derivatives as cash flow hedges.

During 2012, 2011 and 2010, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

295

The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges for the years ended December 31, 2012, 2011 and 2010. All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Year Ended December 31, 2012

Commodity Contracts	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2011	$	(1,309	)	$	(819	)	$	(1,748	)	$	(69	)	$	(62	)
Changes in Fair Value Recognized in AOCI		(1,310	)		(987	)		(2,002	)		104			100
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Electric Generation, Transmission and
Distribution Revenues		(16	)		(43	)		(109	)		-			-
Fuel and Other Consumables Used for
Electric Generation		-			-			-			-			-
Purchased Electricity for Resale		440			1,151			3,002			-			-
Other Operation Expense		(25	)		(14	)		(35	)		(14	)		(11	)
Maintenance Expense		-			(2	)		(5	)		1			-
Property, Plant and Equipment		(14	)		(10	)		(15	)		(1	)		(5	)
Regulatory Assets (a)		1,590			278			-			-			-
Regulatory Liabilities (a)		-			-			-			-			-
Balance in AOCI as of December 31, 2012	$	(644	)	$	(446	)	$	(912	)	$	21		$	22

Interest Rate and
Foreign Currency Contracts	APCo		I&M			OPCo			PSO			SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2011	$	1,024	$	(14,465	)	$	9,454		$	7,218		$	(15,462	)
Changes in Fair Value Recognized in AOCI		-		(5,777	)		-			-			(2,778	)
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Other Operation Expense		-		-			-			-			-
Depreciation and Amortization
Expense		-		-			4			-			-
Interest Expense		1,053		595			(1,363	)		(758	)		2,669
Balance in AOCI as of December 31, 2012	$	2,077	$	(19,647	)	$	8,095		$	6,460		$	(15,571	)

Total Contracts	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2011	$	(285	)	$	(15,284	)	$	7,706		$	7,149		$	(15,524	)
Changes in Fair Value Recognized in AOCI		(1,310	)		(6,764	)		(2,002	)		104			(2,678	)
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Electric Generation, Transmission and
Distribution Revenues		(16	)		(43	)		(109	)		-			-
Fuel and Other Consumables Used for
Electric Generation		-			-			-			-			-
Purchased Electricity for Resale		440			1,151			3,002			-			-
Other Operation Expense		(25	)		(14	)		(35	)		(14	)		(11	)
Maintenance Expense		-			(2	)		(5	)		1			-
Depreciation and Amortization
Expense		-			-			4			-			-
Interest Expense		1,053			595			(1,363	)		(758	)		2,669
Property, Plant and Equipment		(14	)		(10	)		(15	)		(1	)		(5	)
Regulatory Assets (a)		1,590			278			-			-			-
Regulatory Liabilities (a)		-			-			-			-			-
Balance in AOCI as of December 31, 2012	$	1,433		$	(20,093	)	$	7,183		$	6,481		$	(15,549	)

296

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Year Ended December 31, 2011

Commodity Contracts	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2010	$	(273	)	$	(178	)	$	(364	)	$	88		$	82
Changes in Fair Value Recognized in AOCI		(2,077	)		(1,294	)		(2,748	)		108			102
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Electric Generation, Transmission and
Distribution Revenues		249			544			1,457			-			-
Fuel and Other Consumables Used for
Electric Generation		-			-			-			-			-
Purchased Electricity for Resale		62			79			425			-			-
Other Operation Expense		(95	)		(71	)		(160	)		(93	)		(93	)
Maintenance Expense		(169	)		(64	)		(141	)		(62	)		(65	)
Property, Plant and Equipment		(175	)		(90	)		(217	)		(110	)		(88	)
Regulatory Assets (a)		1,169			255			-			-			-
Regulatory Liabilities (a)		-			-			-			-			-
Balance in AOCI as of December 31, 2011	$	(1,309	)	$	(819	)	$	(1,748	)	$	(69	)	$	(62	)

Interest Rate and
Foreign Currency Contracts	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2010	$	217		$	(8,507	)	$	10,813		$	8,406		$	(4,272	)
Changes in Fair Value Recognized in AOCI		(373	)		(6,913	)		-			(475	)		(12,438	)
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Other Operation Expense		-			-			-			-			-
Depreciation and Amortization
Expense		-			-			4			-			-
Interest Expense		1,180			955			(1,363	)		(713	)		1,248
Balance in AOCI as of December 31, 2011	$	1,024		$	(14,465	)	$	9,454		$	7,218		$	(15,462	)

Total Contracts	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2010	$	(56	)	$	(8,685	)	$	10,449		$	8,494		$	(4,190	)
Changes in Fair Value Recognized in AOCI		(2,450	)		(8,207	)		(2,748	)		(367	)		(12,336	)
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Electric Generation, Transmission and
Distribution Revenues		249			544			1,457			-			-
Fuel and Other Consumables Used for
Electric Generation		-			-			-			-			-
Purchased Electricity for Resale		62			79			425			-			-
Other Operation Expense		(95	)		(71	)		(160	)		(93	)		(93	)
Maintenance Expense		(169	)		(64	)		(141	)		(62	)		(65	)
Depreciation and Amortization
Expense		-			-			4			-			-
Interest Expense		1,180			955			(1,363	)		(713	)		1,248
Property, Plant and Equipment		(175	)		(90	)		(217	)		(110	)		(88	)
Regulatory Assets (a)		1,169			255			-			-			-
Regulatory Liabilities (a)		-			-			-			-			-
Balance in AOCI as of December 31, 2011	$	(285	)	$	(15,284	)	$	7,706		$	7,149		$	(15,524	)

297

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Year Ended December 31, 2010

Commodity Contracts	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2009	$	(743	)	$	(382	)	$	(742	)	$	(78	)	$	112
Changes in Fair Value Recognized in AOCI		(1,450	)		(901	)		(1,958	)		77			69
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Electric Generation, Transmission and
Distribution Revenues		51			87			229			-			-
Fuel and Other Consumables Used for
Electric Generation		-			-			(13	)		197			-
Purchased Electricity for Resale		393			895			2,338			-			-
Other Operation Expense		(43	)		(31	)		(72	)		(39	)		(44	)
Maintenance Expense		(70	)		(28	)		(54	)		(24	)		(23	)
Property, Plant and Equipment		(71	)		(36	)		(87	)		(45	)		(32	)
Regulatory Assets (a)		1,660			218			-			-			-
Regulatory Liabilities (a)		-			-			(5	)		-			-
Balance in AOCI as of December 31, 2010	$	(273	)	$	(178	)	$	(364	)	$	88		$	82

Interest Rate and
Foreign Currency Contracts	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2009	$	(6,450	)	$	(9,514	)	$	12,172		$	(521	)	$	(5,047	)
Changes in Fair Value Recognized in AOCI		5,042			-			-			8,813			(74	)
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Other Operation Expense		-			-			-			-			21
Depreciation and Amortization
Expense		-			-			4			-			-
Interest Expense		1,625			1,007			(1,363	)		114			828
Balance in AOCI as of December 31, 2010	$	217		$	(8,507	)	$	10,813		$	8,406		$	(4,272	)

Total Contracts	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Balance in AOCI as of December 31, 2009	$	(7,193	)	$	(9,896	)	$	11,430		$	(599	)	$	(4,935	)
Changes in Fair Value Recognized in AOCI		3,592			(901	)		(1,958	)		8,890			(5	)
Amount of (Gain) or Loss Reclassified
from AOCI to Statement of Income/within
Balance Sheet:
Electric Generation, Transmission and
Distribution Revenues		51			87			229			-			-
Fuel and Other Consumables Used for
Electric Generation		-			-			(13	)		197			-
Purchased Electricity for Resale		393			895			2,338			-			-
Other Operation Expense		(43	)		(31	)		(72	)		(39	)		(23	)
Maintenance Expense		(70	)		(28	)		(54	)		(24	)		(23	)
Depreciation and Amortization
Expense		-			-			4			-			-
Interest Expense		1,625			1,007			(1,363	)		114			828
Property, Plant and Equipment		(71	)		(36	)		(87	)		(45	)		(32	)
Regulatory Assets (a)		1,660			218			-			-			-
Regulatory Liabilities (a)		-			-			(5	)		-			-
Balance in AOCI as of December 31, 2010	$	(56	)	$	(8,685	)	$	10,449		$	8,494		$	(4,190	)

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

298

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets as of December 31, 2012 and 2011 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Balance Sheets
December 31, 2012

	Hedging Assets (a)				Hedging Liabilities (a)				AOCI Gain (Loss) Net of Tax
			Interest Rate				Interest Rate				Interest Rate
			and Foreign				and Foreign				and Foreign
Company	Commodity		Currency		Commodity		Currency		Commodity		Currency
	(in thousands)
APCo	$	302	$	-	$	1,355	$	-	$	(644)	$	2,077
I&M		200		-		931		19,524		(446)		(19,647)
OPCo		416		-		1,903		-		(912)		8,095
PSO		25		-		-		-		21		6,460
SWEPCo		24		-		-		-		22		(15,571)

	Expected to be Reclassified to
	Net Income During the Next
	Twelve Months
					Maximum Term for
			Interest Rate		Exposure to
			and Foreign		Variability of Future
Company	Commodity		Currency		Cash Flows
	(in thousands)				(in months)
APCo	$	(507)	$	(1,013)		17
I&M		(355)		(1,600)		17
OPCo		(720)		1,359		17
PSO		21		759		12
SWEPCo		22		(2,267)		12

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Balance Sheets
December 31, 2011

	Hedging Assets (a)				Hedging Liabilities (a)				AOCI Gain (Loss) Net of Tax
			Interest Rate				Interest Rate				Interest Rate
			and Foreign				and Foreign				and Foreign
Company	Commodity		Currency		Commodity		Currency		Commodity		Currency
	(in thousands)
APCo	$	431	$	-	$	2,418	$	-	$	(1,309)	$	1,024
I&M		277		-		1,523		10,637		(819)		(14,465)
OPCo		584		-		3,239		-		(1,748)		9,454
PSO		-		-		107		-		(69)		7,218
SWEPCo		-		3		97		19,143		(62)		(15,462)

	Expected to be Reclassified to
	Net Income During the Next
	Twelve Months
			Interest Rate
			and Foreign
Company	Commodity		Currency
	(in thousands)
APCo	$	(1,140)	$	(1,052)
I&M		(712)		(595)
OPCo		(1,518)		1,359
PSO		(70)		759
SWEPCo		(63)		(1,864)

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

299

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

Credit Risk

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

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

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries’ fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of December 31, 2012 and 2011:

	December 31, 2012
	Liabilities for		Amount of Collateral the		Amount
	Derivative Contracts		Registrant Subsidiaries		Attributable to
	with Credit		Would Have Been		RTO and ISO
Company	Downgrade Triggers		Required to Post		Activities
	(in thousands)
APCo	$	2,159	$	3,699	$	3,510
I&M		1,483		2,540		2,411
OPCo		3,034		5,198		4,933
PSO		-		1,509		1,429
SWEPCo		-		1,778		1,683

	December 31, 2011
	Liabilities for		Amount of Collateral the		Amount
	Derivative Contracts		Registrant Subsidiaries		Attributable to
	with Credit		Would Have Been		RTO and ISO
Company	Downgrade Triggers		Required to Post		Activities
	(in thousands)
APCo	$	10,007	$	6,211	$	6,211
I&M		6,418		3,983		3,983
OPCo		13,550		8,410		8,410
PSO		-		856		414
SWEPCo		-		1,128		522

As of December 31, 2012 and 2011, the Registrant Subsidiaries were not required to post any collateral.

300

In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of December 31, 2012 and 2011:

	December 31, 2012
	Liabilities for				Additional
	Contracts with Cross				Settlement
	Default Provisions				Liability if Cross
	Prior to Contractual		Amount of Cash		Default Provision
Company	Netting Arrangements		Collateral Posted		is Triggered
	(in thousands)
APCo	$	49,465	$	1,822	$	30,160
I&M		53,499		1,252		40,240
OPCo		69,516		2,561		42,386
PSO		-		-		-
SWEPCo		-		-		-

	December 31, 2011
	Liabilities for				Additional
	Contracts with Cross				Settlement
	Default Provisions				Liability if Cross
	Prior to Contractual		Amount of Cash		Default Provision
Company	Netting Arrangements		Collateral Posted		is Triggered
	(in thousands)
APCo	$	76,868	$	8,107	$	27,603
I&M		59,936		5,200		28,339
OPCo		104,091		10,978		37,380
PSO		142		-		61
SWEPCo		19,322		-		19,220

9. FAIR VALUE MEASUREMENTS

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 Registrant Subsidiaries as of December 31, 2012 and 2011 are summarized in the following table:

	December 31,
	2012				2011
Company	Book Value		Fair Value		Book Value		Fair Value
	(in thousands)
APCo	$	3,702,442	$	4,555,143	$	3,726,251	$	4,431,912
I&M		2,057,666		2,372,017		2,057,675		2,339,344
OPCo		3,860,440		4,560,337		4,054,148		4,665,739
PSO		949,871		1,175,759		947,364		1,123,306
SWEPCo		2,046,228		2,400,509		1,728,637		2,019,094

301

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF 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, 2012 and 2011:

		December 31,
		2012						2011
		Estimated		Gross		Other-Than-		Estimated		Gross		Other-Than-
		Fair		Unrealized		Temporary		Fair		Unrealized		Temporary
		Value		Gains		Impairments		Value		Gains		Impairments
		(in thousands)
Cash and Cash Equivalents		$	16,783	$	-	$	-	$	18,229	$	-	$	-
Fixed Income Securities:
	United States Government		647,918		58,268		(747)		543,506		60,946		(547)
	Corporate Debt		35,399		4,903		(1,352)		53,979		4,932		(1,536)
	State and Local Government		270,090		1,006		(863)		329,986		(430)		(2,236)
	Subtotal Fixed Income Securities		953,407		64,177		(2,962)		927,471		65,448		(4,319)
Equity Securities - Domestic			735,582		284,599		(76,557)		646,032		214,748		(79,536)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,705,772	$	348,776	$	(79,519)	$	1,591,732	$	280,196	$	(83,855)

The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2012, 2011 and 2010:

	Years Ended December 31,
	2012		2011		2010
	(in thousands)
Proceeds from Investment Sales	$	987,550	$	1,110,909	$	1,361,813
Purchases of Investments		1,045,422		1,166,690		1,414,473
Gross Realized Gains on Investment Sales		24,605		33,382		11,570
Gross Realized Losses on Investment Sales		8,881		22,159		2,087

The adjusted cost of debt securities was $889 million and $862 million as of December 31, 2012 and 2011, respectively. The adjusted cost of equity securities was $451 million and $431 million as of December 31, 2012 and 2011, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2012 was as follows:

	Fair Value
	of Debt
	Securities
	(in thousands)
Within 1 year	$	80,993
1 year – 5 years		373,532
5 years – 10 years		265,885
After 10 years		232,997
Total	$	953,407

302

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 Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2012 and 2011. 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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2012
APCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)		$	4,161	$	166,916	$	17,058	$	(123,117)	$	65,018
Cash Flow Hedges:
	Commodity Hedges (a)		-		498		-		(196)		302
Total Risk Management Assets		$	4,161	$	167,414	$	17,058	$	(123,313)	$	65,320

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	1,959	$	158,665	$	6,079	$	(132,884)	$	33,819
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,551		-		(196)		1,355
Total Risk Management Liabilities		$	1,959	$	160,216	$	6,079	$	(133,080)	$	35,174

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2011
APCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)		$	4,680	$	302,128	$	25,423	$	(255,324)	$	76,907
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,095		-		(664)		431
De-designated Risk Management Contracts (c)			-		-		-		1,533		1,533
Total Risk Management Assets		$	4,680	$	303,223	$	25,423	$	(254,455)	$	78,871

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	2,535	$	291,194	$	23,379	$	(279,997)	$	37,111
Cash Flow Hedges:
	Commodity Hedges (a)		-		3,009		73		(664)		2,418
Total Risk Management Liabilities		$	2,535	$	294,203	$	23,452	$	(280,661)	$	39,529

303

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2012
I&M
			Level 1		Level 2		Level 3		Other		Total
Assets:			(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)			$	2,858	$	120,242	$	11,717	$	(84,474)	$	50,343
Cash Flow Hedges:
	Commodity Hedges (a)			-		330		-		(130)		200
Total Risk Management Assets				2,858		120,572		11,717		(84,604)		50,543

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (d)				6,508		-		-		10,275		16,783
Fixed Income Securities:
	United States Government			-		647,918		-		-		647,918
	Corporate Debt			-		35,399		-		-		35,399
	State and Local Government			-		270,090		-		-		270,090
		Subtotal Fixed Income Securities		-		953,407		-		-		953,407
Equity Securities - Domestic (e)				735,582		-		-		-		735,582
Total Spent Nuclear Fuel and Decommissioning Trusts				742,090		953,407		-		10,275		1,705,772

Total Assets			$	744,948	$	1,073,979	$	11,717	$	(74,329)	$	1,756,315

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)			$	1,346	$	110,621	$	4,176	$	(91,183)	$	24,960
Cash Flow Hedges:
	Commodity Hedges (a)			-		1,061		-		(130)		931
	Interest Rate/Foreign Currency Hedges			-		19,524		-		-		19,524
Total Risk Management Liabilities			$	1,346	$	131,206	$	4,176	$	(91,313)	$	45,415

304

		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		December 31, 2011
I&M
			Level 1		Level 2		Level 3		Other		Total
Assets:			(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)			$	3,001	$	203,175	$	16,305	$	(162,227)	$	60,254
Cash Flow Hedges:
	Commodity Hedges (a)			-		702		-		(425)		277
De-designated Risk Management Contracts (c)				-		-		-		983		983
Total Risk Management Assets				3,001		203,877		16,305		(161,669)		61,514

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (d)				-		5,431		-		12,798		18,229
Fixed Income Securities:
	United States Government			-		543,506		-		-		543,506
	Corporate Debt			-		53,979		-		-		53,979
	State and Local Government			-		329,986		-		-		329,986
		Subtotal Fixed Income Securities		-		927,471		-		-		927,471
Equity Securities - Domestic (e)				646,032		-		-		-		646,032
Total Spent Nuclear Fuel and Decommissioning Trusts				646,032		932,902		-		12,798		1,591,732

Total Assets			$	649,033	$	1,136,779	$	16,305	$	(148,871)	$	1,653,246

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)			$	1,626	$	185,092	$	14,995	$	(178,022)	$	23,691
Cash Flow Hedges:
	Commodity Hedges (a)			-		1,901		47		(425)		1,523
	Interest Rate/Foreign Currency Hedges			-		10,637		-		-		10,637
Total Risk Management Liabilities			$	1,626	$	197,630	$	15,042	$	(178,447)	$	35,851

305

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2012
OPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Other Cash Deposits (f)		$	-	$	26	$	-	$	39	$	65

Risk Management Assets
Risk Management Commodity Contracts (a) (b)			5,848		238,254		23,973		(175,890)		92,185
Cash Flow Hedges:
	Commodity Hedges (a)		-		688		-		(272)		416
Total Risk Management Assets			5,848		238,942		23,973		(176,162)		92,601

Total Assets		$	5,848	$	238,968	$	23,973	$	(176,123)	$	92,666

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	2,753	$	226,536	$	8,544	$	(189,616)	$	48,217
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,175		-		(272)		1,903
Total Risk Management Liabilities		$	2,753	$	228,711	$	8,544	$	(189,888)	$	50,120

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2011
OPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Other Cash Deposits (f)		$	26	$	-	$	-	$	22	$	48

Risk Management Assets
Risk Management Commodity Contracts (a) (b)			6,339		421,249		34,425		(356,766)		105,247
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,483		-		(899)		584
De-designated Risk Management Contracts (c)			-		-		-		2,076		2,076
Total Risk Management Assets			6,339		422,732		34,425		(355,589)		107,907

Total Assets		$	6,365	$	422,732	$	34,425	$	(355,567)	$	107,955

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	3,433	$	406,259	$	31,659	$	(390,139)	$	51,212
Cash Flow Hedges:
	Commodity Hedges (a)		-		4,038		100		(899)		3,239
Total Risk Management Liabilities		$	3,433	$	410,297	$	31,759	$	(391,038)	$	54,451

306

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2012
PSO
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)		$	-	$	1,657	$	-	$	(1,142)	$	515
Cash Flow Hedges:
	Commodity Hedges (a)		-		42		-		(17)		25
Total Risk Management Assets		$	-	$	1,699	$	-	$	(1,159)	$	540

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	-	$	7,021	$	-	$	(1,142)	$	5,879
Cash Flow Hedges:
	Commodity Hedges (a)		-		17		-		(17)		-
Total Risk Management Liabilities		$	-	$	7,038	$	-	$	(1,159)	$	5,879

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2011
PSO
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)		$	97	$	7,797	$	-	$	(7,015)	$	879

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	53	$	9,542	$	-	$	(7,092)	$	2,503
Cash Flow Hedges:
	Commodity Hedges		-		107		-		-		107
Total Risk Management Liabilities		$	53	$	9,649	$	-	$	(7,092)	$	2,610

307

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2012
SWEPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)		$	-	$	2,804	$	-	$	(2,133)	$	671
Cash Flow Hedges:
	Commodity Hedges (a)		-		41		-		(17)		24
Total Risk Management Assets		$	-	$	2,845	$	-	$	(2,150)	$	695

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	-	$	3,261	$	-	$	(2,133)	$	1,128
Cash Flow Hedges:
	Commodity Hedges (a)		-		17		-		(17)		-
Total Risk Management Liabilities		$	-	$	3,278	$	-	$	(2,150)	$	1,128

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2011
SWEPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (b)		$	122	$	7,023	$	-	$	(6,421)	$	724
Cash Flow Hedges:
	Interest Rate/Foreign Currency Hedges		-		3		-		-		3
Total Risk Management Assets		$	122	$	7,026	$	-	$	(6,421)	$	727

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (b)		$	66	$	11,753	$	-	$	(6,479)	$	5,340
Cash Flow Hedges:
	Commodity Hedges		-		97		-		-		97
	Interest Rate/Foreign Currency Hedges		-		19,143		-		-		19,143
Total Risk Management Liabilities		$	66	$	30,993	$	-	$	(6,479)	$	24,580

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

(b)	Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.

(c)

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

(d)	Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 2 amounts primarily represent investments in money market funds.

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

(f)	Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.

There have been no transfers between Level 1 and Level 2 during the years ended December 31, 2012, 2011 and 2010.

308

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, 2012	APCo			I&M			OPCo			PSO		SWEPCo
	(in thousands)
Balance as of December 31, 2011	$	1,971		$	1,263		$	2,666		$	-	$	-
Realized Gain (Loss) Included in Net Income
(or Changes in Net Assets) (a) (b)		(5,204	)		(3,554	)		(7,452	)		-		-
Unrealized Gain (Loss) Included in Net
Income (or Changes in Net Assets) Relating
to Assets Still Held at the Reporting Date (a)		-			-			5,401			-		-
Realized and Unrealized Gains (Losses)
Included in Other Comprehensive Income		23			13			28			-		-
Purchases, Issuances and Settlements (c)		11,200			7,734			16,214			-		-
Transfers into Level 3 (d) (e)		1,392			860			1,909			-		-
Transfers out of Level 3 (e) (f)		(1,930	)		(1,144	)		(2,527	)		-		-
Changes in Fair Value Allocated to Regulated
Jurisdictions (g)		3,527			2,369			(810	)		-		-
Balance as of December 31, 2012	$	10,979		$	7,541		$	15,429		$	-	$	-

Year Ended December 31, 2011	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Balance as of December 31, 2010	$	5,131		$	3,108		$	6,583		$	1		$	2
Realized Gain (Loss) Included in Net Income
(or Changes in Net Assets) (a) (b)		(2,154	)		(1,261	)		(2,711	)		-			-
Unrealized Gain (Loss) Included in Net
Income (or Changes in Net Assets) Relating
to Assets Still Held at the Reporting Date (a)		-			-			7,741			-			-
Realized and Unrealized Gains (Losses)
Included in Other Comprehensive Income		(73	)		(47	)		(100	)		-			-
Purchases, Issuances and Settlements (c)		1,574			847			1,858			-			-
Transfers into Level 3 (d) (e)		2,488			1,531			3,257			-			-
Transfers out of Level 3 (e) (f)		(3,003	)		(1,906	)		(4,032	)		-			-
Changes in Fair Value Allocated to Regulated
Jurisdictions (g)		(1,992	)		(1,009	)		(9,930	)		(1	)		(2	)
Balance as of December 31, 2011	$	1,971		$	1,263		$	2,666		$	-		$	-

Year Ended December 31, 2010	APCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Balance as of December 31, 2009	$	9,428		$	4,816		$	10,345		$	2		$	3
Realized Gain (Loss) Included in Net Income
(or Changes in Net Assets) (a) (b)		1,670			963			2,053			2			2
Unrealized Gain (Loss) Included in Net
Income (or Changes in Net Assets) Relating
to Assets Still Held at the Reporting Date (a)		-			-			21,314			-			-
Realized and Unrealized Gains (Losses)
Included in Other Comprehensive Income		-			-			-			-			-
Purchases, Issuances and Settlements (c)		(7,163	)		(4,121	)		(8,800	)		(1	)		(1	)
Transfers into Level 3 (d) (e)		1,133			616			1,333			-			-
Transfers out of Level 3 (e) (f)		(10,999	)		(6,558	)		(13,978	)		-			-
Changes in Fair Value Allocated to Regulated
Jurisdictions (g)		11,062			7,392			(5,684	)		(2	)		(2	)
Balance as of December 31, 2010	$	5,131		$	3,108		$	6,583		$	1		$	2

(a)	Included in revenues on the statements of income.

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

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

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

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

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

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

309

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of December 31, 2012:

APCo	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	15,310	$	3,920	Discounted Cash Flow	Forward Market Price	$	9.40	$	68.80
FTRs		1,748		2,159	Discounted Cash Flow	Forward Market Price		(3.21)		14.79
Total	$	17,058	$	6,079

I&M	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	10,516	$	2,693	Discounted Cash Flow	Forward Market Price	$	9.40	$	68.80
FTRs		1,201		1,483	Discounted Cash Flow	Forward Market Price		(3.21)		14.79
Total	$	11,717	$	4,176

OPCo	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	21,516	$	5,510	Discounted Cash Flow	Forward Market Price	$	9.40	$	68.80
FTRs		2,457		3,034	Discounted Cash Flow	Forward Market Price		(3.21)		14.79
Total	$	23,973	$	8,544

(a)	Represents market prices in dollars per MWh.

10. INCOME TAXES

The details of the Registrant Subsidiaries’ income taxes as reported are as follows:

Year Ended December 31, 2012		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Income Tax Expense (Credit):
	Current	$	28,307	$	(9,221)	$	100,447	$	18,634	$	(214,353)
	Deferred		138,460		53,067		45,685		48,916		260,761
	Deferred Investment Tax Credits		(1,240)		(4,502)		(1,849)		(856)		(550)
Income Tax Expense		$	165,527	$	39,344	$	144,283	$	66,694	$	45,858

Year Ended December 31, 2011		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Income Tax Expense (Credit):
	Current	$	(15,136)	$	(86,471)	$	96,893	$	6,904	$	40,727
	Deferred		107,565		141,014		119,184		61,581		16,726
	Deferred Investment Tax Credits		(2,569)		(2,783)		(2,380)		(856)		(550)
Income Tax Expense		$	89,860	$	51,760	$	213,697	$	67,629	$	56,903

Year Ended December 31, 2010		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Income Tax Expense (Credit):
	Current	$	(66,216)	$	1,795	$	11,403	$	(46,528)	$	(16,066)
	Deferred		144,413		63,947		292,831		92,695		81,764
	Deferred Investment Tax Credits		(3,967)		(2,316)		(2,928)		3,933		(1,484)
Income Tax Expense		$	74,230	$	63,426	$	301,306	$	50,100	$	64,214

310

Shown below for each Registrant Subsidiary is a reconciliation of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory rate and the amount of income taxes reported:

APCo		Years Ended December 31,
		2012			2011			2010
		(in thousands)
Net Income		$	257,503		$	162,758		$	136,668
Income Tax Expense			165,527			89,860			74,230
Pretax Income		$	423,030		$	252,618		$	210,898

Income Taxes on Pretax Income at Statutory Rate (35%)		$	148,061		$	88,416		$	73,814
Increase (Decrease) in Income Taxes Resulting from the Following Items:
	Depreciation		20,424			17,923			18,134
	Investment Tax Credits, Net		(1,240)			(2,569)			(3,967)
	State and Local Income Taxes, Net		3,175			(35,532)			(7,189)
	Removal Costs		(6,641)			(4,447)			(6,709)
	AFUDC		(1,145)			(5,314)			(1,860)
	Medicare Subsidy		382			4,908			(1,159)
	Valuation Allowance		5,674			30,541			-
	Other		(3,163)			(4,066)			3,166
Income Tax Expense		$	165,527		$	89,860		$	74,230

Effective Income Tax Rate			39.1	%		35.6	%		35.2	%

I&M		Years Ended December 31,
		2012			2011			2010
		(in thousands)
Net Income		$	118,457		$	149,674		$	126,091
Income Tax Expense			39,344			51,760			63,426
Pretax Income		$	157,801		$	201,434		$	189,517

Income Taxes on Pretax Income at Statutory Rate (35%)		$	55,230		$	70,502		$	66,331
Increase (Decrease) in Income Taxes Resulting from the Following Items:
	Depreciation		8,659			7,895			11,419
	Investment Tax Credits, Net		(4,502)			(2,783)			(2,316)
	State and Local Income Taxes, Net		(1,559)			(1,376)			3,966
	Removal Costs		(5,490)			(5,566)			(3,663)
	AFUDC		(7,218)			(9,223)			(9,032)
	Nuclear Fuel Disposal Costs		225			(1,400)			(1,655)
	Other		(6,001)			(6,289)			(1,624)
Income Tax Expense		$	39,344		$	51,760		$	63,426

Effective Income Tax Rate			24.9	%		25.7	%		33.5	%

311

OPCo		Years Ended December 31,
		2012			2011			2010
		(in thousands)
Net Income		$	343,534		$	464,993		$	541,616
Income Tax Expense			144,283			213,697			301,306
Pretax Income		$	487,817		$	678,690		$	842,922

Income Taxes on Pretax Income at Statutory Rate (35%)		$	170,736		$	237,542		$	295,023
Increase (Decrease) in Income Taxes Resulting from the Following Items:
	Depreciation		5,239			6,368			11,443
	Investment Tax Credits, Net		(1,849)			(2,380)			(2,928)
	State and Local Income Taxes, Net		(18,291)			(3,222)			906
	Parent Company Loss Benefit		(11,915)			(7,117)			(9,583)
	Other		363			(17,494)			6,445
Income Tax Expense		$	144,283		$	213,697		$	301,306

Effective Income Tax Rate			29.6	%		31.5	%		35.7	%

PSO		Years Ended December 31,
		2012			2011			2010
		(in thousands)
Net Income		$	114,141		$	124,628		$	72,787
Income Tax Expense			66,694			67,629			50,100
Pretax Income		$	180,835		$	192,257		$	122,887

Income Taxes on Pretax Income at Statutory Rate (35%)		$	63,292		$	67,290		$	43,010
Increase (Decrease) in Income Taxes Resulting from the Following Items:
	Depreciation		(10)			(165)			(166)
	Investment Tax Credits, Net		(781)			(781)			(781)
	State and Local Income Taxes, Net		6,953			4,744			10,307
	Other		(2,760)			(3,459)			(2,270)
Income Tax Expense		$	66,694		$	67,629		$	50,100

Effective Income Tax Rate			36.9	%		35.2	%		40.8	%

SWEPCo		Years Ended December 31,
		2012			2011			2010
		(in thousands)
Net Income		$	202,513		$	165,126		$	146,684
Income Tax Expense			45,858			56,903			64,214
Pretax Income		$	248,371		$	222,029		$	210,898

Income Taxes on Pretax Income at Statutory Rate (35%)		$	86,930		$	77,710		$	73,814
Increase (Decrease) in Income Taxes Resulting from the Following Items:
	Depreciation		2,105			(7)			1,223
	Depletion		(3,276)			(1,506)			(1,506)
	Investment Tax Credits, Net		(550)			(550)			(1,484)
	State and Local Income Taxes, Net		(18,010)			4,004			(637)
	AFUDC		(19,879)			(16,962)			(15,856)
	Other		(1,462)			(5,786)			8,660
Income Tax Expense		$	45,858		$	56,903		$	64,214

Effective Income Tax Rate			18.5	%		25.6	%		30.4	%

312

The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant Subsidiary:

APCo	December 31,
	2012			2011
	(in thousands)
Deferred Tax Assets	$	526,665		$	591,379
Deferred Tax Liabilities		(2,467,063	)		(2,341,814	)
Net Deferred Tax Liabilities	$	(1,940,398	)	$	(1,750,435	)

Property Related Temporary Differences	$	(1,416,426	)	$	(1,303,698	)
Amounts Due from Customers for Future Federal Income Taxes		(100,520	)		(95,960	)
Deferred State Income Taxes		(230,490	)		(235,296	)
Regulatory Assets		(161,274	)		(194,161	)
Postretirement Benefits		45,044			61,109
Accrued Pensions		41,643			45,782
Deferred Income Taxes on Other Comprehensive Loss		16,099			31,523
Deferred Fuel and Purchased Power		(115,900	)		(131,137	)
Net Operating Loss Carryforward		69,580			88,721
Tax Credit Carryforward		13,199			37,850
Valuation Allowance		(36,215	)		(30,541	)
All Other, Net		(65,138	)		(24,627	)
Net Deferred Tax Liabilities	$	(1,940,398	)	$	(1,750,435	)

I&M	December 31,
	2012			2011
	(in thousands)
Deferred Tax Assets	$	831,724		$	773,679
Deferred Tax Liabilities		(1,842,791	)		(1,700,182	)
Net Deferred Tax Liabilities	$	(1,011,067	)	$	(926,503	)

Property Related Temporary Differences	$	(351,682	)	$	(305,400	)
Amounts Due from Customers for Future Federal Income Taxes		(37,633	)		(28,551	)
Deferred State Income Taxes		(112,388	)		(107,497	)
Deferred Income Taxes on Other Comprehensive Loss		15,553			15,196
Accrued Nuclear Decommissioning		(475,223	)		(435,916	)
Postretirement Benefits		27,323			51,037
Net Operating Loss Carryforward		31,233			12,986
Accrued Pensions		24,746			27,819
Regulatory Assets		(88,696	)		(116,474	)
All Other, Net		(44,300	)		(39,703	)
Net Deferred Tax Liabilities	$	(1,011,067	)	$	(926,503	)

313

OPCo	December 31,
	2012			2011
	(in thousands)
Deferred Tax Assets	$	505,003		$	574,007
Deferred Tax Liabilities		(2,851,068	)		(2,834,046	)
Net Deferred Tax Liabilities	$	(2,346,065	)	$	(2,260,039	)

Property Related Temporary Differences	$	(2,061,841	)	$	(1,966,581	)
Amounts Due from Customers for Future Federal Income Taxes		(59,291	)		(59,699	)
Deferred State Income Taxes		(90,001	)		(98,093	)
Regulatory Assets		(190,273	)		(205,925	)
Postretirement Benefits		50,421			74,447
Accrued Pensions		(43,928	)		(30,853	)
Deferred Income Taxes on Other Comprehensive Loss		89,236			106,466
Impairment Loss		100,459			-
Deferred Fuel and Purchased Power		(199,997	)		(194,509	)
All Other, Net		59,150			114,708
Net Deferred Tax Liabilities	$	(2,346,065	)	$	(2,260,039	)

PSO	December 31,
	2012			2011
	(in thousands)
Deferred Tax Assets	$	101,561		$	121,181
Deferred Tax Liabilities		(835,054	)		(840,631	)
Net Deferred Tax Liabilities	$	(733,493	)	$	(719,450	)

Property Related Temporary Differences	$	(640,859	)	$	(626,456	)
Amounts Due from Customers for Future Federal Income Taxes		(1,325	)		(1,023	)
Deferred State Income Taxes		(95,378	)		(89,605	)
Regulatory Assets		(57,367	)		(77,016	)
Postretirement Benefits		13,541			25,607
Accrued Pensions		7,570			12,978
Deferred Income Taxes on Other Comprehensive Loss		(3,489	)		(3,849	)
Deferred Federal Income Taxes on Deferred State Income Taxes		39,050			36,018
Net Operating Loss Carryforward		3,892			5,247
Tax Credit Carryforward		401			6,872
All Other, Net		471			(8,223	)
Net Deferred Tax Liabilities	$	(733,493	)	$	(719,450	)

SWEPCo	December 31,
	2012			2011
	(in thousands)
Deferred Tax Assets	$	286,133		$	143,200
Deferred Tax Liabilities		(1,260,281	)		(800,673	)
Net Deferred Tax Liabilities	$	(974,148	)	$	(657,473	)

Property Related Temporary Differences	$	(997,337	)	$	(588,612	)
Amounts Due from Customers for Future Federal Income Taxes		(43,090	)		(36,289	)
Deferred State Income Taxes		(98,630	)		(70,211	)
Regulatory Assets		(12,922	)		(35,349	)
Postretirement Benefits		13,039			21,654
Accrued Pensions		5,061			5,861
Deferred Income Taxes on Other Comprehensive Loss		9,618			14,440
Impairment Loss - Turk Plant		21,700			17,150
Net Operating Loss Carryforward		104,738			-
All Other, Net		23,675			13,883
Net Deferred Tax Liabilities	$	(974,148	)	$	(657,473	)

314

AEP System Tax Allocation Agreement

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

Federal and State Income Tax Audit Status

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2009. The Registrant Subsidiaries completed the examination of the years 2007 and 2008 in April 2011 and settled all outstanding issues on appeal for the years 2001 through 2006 in October 2011. The settlements did not materially impact the Registrant Subsidiaries’ net income, cash flows or financial condition. The IRS examination of years 2009 and 2010 started in October 2011. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.

The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine their tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. Management believes that previously filed tax returns have positions that may be challenged by these tax authorities. However, management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. With few exceptions, the Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2008. In March 2012, AEP settled all outstanding franchise tax issues with the state of Ohio for the years 2000 through 2009. The settlements did not materially impact the Registrants Subsidiaries' net income, cash flows or financial condition.

Net Income Tax Operating Loss Carryforward

In 2011, APCo and I&M recognized federal net income tax operating losses of $313 million and $123 million, respectively, driven primarily by bonus depreciation, pension plan contributions and other book versus tax temporary differences. In 2012, SWEPCo recognized a federal net income tax operating loss of $858 million driven primarily by bonus depreciation. APCo, OPCo, PSO and SWEPCo also had state net income tax operating loss carryforwards as indicated in the table below.

		State Net Income
		Tax Operating
		Loss		Year of
Company	State	Carryforward		Expiration
		(in thousands)
APCo	Tennessee	$	12,513	2026
APCo	Virginia		328,850	2031
APCo	West Virginia		583,890	2032
OPCo	West Virginia		312,791	2032
PSO	Oklahoma		99,792	2031
SWEPCo	Louisiana		313,750	2027

As a result, APCo, I&M, OPCo, PSO and SWEPCo accrued deferred federal and/or state and local income tax benefits in 2011 and/or 2012 and expect to realize the federal, state and local cash flow benefits in future periods as there was insufficient capacity in prior periods to carry the net operating losses back. Management anticipates future taxable income will be sufficient to realize the net income tax operating loss tax benefits before the federal carryforward expires after 2032.

315

Tax Credit Carryforward

Federal and state net income tax operating losses sustained in 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, 2012, the Registrant Subsidiaries have federal tax credit carryforwards and APCo 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 2028 through 2031 and state coal tax credits will expire in the years 2013 through 2021.

			Federal Tax				State Tax
			Credit				Credit
	Total Federal		Carryforward		Total State		Carryforward
	Tax Credit		Subject to		Tax Credit		Subject to
Company	Carryforward		Expiration		Carryforward		Expiration
	(in thousands)
APCo	$	12,692	$	4,476	$	65,653	$	29,297
I&M		2,487		2,487		-		-
OPCo		21,321		1,548		-		-
PSO		401		381		16,194		-
SWEPCo		2,537		899		-		-

The Registrant Subsidiaries anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. APCo does not anticipate that state taxable income will be sufficient in future periods to realize the tax benefits of all state tax credits before they expire unused and a valuation allowance has been provided accordingly.

Valuation Allowance

Management assesses past results and future operations to estimate and evaluate available positive and negative evidence to evaluate whether sufficient future taxable income will be generated to use existing deferred tax assets. A significant piece of objective negative information evaluated were the net income tax operating losses sustained in 2012, 2011 and 2009. On the basis of this evaluation of available positive and negative evidence, as of December 31, 2012, a valuation allowance of $36.2 million for state tax credits, net of federal tax, has been recorded by APCo in order to measure only the portion of the deferred tax assets that, more likely than not, will be realized. The amount of the deferred tax assets considered realizable, however, could be adjusted if estimates of future taxable income during the carryforward period are reduced or if objective negative evidence in the form of cumulative losses is no longer present and additional weight may be given to subjective evidence, such as projections for growth.

316

Uncertain Tax Positions

The Registrant Subsidiaries 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.”

The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense:

	Years Ended December 31,
	2012						2011
					Reversal of						Reversal of
					Prior Period						Prior Period
	Interest		Interest		Interest		Interest		Interest		Interest
Company	Expense		Income		Expense		Expense		Income		Expense
	(in thousands)
APCo	$	62	$	-	$	183	$	737	$	3,229	$	2,416
I&M		1,355		-		-		-		2,681		638
OPCo		266		-		504		1,213		5,173		4,019
PSO		259		-		294		239		344		3,123
SWEPCo		286		-		271		1,382		1,991		2,255

	Year Ended December 31, 2010
					Reversal of
					Prior Period
	Interest		Interest		Interest
Company	Expense		Income		Expense
	(in thousands)
APCo	$	2,330	$	-	$	1,146
I&M		-		209		159
OPCo		3,948		-		1,653
PSO		455		-		871
SWEPCo		749		-		320

The following table shows balances for amounts accrued for the receipt of interest:

	December 31,
Company	2012		2011
	(in thousands)
APCo	$	-	$	70
I&M		-		759
OPCo		-		869
PSO		15		134
SWEPCo		-		452

The following table shows balances for amounts accrued for the payment of interest and penalties:

	December 31,
Company	2012		2011
	(in thousands)
APCo	$	271	$	120
I&M		1,337		145
OPCo		451		1,513
PSO		424		426
SWEPCo		1,061		668

317

The reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of January 1, 2012		$	7,311	$	14,071	$	43,565	$	3,585	$	9,031
Increase - Tax Positions Taken During
	a Prior Period		-		2,266		1,360		421		2,806
Decrease - Tax Positions Taken During
	a Prior Period		(384)		(1,252)		(13,582)		(92)		(775)
Increase - Tax Positions Taken During
	the Current Year		-		-		-		-		-
Decrease - Tax Positions Taken During
	the Current Year		-		-		-		-		-
Decrease - Settlements with Taxing
	Authorities		(1,674)		-		(20,291)		-		-
Decrease - Lapse of the Applicable
	Statute of Limitations		-		-		-		(1,641)		(1,509)
Balance as of December 31, 2012		$	5,253	$	15,085	$	11,052	$	2,273	$	9,553

		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of January 1, 2011		$	13,267	$	17,871	$	68,655	$	9,845	$	14,410
Increase - Tax Positions Taken During
	a Prior Period		5,990		9,256		11,330		1,339		14,355
Decrease - Tax Positions Taken During
	a Prior Period		(2,100)		(8,622)		(20,299)		(1,171)		(2,706)
Increase - Tax Positions Taken During
	the Current Year		-		-		-		-		-
Decrease - Tax Positions Taken During
	the Current Year		-		-		-		-		-
Decrease - Settlements with Taxing
	Authorities		(2,587)		(1,424)		(6,935)		(1,178)		(12,997)
Decrease - Lapse of the Applicable
	Statute of Limitations		(7,259)		(3,010)		(9,186)		(5,250)		(4,031)
Balance as of December 31, 2011		$	7,311	$	14,071	$	43,565	$	3,585	$	9,031

		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of January 1, 2010		$	17,292	$	20,007	$	65,551	$	12,216	$	10,163
Increase - Tax Positions Taken During
	a Prior Period		4,177		4,964		19,214		151		6,128
Decrease - Tax Positions Taken During
	a Prior Period		(6,376)		(5,287)		(8,837)		(1,200)		(376)
Increase - Tax Positions Taken During
	the Current Year		-		-		-		-		-
Decrease - Tax Positions Taken During
	the Current Year		(1,015)		(1,487)		(1,749)		(517)		(691)
Decrease - Settlements with Taxing
	Authorities		(811)		(236)		(70)		(265)		(4)
Decrease - Lapse of the Applicable
	Statute of Limitations		-		(90)		(5,454)		(540)		(810)
Balance as of December 31, 2010		$	13,267	$	17,871	$	68,655	$	9,845	$	14,410

318

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 Subsidiary was as follows:

Company	2012		2011		2010
	(in thousands)
APCo	$	-	$	806	$	1,109
I&M		1,220		654		1,664
OPCo		674		21,177		28,749
PSO		818		1,882		1,977
SWEPCo		3,512		3,717		2,481

Federal Tax Legislation – Affecting APCo, I&M, OPCo, PSO and SWEPCo

The American Recovery and Reinvestment Act of 2009 provided for several new grant programs and expanded tax credits and an extension of the 50% bonus depreciation provision enacted in the Economic Stimulus Act of 2008. The enacted provisions did not materially impact the Registrants Subsidiaries’ net income or financial condition. However, the bonus depreciation contributed to AEP’s 2009 federal net operating tax loss that resulted in a 2010 cash flow benefit to the Registrant Subsidiaries as follows:

Company	(in thousands)
APCo	$	170,466
I&M		78,456
OPCo		141,111
PSO		10,741
SWEPCo		-

The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts) were enacted in March 2010. The Health Care Acts amend tax rules so that the portion of employer health care costs that are reimbursed by the Medicare Part D prescription drug subsidy will no longer be deductible by the employer for federal income tax purposes effective for years beginning after December 31, 2012. Due to the loss of the future tax deduction, a reduction in the deferred tax asset related to the nondeductible OPEB liabilities accrued to date was recorded by the Registrant Subsidiaries in March 2010. This reduction did not materially impact the Registrant Subsidiaries' cash flows or financial condition. For the year ended December 31, 2010, the Registrant Subsidiaries reflected a decrease in deferred tax assets, which was partially offset by recording net tax regulatory assets in jurisdictions with regulated operations, resulting in a decrease in net income as follows:

	Net Reduction		Tax
	to Deferred		Regulatory		Decrease in
Company	Tax Assets		Assets, Net		Net Income
	(in thousands)
APCo	$	9,397	$	8,831	$	566
I&M		7,212		6,528		684
OPCo		12,771		6,990		5,781
PSO		3,172		3,172		-
SWEPCo		3,412		3,412		-

319

The Small Business Jobs Act (the 2010 Act) was enacted in September 2010. Included in the 2010 Act was a one-year extension of the 50% bonus depreciation provision. The Tax Relief, Unemployment Insurance Reauthorization and the Job Creation Act of 2010 extended the life of research and development, employment and several energy tax credits originally scheduled to expire at the end of 2010. In addition, the 2010 Act extended the time for claiming bonus depreciation and increased the deduction to 100% for part of 2011 and 2010. The enacted provisions did not materially impact the Registrant Subsidiaries’ net income or financial condition but had a favorable impact on cash flows in 2010 as follows:

Company	(in thousands)
APCo	$	43,379
I&M		49,740
OPCo		124,637
PSO		-
SWEPCo		30,269

In December 2011, the U.S. Treasury Department issued guidance regarding the deduction and capitalization of expenditures related to tangible property. The guidance was in the form of proposed and temporary regulations and generally is effective for tax years beginning in 2012. In November 2012, the effective date was moved to tax years beginning in 2014. Further, the notice stated that the U. S. Treasury Department anticipates that the final regulations will contain changes from the temporary regulations. Management will evaluate the impact of these regulations once they are issued.

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 will not materially impact the Registrant Subsidiaries’ net income or financial condition but are expected to have a favorable impact on cash flows in 2013.

State Tax Legislation – Affecting APCo, I&M and OPCo

Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rates 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.

In May 2011, Michigan repealed its Business Tax regime and replaced it with a traditional corporate net income tax with a rate of 6%, effective January 1, 2012.

During the third quarter of 2012, the state of West Virginia achieved certain minimum levels of shortfall reserve funds. As a result, the West Virginia corporate income tax rate will be reduced from 7.75% to 7.0% in 2013. The enacted provisions will not materially impact the Registrant Subsidiaries’ net income, cash flows or financial condition.

320

11. LEASES

Leases of property, plant and equipment are for periods up to 60 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, 2012	APCo		I&M		OPCo		PSO		SWEPCo
	(in thousands)
Net Lease Expense on Operating Leases	$	15,633	$	95,509	$	59,836	$	5,283	$	5,797
Amortization of Capital Leases		7,429		8,429		10,906		3,839		14,793
Interest on Capital Leases		1,782		1,738		3,307		815		9,041
Total Lease Rental Costs	$	24,844	$	105,676	$	74,049	$	9,937	$	29,631

Year Ended December 31, 2011	APCo		I&M		OPCo		PSO		SWEPCo
	(in thousands)
Net Lease Expense on Operating Leases	$	13,488	$	94,317	$	59,983	$	6,532	$	5,990
Amortization of Capital Leases		7,880		8,762		13,118		4,438		12,694
Interest on Capital Leases		1,898		2,115		3,753		1,098		9,651
Total Lease Rental Costs	$	23,266	$	105,194	$	76,854	$	12,068	$	28,335

Year Ended December 31, 2010	APCo		I&M		OPCo		PSO		SWEPCo
	(in thousands)
Net Lease Expense on Operating Leases	$	18,034	$	91,973	$	62,887	$	2,649	$	5,877
Amortization of Capital Leases		7,002		31,178		12,069		3,992		11,742
Interest on Capital Leases		1,598		2,298		3,132		1,057		9,892
Total Lease Rental Costs	$	26,634	$	125,449	$	78,088	$	7,698	$	27,511

321

The following table shows the property, plant and equipment under capital leases and related obligations recorded on the Registrant Subsidiaries’ balance sheets. For SWEPCo, current and long-term capital lease obligations are included in Obligations Under Capital Leases on SWEPCo’s balance sheets. For all other Registrant Subsidiaries, 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 balance sheets.

December 31, 2012		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Property, Plant and Equipment Under
	Capital Leases:
Generation		$	11,798	$	19,102	$	39,080	$	3,624	$	27,745
Other Property, Plant and Equipment			20,944		22,697		35,666		15,614		154,166
Total Property, Plant and Equipment			32,742		41,799		74,746		19,238		181,911
Accumulated Amortization			10,282		13,154		27,513		6,738		50,440
Net Property, Plant and Equipment
	Under Capital Leases	$	22,460	$	28,645	$	47,233	$	12,500	$	131,471

Obligations Under Capital Leases:
Noncurrent Liability		$	16,375	$	22,842	$	36,381	$	8,864	$	114,161
Liability Due Within One Year			6,085		5,803		14,707		3,636		17,599

Total Obligations Under Capital Leases		$	22,460	$	28,645	$	51,088	$	12,500	$	131,760

December 31, 2011		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Property, Plant and Equipment Under
	Capital Leases:
Generation		$	11,712	$	16,100	$	36,689	$	3,617	$	20,453
Other Property, Plant and Equipment			25,201		27,712		36,264		16,441		145,273
Total Property, Plant and Equipment			36,913		43,812		72,953		20,058		165,726
Accumulated Amortization			9,886		12,779		22,075		5,196		38,163
Net Property, Plant and Equipment
	Under Capital Leases	$	27,027	$	31,033	$	50,878	$	14,862	$	127,563

Obligations Under Capital Leases:
Noncurrent Liability		$	19,293	$	23,117	$	40,152	$	11,101	$	112,802
Liability Due Within One Year			7,734		7,916		14,096		3,761		15,058

Total Obligations Under Capital Leases		$	27,027	$	31,033	$	54,248	$	14,862	$	127,860

Future minimum lease payments consisted of the following as of December 31, 2012:

Capital Leases		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
2013		$	6,988	$	6,827	$	13,669	$	4,222	$	25,706
2014			4,596		5,649		10,371		3,149		23,702
2015			3,849		4,279		7,383		1,921		21,585
2016			3,372		3,504		6,743		1,636		18,728
2017			2,809		3,344		6,322		1,646		20,103
Later Years			3,748		11,781		17,905		1,709		60,112
Total Future Minimum Lease
	Payments		25,362		35,384		62,393		14,283		169,936
Less Estimated Interest Element			2,902		6,739		11,305		1,782		38,176
Estimated Present Value of Future
	Minimum Lease Payments	$	22,460	$	28,645	$	51,088	$	12,501	$	131,760

Noncancelable Operating Leases		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
2013		$	15,693	$	98,719	$	58,968	$	2,383	$	5,893
2014			13,959		98,673		55,261		1,858		4,279
2015			11,054		97,266		52,287		1,524		3,672
2016			10,270		89,872		46,002		1,231		3,030
2017			9,819		84,142		42,678		1,048		2,681
Later Years			47,613		423,279		68,094		1,723		10,297
Total Future Minimum Lease
	Payments	$	108,408	$	891,951	$	323,290	$	9,767	$	29,852

322

Master Lease Agreements

The Registrant Subsidiaries lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. As of December 31, 2012, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows:

	Maximum
Company	Potential Loss
	(in thousands)
APCo	$	3,463
I&M		2,432
OPCo		4,003
PSO		1,171
SWEPCo		2,405

Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.

Rockport Lease

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. I&M’s future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2012 are as follows:

Future Minimum Lease Payments	I&M
	(in millions)
2013	$	74
2014		74
2015		74
2016		74
2017		74
Later Years		369
Total Future Minimum Lease Payments	$	739

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $14 million for I&M and $15 million for SWEPCo for the remaining railcars as of December 31, 2012. 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 approximately 84% under the current five-year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment. I&M and

323

SWEPCo have assumed the guarantee under the return-and-sale option. I&M’s maximum potential loss related to the guarantee is approximately $12 million and SWEPCo’s is approximately $13 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.

Sabine Dragline Lease

During 2009, Sabine, an entity consolidated in accordance with the accounting guidance for “Variable Interest Entities,” 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 SWEPCo’s December 31, 2012 and 2011 balance sheets. The short-term and long-term capital lease obligations are included in Obligations Under Capital Leases on SWEPCo’s December 31, 2012 and 2011 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

In December 2007, I&M entered into a sale-and-leaseback transaction with Citicorp Leasing, Inc. (CLI), an unrelated, unconsolidated, wholly-owned subsidiary of Citibank, N.A. to lease nuclear fuel for I&M’s Cook Plant. In December 2007, I&M sold a portion of its unamortized nuclear fuel inventory to CLI at cost for $85 million. The lease had a variable rate based on one month LIBOR and was accounted for as a capital lease with lease terms up to 60 months. This lease was terminated with the March 2012 refueling.

12. FINANCING ACTIVITIES

Preferred Stock

In December 2011, the Registrant Subsidiaries redeemed all of their outstanding preferred stock, resulting in a loss, which is included in Preferred Stock Dividend Requirements Including Capital Stock Expense on the statements of income. The par value of preferred stock redeemed and the loss recorded by the Registrant Subsidiaries was as follows:

	Par Value of		Loss on
Company	Stock Redeemed		Redemption
	(in thousands)
APCo	$	17,736	$	1,013
I&M		8,072		314
OPCo		16,613		488
PSO		4,882		254
SWEPCo		4,694		369

			Number of Shares Redeemed
			Years Ended December 31,
Company	Series		2011	2010
APCo	4.50	%	177,465	53
I&M	4.12	%	11,055	-
I&M	4.125	%	55,257	44
I&M	4.56	%	14,412	-
OPCo	4.08	%	14,495	100
OPCo	4.20	%	22,824	-
OPCo	4.40	%	31,482	-
OPCo	4.50	%	97,357	6
PSO	4.00	%	44,508	-
PSO	4.24	%	4,310	3,759
SWEPCo	4.28	%	7,386	-
SWEPCo	4.65	%	1,907	-
SWEPCo	5.00	%	37,665	8

324

Long-term Debt

There are certain limitations on establishing liens against the Registrant Subsidiaries’ assets under their respective indentures. None of the long-term debt obligations of the Registrant Subsidiaries have been guaranteed or secured by AEP or any of its affiliates.

The following details long-term debt outstanding as of December 31, 2012 and 2011:

		Weighted
		Average
		Interest
		Rate as of			Outstanding as of
		December 31,	Interest Rate Ranges as of December 31,		December 31,
Company	Maturity	2012	2012	2011	2012		2011
Senior Unsecured Notes					(in thousands)
APCo	2012-2038	5.43%	0.685%-7.95%	3.40%-7.95%	$	3,167,559	$	3,141,843
I&M	2012-2037	6.24%	5.05%-7.00%	5.05%-7.00%		1,171,080		1,270,599
OPCo	2012-2035	5.84%	4.85%-6.60%	0.955%-6.60%		3,142,615		3,291,823
PSO	2016-2037	5.52%	4.40%-6.625%	4.40%-6.625%		896,364		896,023
SWEPCo	2015-2040	5.56%	3.55%-6.45%	4.90%-6.45%		1,822,653		1,548,437

Pollution Control Bonds (a)
APCo	2012-2038 (b)	2.01%	0.12%-5.375%	0.07%-6.05%		532,500		582,000
I&M	2012-2025 (b)	4.03%	0.11%-6.25%	0.06%-6.25%		266,531		266,494
OPCo	2012-2038 (b)	3.72%	0.13%-5.80%	0.07%-5.80%		517,825		562,325
PSO	2014-2020	5.03%	4.45%-5.25%	4.45%-5.25%		46,360		46,360
SWEPCo	2015-2018	4.28%	3.25%-4.95%	3.25%-4.95%		135,200		135,200

Notes Payable - Affiliated
OPCo	2015	5.25%	5.25%	5.25%		200,000		200,000

Notes Payable - Nonaffiliated
I&M	2013-2016	2.42%	1.913%-5.44%	2.029%-5.44%		224,376		234,590
SWEPCo	2012-2032	5.09%	4.58%-6.37%	6.37%-7.03%		88,375		45,000

Spent Nuclear Fuel Obligation (c)
I&M						265,249		265,065

Other Long-term Debt
APCo	2026	13.718%	13.718%	13.718%		2,383		2,408
I&M (d)	2015-2025	2.39%	1.72%-6.00%	6.00%		130,430		20,927
PSO	2027	3.00%	3.00%	3.00%		7,147		4,981

(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, standby bond purchase agreements 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)

Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 4).

(d)

In 2012, I&M issued a $110 million three-year credit facility to be used for general corporate purposes.

325

Long-term debt outstanding as of December 31, 2012 is payable as follows:

		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
2013		$	574,679	$	203,953	$	856,000	$	764	$	3,250
2014			100,033		353,946		403,580		34,115		3,250
2015			500,038		253,730		286,000		427		306,750
2016			65,393		4,158		350,000		150,440		3,250
2017			250,049		1,479		-		454		253,250
After 2017			2,219,692		1,244,789		1,972,245		767,307		1,478,825
Principal Amount			3,709,884		2,062,055		3,867,825		953,507		2,048,575
Unamortized Discount, Net			(7,442)		(4,389)		(7,385)		(3,636)		(2,347)
Total Long-term Debt
	Outstanding	$	3,702,442	$	2,057,666	$	3,860,440	$	949,871	$	2,046,228

In January 2013 and February 2013, I&M retired $12 million and $11 million, respectively, of Notes Payable related to DCC Fuel.

In February 2013, OPCo retired $250 million of 5.5% Senior Unsecured Notes due in 2013.

As of December 31, 2012, trustees held, on behalf of OPCo, $463 million of its reacquired Pollution Control Bonds.

Dividend Restrictions

The Registrant Subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

Federal Power Act

The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock.

Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants. Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo.

None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

Leverage Restrictions

Pursuant to the credit agreement leverage restrictions, APCo, I&M and OPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. As of December 31, 2012, $32 million of APCo’s retained earnings and none of I&M’s or OPCo’s retained earnings have restrictions related to the payment of dividends to Parent.

326

Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of the subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions approved in a regulatory order. The amount of outstanding loans (borrowings) to/from the Utility Money Pool as of December 31, 2012 and 2011 is included in Advances to/from Affiliates 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, 2012 and 2011 are described in the following tables:

Year Ended December 31, 2012:

									Net
									Loans
	Maximum		Maximum		Average		Average		(Borrowings)		Authorized
	Borrowings		Loans		Borrowings		Loans		to/from Utility		Short-term
	from Utility		to Utility		from Utility		to Utility		Money Pool as of		Borrowing
Company	Money Pool		Money Pool		Money Pool		Money Pool		December 31, 2012		Limit
	(in thousands)
APCo	$	350,153	$	23,504	$	161,363	$	22,821	$	(150,941)	$	600,000
I&M		-		362,733		-		202,439		116,977		500,000
OPCo		126,975		290,356		47,820		105,154		116,422		600,000
PSO		-		177,778		-		92,697		10,558		300,000
SWEPCo		227,087		173,778		147,338		78,994		153,829		350,000

Year Ended December 31, 2011:

									Net
									Loans
	Maximum		Maximum		Average		Average		(Borrowings)		Authorized
	Borrowings		Loans		Borrowings		Loans		to/from Utility		Short-term
	from Utility		to Utility		from Utility		to Utility		Money Pool as of		Borrowing
Company	Money Pool		Money Pool		Money Pool		Money Pool		December 31, 2011		Limit
	(in thousands)
APCo	$	217,876	$	393,811	$	117,378	$	96,186	$	(176,240)	$	600,000
I&M		57,352		219,386		23,793		56,999		95,714		500,000
OPCo		46,761		452,187		31,365		225,728		219,458		600,000
PSO		96,034		255,611		41,971		88,805		39,876		300,000
SWEPCo		136,752		105,184		47,232		38,798		(132,473)		350,000

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,
	2012		2011		2010
Maximum Interest Rate	0.56	%	0.56	%	0.55	%
Minimum Interest Rate	0.39	%	0.06	%	0.09	%

327

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the years ended December 31, 2012, 2011 and 2010 are summarized for all Registrant Subsidiaries in the following table:

	Average Interest Rate						Average Interest Rate
	for Funds Borrowed						for Funds Loaned
	from Utility Money Pool for						to Utility Money Pool for
	Years Ended December 31,						Years Ended December 31,
Company	2012		2011		2010		2012		2011		2010
APCo	0.47	%	0.42	%	0.26	%	0.47	%	0.32	%	-	%
I&M	-	%	0.39	%	0.43	%	0.46	%	0.38	%	0.24	%
OPCo	0.47	%	0.45	%	-	%	0.47	%	0.35	%	0.22	%
PSO	-	%	0.41	%	0.31	%	0.46	%	0.32	%	0.17	%
SWEPCo	0.53	%	0.40	%	0.19	%	0.45	%	0.33	%	0.27	%

Interest expense related to the Utility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries incurred interest expense for amounts borrowed from the Utility Money Pool as follows:

	Years Ended December 31,
Company	2012		2011		2010
			(in thousands)
APCo	$	772	$	198	$	611
I&M		-		20		17
OPCo		555		12		16
PSO		11		85		102
SWEPCo		977		174		11

Interest income related to the Utility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries earned interest income for amounts advanced to the Utility Money Pool as follows:

	Years Ended December 31,
Company	2012		2011		2010
			(in thousands)
APCo	$	123	$	313	$	9
I&M		963		226		219
OPCo		1,038		820		708
PSO		435		250		19
SWEPCo		320		32		438

Short-term Debt

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

December 31,

2012

2011

Outstanding

Interest

Outstanding

Interest

Company

Type of Debt

Amount

Rate (a)

Amount

Rate (a)

(in thousands)

SWEPCo

Line of Credit – Sabine

2,603

1.82

17,016

1.79

(a)

Weighted average rate.

Credit Facilities

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

328

Sale of Receivables – AEP Credit

Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold.

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

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of December 31, 2012 and 2011 was as follows:

	December 31,
Company	2012			2011
	(in thousands)
APCo		$	153,719	$	121,605
I&M			123,447		121,597
OPCo			300,675		346,695
PSO			85,530		123,172
SWEPCo			132,449		140,440

The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:

	Years Ended December 31,
Company	2012		2011		2010
	(in thousands)
APCo	$	6,883	$	9,612	$	9,194
I&M		6,121		6,168		6,770
OPCo		20,312		18,851		20,630
PSO		7,054		6,363		5,406
SWEPCo		6,140		5,672		5,688

The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:

	Years Ended December 31,
Company	2012			2011		2010
	(in thousands)
APCo		$	1,353,920	$	1,248,253	$	1,418,487
I&M			1,344,260		1,323,068		1,283,955
OPCo			2,952,723		3,461,758		3,495,609
PSO			1,157,174		1,299,190		1,196,586
SWEPCo			1,481,925		1,495,397		1,402,525

13. RELATED PARTY TRANSACTIONS

For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 10 in addition to “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 12.

Interconnection Agreement

APCo, I&M, KPCo, OPCo and AEPSC are parties to the Interconnection Agreement, which defines the sharing of costs and benefits associated with the respective generating plants. This sharing is based upon each AEP utility subsidiary’s MLR and is 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

329

months. In addition, APCo, I&M, KPCo and OPCo are parties to the AEP System Interim Allowance Agreement, which provides, among other things, for the transfer of SO2 allowances associated with the transactions under the Interconnection Agreement.

In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo's generating assets from its distribution and transmission operations. Additionally, the AEP East Companies asked the FERC to terminate the existing Interconnection Agreement and to approve a new Power Coordination Agreement among APCo, I&M and KPCo. A decision from the FERC is expected in mid-2013. See "Corporate Separation and Termination of Interconnection Agreement" section of Note 2.

Power, gas and risk management activities are conducted by AEPSC and profits and losses are allocated under the SIA to members of the Interconnection Agreement, PSO and SWEPCo. Risk management activities involve the purchase and sale of electricity and gas under physical forward contracts at fixed and variable prices. In addition, the risk management of electricity, and to a lesser extent gas contracts, includes exchange traded futures and options and OTC options and swaps. The majority of these transactions represent physical forward contracts in the AEP System’s traditional marketing area and are typically settled by entering into offsetting contracts. In addition, AEPSC enters into transactions for the purchase and sale of electricity and gas options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System’s traditional marketing area.

CSW Operating Agreement

PSO, SWEPCo and AEPSC are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement), which was approved by the FERC. The CSW 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. Parties are compensated for energy delivered to recipients based upon the deliverer’s incremental cost plus a portion of the recipient’s savings realized by the purchaser that avoids the use of more costly alternatives. Revenues and costs arising from third party sales are generally shared based on the amount of energy PSO or SWEPCo contributes that is sold to third parties.

System Integration Agreement (SIA)

The SIA provides for the integration and coordination of AEP East Companies’ and AEP West Companies’ zones. This includes joint dispatch of generation within the AEP System and the distribution, between the two zones, of costs and benefits associated with the transfers of power between the two zones (including sales to third parties and risk management and trading activities). The SIA is designed to function as an umbrella agreement in addition to the Interconnection Agreement and the CSW Operating Agreement, each of which controls the distribution of costs and benefits within a zone.

Power generated, allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any Registrant Subsidiary is primarily sold to customers by such Registrant Subsidiary at rates approved (other than in Ohio) by the public utility commission in the jurisdiction of sale. In Ohio, such rates are based on a statutory formula as that jurisdiction transitions to the use of market rates for generation.

Under both the Interconnection Agreement and CSW Operating Agreement, power generated that is not needed to serve the native load of any Registrant Subsidiary is sold in the wholesale market by AEPSC on behalf of the generating subsidiary.

330

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, natural gas contracts with AEPES and other revenues for the years ended December 31, 2012, 2011 and 2010:

Related Party Revenues			APCo		I&M		OPCo		PSO		SWEPCo
			(in thousands)
Year Ended December 31, 2012
	Sales under Interconnection Agreement		$	166,733	$	265,923	$	643,486	$	-	$	-
	Direct Sales to East Affiliates			124,519		-		136,142		34		142
	Direct Sales to West Affiliates			314		218		454		18,861		23,695
	Direct Sales to AEPEP			-		-		-		-		(583)
	Transmission Agreement and Transmission
		Coordination Agreement Sales		(1,289)		758		26,295		8		12,338
	Natural Gas Contracts with AEPES			-		-		-		-		-
	Other Revenues			27,922		1,509		40,917		3,700		1,849
	Total Affiliated Revenues		$	318,199	$	268,408	$	847,294	$	22,603	$	37,441

Related Party Revenues			APCo		I&M		OPCo		PSO		SWEPCo
			(in thousands)
Year Ended December 31, 2011
	Sales under Interconnection Agreement		$	186,788	$	308,336	$	823,703	$	-	$	-
	Direct Sales to East Affiliates			126,737		-		115,120		124		3,535
	Direct Sales to West Affiliates			1,492		908		1,936		10,624		43,714
	Direct Sales to AEPEP			-		-		-		-		(637)
	Transmission Agreement and Transmission
		Coordination Agreement Sales		2,348		9,379		3,375		111		8,962
	Natural Gas Contracts with AEPES			154		92		196		3		4
	Other Revenues			42,283		1,469		33,669		3,330		2,037
	Total Affiliated Revenues		$	359,802	$	320,184	$	977,999	$	14,192	$	57,615

Related Party Revenues		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Year Ended December 31, 2010
	Sales under Interconnection Agreement	$	158,873	$	327,992	$	839,441	$	-	$	-
	Direct Sales to East Affiliates		123,832		-		115,406		1,210		1,248
	Direct Sales to West Affiliates		3,471		1,931		4,125		19,629		39,851
	Direct Sales to AEPEP		-		-		-		-		(286)
	Direct Sales to Transmission Companies		44		1,848		236		30		1
	Natural Gas Contracts with AEPES		(2,171)		(1,087)		(2,330)		2		3
	Other Revenues		32,158		267		34,407		2,657		11,053
	Total Affiliated Revenues	$	316,207	$	330,951	$	991,285	$	23,528	$	51,870

331

The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and affiliates for the years ended December 31, 2012, 2011 and 2010:

Related Party Purchases		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Year Ended December 31, 2012
	Purchases under Interconnection Agreement	$	661,185	$	147,502	$	174,240	$	-	$	-
	Direct Purchases from East Affiliates		-		-		-		683		368
	Direct Purchases from West Affiliates		53		36		75		23,695		18,861
	Purchases from AEGCo		-		238,866		203,583		-		-
	Gas Purchases from AEPES		-		-		2,808		-		-
	Total Affiliated Purchases	$	661,238	$	386,404	$	380,706	$	24,378	$	19,229

Related Party Purchases		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Year Ended December 31, 2011
	Purchases under Interconnection Agreement	$	818,943	$	124,598	$	326,871	$	-	$	-
	Direct Purchases from East Affiliates		-		-		-		6,378		1,184
	Direct Purchases from West Affiliates		239		147		312		43,714		10,624
	Purchases from AEGCo		-		228,739		185,741		-		-
	Gas Purchases from AEPES		-		-		2,689		-		-
	Total Affiliated Purchases	$	819,182	$	353,484	$	515,613	$	50,092	$	11,808

Related Party Purchases		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Year Ended December 31, 2010
	Purchases under Interconnection Agreement	$	916,791	$	91,129	$	268,964	$	-	$	-
	Direct Purchases from East Affiliates		-		-		-		6,162		4,078
	Direct Purchases from West Affiliates		825		466		996		39,851		19,629
	Direct Purchases from AEGCo		-		235,740		113,801		-		-
	Gas Purchases from AEPES		-		-		2,857		-		-
	Total Affiliated Purchases	$	917,616	$	327,335	$	386,618	$	46,013	$	23,707

The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates 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

AEP’s System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP East Companies’ and AEP West Companies’ zones. Similar to the SIA, the System Transmission Integration Agreement functions as an umbrella agreement in addition to the Transmission Agreement (TA) and the Transmission Coordination Agreement (TCA). The System Transmission Integration Agreement contains two service schedules that govern:

·	The allocation of transmission costs and revenues.

·	The allocation of third-party transmission costs and revenues and AEP System dispatch costs.

The System Transmission Integration Agreement anticipates that additional service schedules may be added as circumstances warrant.

APCo, I&M, KPCo and OPCo are parties to the TA, dated April 1, 1984, as amended, defining how they share the costs associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 kV and above) and certain facilities operated at lower voltages (138 kV and above). This sharing was based upon each company’s MLR until the FERC approved a new TA effective November 2010. The new TA will be phased-in for retail rates, added KGPCo and WPCo as parties to the agreement and changed the allocation method.

332

The following table shows the net charges recorded by the Registrant Subsidiaries for the years ended December 31, 2012 and 2011 related to the new TA:

	Years Ended December 31,
Company	2012			2011
	(in thousands)
APCo		$	20,264		$	4,608
I&M			5,689			1,538
OPCo			6,090			17,186

The charges shown above are recorded in Other Operation expenses on the statements of income.

The following table shows the net charges (credits) allocated among the Registrant Subsidiaries for the year ended December 31, 2010 related to the original TA:

	Year Ended
Company	December 31, 2010
	(in thousands)
APCo		$	(16,079	)
I&M			(25,188	)
OPCo			49,281

The net charges (credits) 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, revised 1999 and 2011, as restated and amended, 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, 2012, 2011 and 2010:

	Years Ended December 31,
Company	2012				2011				2010
	(in thousands)
PSO		$	12,300			$	9,000			$	10,600
SWEPCo			(12,300	)			(9,000	)			(10,500	)

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.

Unit Power Agreements (UPA)

Lawrenceburg UPA between OPCo and AEGCo

In March 2007, OPCo and AEGCo entered into a ten-year UPA for the entire output from the Lawrenceburg Generating Station effective with AEGCo’s purchase of the plant in May 2007. The UPA has an option for an additional two-year period. I&M operates the plant under an agreement with AEGCo. Under the UPA, OPCo 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.

333

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

Cook Coal Terminal, a division of OPCo, performs coal transloading services at cost for APCo and I&M. 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 2012, 2011 and 2010 were as follows:

	Years Ended December 31,
Company	2012		2011		2010
	(in thousands)
APCo	$	942	$	31	$	-
I&M		32,639		21,852		17,208

APCo and I&M recorded the cost of transloading services in Fuel on the balance sheets.

Cook Coal Terminal also performs railcar maintenance services at cost for APCo, I&M, PSO and SWEPCo. 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 2012, 2011 and 2010 were as follows:

	Years Ended December 31,
Company	2012		2011		2010
	(in thousands)
APCo	$	88	$	9	$	7
I&M		3,343		3,012		1,870
PSO		281		542		522
SWEPCo		2,102		2,348		1,044

APCo, I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets.

SWEPCo Railcar Facility

SWEPCo operates a railcar maintenance facility in Alliance, Nebraska. The facility performs maintenance on its own railcars as well as railcars belonging to I&M, PSO and third parties. SWEPCo billed I&M $1.6 million and $2.9 million for railcar services provided in 2012 and 2011, respectively, and billed PSO $232 thousand and $287 thousand in 2012 and 2011, respectively. These billings for SWEPCo, and costs for I&M and PSO, are recorded in Fuel on the balance sheets.

334

I&M Barging, Urea Transloading and Other Services

I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NOx 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	2012		2011		2010
	(in thousands)
AEGCo	$	19,961	$	15,460	$	12,548
APCo		34,725		27,455		28,241
KPCo		74		122		133
OPCo		39,956		36,980		44,160
AEP River Operations LLC – (Nonutility
Subsidiary of AEP)		20,917		25,356		20,729

Services Provided by AEP River Operations LLC

AEP River Operations LLC provides services for barge towing, chartering and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation expenses. For the years ended December 31, 2012, 2011 and 2010, I&M recorded expenses of $24 million, $24 million and $28 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	2012		2011		2010
	(in thousands)
AEGCo	$	80	$	102	$	180
I&M		1,280		2,157		2,112
KPCo		277		298		368
OPCo		3,838		3,684		3,665
PSO		1,198		53		412
SWEPCo		145		946		560

Affiliate Coal Purchases

In 2008, OPCo entered into contracts to sell excess coal purchases to certain AEP subsidiaries through 2010. These purchases are reflected in Sales to AEP Affiliates on the statements of income. The following table shows the realized and unrealized amounts recorded for the year ended December 31, 2010:

	Year Ended
Company	December 31, 2010
	(in thousands)
APCo		$	2,830
I&M			1,383
KPCo			837
PSO			796
SWEPCo			1,526

335

Affiliate Railcar Agreement

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, 2012
Billing Company

Billed Company	APCo		I&M		OPCo		PSO		SWEPCo
	(in thousands)
APCo	$	-	$	2	$	1,960	$	-	$	2
I&M		148		-		889		48		843
KPCo		98		-		41		-		-
OPCo		854		170		-		5		99
PSO		204		322		74		-		176
SWEPCo		543		1,468		321		21		-

December 31, 2011
Billing Company

Billed Company	APCo		I&M		OPCo		PSO		SWEPCo
	(in thousands)
APCo	$	-	$	-	$	1,373	$	-	$	-
I&M		91		-		1,190		80		787
KPCo		289		-		355		-		-
OPCo		840		170		-		8		66
PSO		289		842		234		-		382
SWEPCo		12		2,662		605		91		-

OVEC

AEP, OPCo and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2012, AEP’s and OPCo’s ownership and investment in OVEC were as follows:

	December 31, 2012
Company	Ownership		Investment
			(in thousands)
AEP	39.17	%	$	3,978
OPCo	4.30	%		430
Total	43.47	%	$	4,408

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 2,200 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. In 2011, the intercompany power agreement was extended until June 2040.

AEP, OPCo and other nonaffiliated owners authorized environmental investments related to their ownership interests and OVEC’s Board of Directors authorized capital expenditures totaling $1.4 billion in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at OVEC’s two generating plants. As of December 31, 2012, OVEC completed financing of $1.4 billion required for these environmental projects through debt issuances. As of December 31, 2012, one plant was operating with new environmental controls and the other plant is scheduled to be operational with new environmental controls during the second quarter of 2013.

336

Purchased Power from OVEC

The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2012, 2011 and 2010 were:

	Years Ended December 31,
Company	2012		2011		2010
	(in thousands)
APCo	$	98,417	$	114,311	$	105,307
I&M		49,239		57,192		52,687
OPCo		125,013		145,207		133,776

The amounts shown above are recoverable from customers and are included in Purchased Electricity for Resale on the statements of income.

Purchases from OVEC under the Interconnection Agreement

In 2011, the parties to the Interconnection Agreement purchased power from OVEC to serve off-system sales and retail sales. These purchases are reported in Purchased Electricity for Resale on the statements of income. The following table shows the amounts recorded for the year ended December 31, 2011:

	Year Ended
Company	December 31, 2011
	(in thousands)
APCo		$	21,110
I&M			12,942
OPCo			27,566

In January 2010, the parties to the Interconnection Agreement purchased power from OVEC to serve off-system sales and retail sales through June 2010. Purchases serving off-system sales are reported net as a reduction in Electric Generation, Transmission and Distribution revenues and purchases serving retail sales are reported in Purchased Electricity for Resale on the statements of income. The following table shows the amounts recorded for the year ended December 31, 2010:

	Year Ended December 31, 2010
	Reported in		Reported in
Company	Revenues		Expenses

	(in thousands)
APCo	$	6,631	$	3,635
I&M		3,721		1,980
OPCo		7,937		4,231

337

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, that were recorded at net book value, for the years ended December 31, 2012, 2011 and 2010:

Sales
	Years Ended December 31,
Company	2012		2011		2010
	(in thousands)
APCo	$	6,643	$	3,978	$	2,004
I&M		3,296		441		1,842
OPCo		4,163		12,113		8,919
PSO		1,782		442		2,156
SWEPCo		1,731		650		5,233

Purchases
	Years Ended December 31,
Company	2012		2011		2010
	(in thousands)
APCo	$	2,522	$	2,312	$	4,732
I&M		285		3,678		4,117
OPCo		10,608		3,045		1,652
PSO		1,867		475		5,146
SWEPCo		7,266		2,993		2,612

The amounts above are recorded in Property, Plant and Equipment on the balance sheets.

Global Borrowing Notes

As of December 31, 2012 and 2011, AEP has an intercompany note in place with OPCo. The debt is reflected in Long-term Debt – Affiliated on OPCo’s balance sheets. OPCo accrues interest for its share of the global borrowing and remits the interest to AEP. The accrued interest is reflected in Accrued Interest on OPCo’s 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.

14. VARIABLE INTEREST ENTITIES

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.

338

SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. APCo, I&M, OPCo, PSO and SWEPCo each hold a significant variable interest in AEPSC. I&M and OPCo each hold a significant variable interest in AEGCo. SWEPCo holds a significant variable interest in DHLC.

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, 2012, 2011 and 2010 were $147 million, $128 million and $133 million, respectively. See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets.

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

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
December 31, 2012 and 2011
(in thousands)
	Sabine
	2012		2011
ASSETS
Current Assets	$	56,535	$	48,044
Net Property, Plant and Equipment		170,436		153,715
Other Noncurrent Assets		55,076		42,574
Total Assets	$	282,047	$	244,333

LIABILITIES AND EQUITY
Current Liabilities	$	31,446	$	67,779
Noncurrent Liabilities		250,340		176,163
Equity		261		391
Total Liabilities and Equity	$	282,047	$	244,333

I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC and DCC Fuel V LLC (collectively DCC Fuel). DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the years ended December 31, 2012, 2011 and 2010 were $127 million, $85 million and $59 million, respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on 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.

339

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

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
December 31, 2012 and 2011
(in thousands)
	DCC Fuel
ASSETS	2012		2011
Current Assets	$	132,886	$	118,144
Net Property, Plant and Equipment		176,065		188,375
Other Noncurrent Assets		92,473		117,772
Total Assets	$	401,424	$	424,291

LIABILITIES AND EQUITY
Current Liabilities	$	120,873	$	102,946
Noncurrent Liabilities		280,551		321,345
Equity		-		-
Total Liabilities and Equity	$	401,424	$	424,291

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, 2012, 2011 and 2010 were $77 million, $62 million and $56 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,
	2012				2011
	As Reported on		Maximum		As Reported on		Maximum
	the Balance Sheet		Exposure		the Balance Sheet		Exposure
	(in thousands)
Capital Contribution from SWEPCo	$	7,643	$	7,643	$	7,643	$	7,643
Retained Earnings		946		946		1,120		1,120
SWEPCo's Guarantee of Debt		-		49,564		-		52,310

Total Investment in DHLC	$	8,589	$	58,153	$	8,763	$	61,073

AEPSC provides certain managerial and professional services to AEP’s subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

340

Total AEPSC billings to the Registrant Subsidiaries were as follows:

	Years Ended December 31,
Company	2012		2011		2010
	(in thousands)
APCo	$	195,176	$	195,787	$	238,367
I&M		127,232		126,505		139,920
OPCo		277,232		279,652		332,431
PSO		89,199		84,028		102,116
SWEPCo		136,642		130,148		147,928

The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:

	December 31,
	2012				2011
	As Reported on		Maximum		As Reported on		Maximum
Company	the Balance Sheet		Exposure		the Balance Sheet		Exposure
	(in thousands)
APCo	$	29,819	$	29,819	$	20,812	$	20,812
I&M		17,911		17,911		13,741		13,741
OPCo		39,323		39,323		29,823		29,823
PSO		13,381		13,381		9,280		9,280
SWEPCo		19,669		19,669		14,699		14,699

AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant Unit 1, leases a 50% interest in Rockport Plant Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo leases the Lawrenceburg Generating Station to OPCo. AEP guarantees all the debt obligations of AEGCo. I&M and OPCo are considered to have a significant interest in AEGCo due to these transactions. I&M and OPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M, OPCo and KPCo, this financing would be provided by AEP. For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 11.

Total billings from AEGCo were as follows:

	Years Ended December 31,
Company	2012		2011		2010
	(in thousands)
I&M	$	238,865	$	228,739	$	235,741
OPCo		203,582		185,741		113,801

The carrying amount and classification of variable interest in AEGCo's accounts payable are as follows:

	December 31,
	2012				2011
	As Reported on		Maximum		As Reported on		Maximum
Company	the Balance Sheet		Exposure		the Balance Sheet		Exposure
	(in thousands)
I&M	$	25,498	$	25,498	$	25,731	$	25,731
OPCo		16,302		16,302		22,139		22,139

341

15. PROPERTY, PLANT AND EQUIPMENT

Depreciation, Depletion and Amortization

The Registrant Subsidiaries 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 annual property information for the Registrant Subsidiaries:

APCo

2012	Regulated									Nonregulated
					Annual									Annual
Functional	Property,				Composite					Property,				Composite
Class of	Plant and		Accumulated		Depreciation		Depreciable			Plant and		Accumulated		Depreciation	Depreciable
Property	Equipment		Depreciation		Rate		Life Ranges			Equipment		Depreciation		Rate	Life Ranges
	(in thousands)						(in years)			(in thousands)					(in years)
Generation	$	5,632,665	$	1,928,562	3.0	%	40	-	121	$	-	$	-	NA	NA
Transmission		2,042,144		468,633	1.6	%	25	-	87		-		-	NA	NA
Distribution		2,991,898		641,504	3.4	%	13	-	57		-		-	NA	NA
CWIP		266,247		(19,379)	NM		NM				-		-	NA	NA
Other		340,027		164,932	6.8	%	24	-	55		33,300		12,387	NM	NM
Total	$	11,272,981	$	3,184,252						$	33,300	$	12,387

2011	Regulated									Nonregulated
					Annual									Annual
Functional	Property,				Composite					Property,				Composite
Class of	Plant and		Accumulated		Depreciation		Depreciable			Plant and		Accumulated		Depreciation	Depreciable
Property	Equipment		Depreciation		Rate		Life Ranges			Equipment		Depreciation		Rate	Life Ranges
	(in thousands)						(in years)			(in thousands)					(in years)
Generation	$	5,194,967	$	1,783,154	2.6	%	40	-	121	$	-	$	-	NA	NA
Transmission		1,943,969		457,235	1.6	%	25	-	87		-		-	NA	NA
Distribution		2,845,405		595,122	3.2	%	11	-	52		-		-	NA	NA
CWIP		565,841		(9,918)	NM		NM				-		-	NA	NA
Other		323,630		155,688	6.6	%	24	-	55		33,696		12,735	NM	NM
Total	$	10,873,812	$	2,981,281						$	33,696	$	12,735

2010

Regulated

Nonregulated

Annual Composite

Depreciable

Annual Composite

Depreciable

Functional Class of Property

Depreciation Rate

Life Ranges

Depreciation Rate

Life Ranges

(in years)

Generation

2.4

121

Transmission

1.6

Distribution

3.2

CWIP

Other

7.8

NA Not applicable.

NM Not meaningful.

342

I&M

2012	Regulated									Nonregulated
					Annual									Annual
Functional	Property,				Composite					Property,				Composite
Class of	Plant and		Accumulated		Depreciation		Depreciable			Plant and		Accumulated		Depreciation	Depreciable
Property	Equipment		Depreciation		Rate		Life Ranges			Equipment		Depreciation		Rate	Life Ranges
	(in thousands)						(in years)			(in thousands)					(in years)
Generation	$	4,062,733	$	2,130,136	1.7	%	59	-	132	$	-	$	-	NA	NA
Transmission		1,278,236		411,825	1.5	%	46	-	75		-		-	NA	NA
Distribution		1,553,358		373,342	2.5	%	14	-	70		-		-	NA	NA
CWIP		341,063		65,449	NM		NM				-		-	NA	NA
Other		573,836		141,291	9.6	%	14	-	40		151,477		110,092	NM	NM
Total	$	7,809,226	$	3,122,043						$	151,477	$	110,092

2011	Regulated									Nonregulated
					Annual									Annual
Functional	Property,				Composite					Property,				Composite
Class of	Plant and		Accumulated		Depreciation		Depreciable			Plant and		Accumulated		Depreciation	Depreciable
Property	Equipment		Depreciation		Rate		Life Ranges			Equipment		Depreciation		Rate	Life Ranges
	(in thousands)						(in years)			(in thousands)					(in years)
Generation	$	3,932,472	$	2,078,651	1.6	%	59	-	132	$	-	$	-	NA	NA
Transmission		1,224,786		414,941	1.4	%	46	-	75		-		-	NA	NA
Distribution		1,481,608		374,137	2.4	%	14	-	70		-		-	NA	NA
CWIP		236,096		60,665	NM		NM				-		-	NA	NA
Other		559,698		143,312	7.4	%	NM				149,860		108,214	NM	NM
Total	$	7,434,660	$	3,071,706						$	149,860	$	108,214

2010

Regulated

Nonregulated

Annual Composite

Depreciable

Annual Composite

Depreciable

Functional Class of Property

Depreciable Rate

Life Ranges

Depreciable Rate

Life Ranges

(in years)

Generation

1.6

132

Transmission

1.4

Distribution

2.5

CWIP

Other

11.7

NA Not applicable.

NM Not meaningful.

343

OPCo

2012	Regulated									Nonregulated
					Annual									Annual
Functional	Property,				Composite					Property,				Composite
Class of	Plant and		Accumulated		Depreciation		Depreciable			Plant and		Accumulated		Depreciation		Depreciable
Property	Equipment		Depreciation		Rate		Life Ranges			Equipment		Depreciation		Rate		Life Ranges
	(in thousands)						(in years)			(in thousands)						(in years)
Generation	$	-	$	-	NA		NA			$	8,673,296	$	3,200,427	3.0	%	35	-	66
Transmission		2,013,737		809,199	2.3	%	39	-	60		-		-	NA		NA
Distribution		3,722,745		1,011,324	2.7	%	12	-	60		-		-	NA		NA
CWIP		147,408		(21,198)	NM		NM				207,089		1,350	NM		NM
Other		427,412		224,153	7.3	%	25	-	50		143,742		17,550	NM		NM
Total	$	6,311,302	$	2,023,478						$	9,024,127	$	3,219,327

2011	Regulated									Nonregulated
					Annual									Annual
Functional	Property,				Composite					Property,				Composite
Class of	Plant and		Accumulated		Depreciation		Depreciable			Plant and		Accumulated		Depreciation		Depreciable
Property	Equipment		Depreciation		Rate		Life Ranges			Equipment		Depreciation		Rate		Life Ranges
	(in thousands)						(in years)			(in thousands)						(in years)
Generation	$	-	$	-	NA		NA			$	9,502,614	$	3,596,589	3.2	%	35	-	66
Transmission		1,948,329		763,664	2.3	%	27	-	70		-		-	NA		NA
Distribution		3,545,574		1,146,202	3.7	%	12	-	56		-		-	NA		NA
CWIP		183,096		(3,371)	NM		NM				171,369		1,152	NM		NM
Other		407,044		222,368	8.7	%	NM				139,598		15,957	NM		NM
Total	$	6,084,043	$	2,128,863						$	9,813,581	$	3,613,698

2010

Regulated

Nonregulated

Annual Composite

Depreciation

Depreciable

Depreciation

Depreciable

Functional Class of Property

Rate

Life Ranges

Rate

Life Ranges

(in years)

Generation

3.3

Transmission

2.3

Distribution

3.7

CWIP

Other

9.2

NA Not applicable.

NM Not meaningful.

344

PSO

2012	Regulated									Nonregulated
					Annual									Annual
Functional	Property,				Composite					Property,				Composite
Class of	Plant and		Accumulated		Depreciation		Depreciable			Plant and		Accumulated		Depreciation	Depreciable
Property	Equipment		Depreciation		Rate		Life Ranges			Equipment		Depreciation		Rate	Life Ranges
	(in thousands)						(in years)			(in thousands)					(in years)
Generation	$	1,346,530	$	654,989	1.7	%	35	-	70	$	-	$	-	NA	NA
Transmission		706,917		176,187	1.9	%	40	-	75		-		-	NA	NA
Distribution		1,859,557		345,207	2.4	%	30	-	65		-		-	NA	NA
CWIP		95,170		(9,281)	NM		NM				-		-	NA	NA
Other		205,373		111,837	6.6	%	5	-	40		5,176		2	NM	NM
Total	$	4,213,547	$	1,278,939						$	5,176	$	2

2011	Regulated									Nonregulated
					Annual									Annual
Functional	Property,				Composite					Property,				Composite
Class of	Plant and		Accumulated		Depreciation		Depreciable			Plant and		Accumulated		Depreciation	Depreciable
Property	Equipment		Depreciation		Rate		Life Ranges			Equipment		Depreciation		Rate	Life Ranges
	(in thousands)						(in years)			(in thousands)					(in years)
Generation	$	1,317,948	$	652,526	1.8	%	9	-	70	$	-	$	-	NA	NA
Transmission		692,644		167,827	1.9	%	40	-	75		-		-	NA	NA
Distribution		1,762,110		329,041	2.4	%	30	-	65		-		-	NA	NA
CWIP		70,371		(5,413)	NM		NM				-		-	NA	NA
Other		209,467		122,838	8.3	%	5	-	35		5,159		(3)	NM	NM
Total	$	4,052,540	$	1,266,819						$	5,159	$	(3)

2010

Regulated

Nonregulated

Annual Composite

Depreciation

Depreciable

Depreciation

Depreciable

Functional Class of Property

Rate

Life Ranges

Rate

Life Ranges

(in years)

Generation

1.8

Transmission

1.9

Distribution

2.4

CWIP

Other

8.3

NA Not applicable.

NM Not meaningful.

345

SWEPCo

2012	Regulated										Nonregulated
						Annual									Annual
Functional	Property,					Composite					Property,				Composite
Class of	Plant and			Accumulated		Depreciation		Depreciable			Plant and		Accumulated		Depreciation	Depreciable
Property	Equipment			Depreciation		Rate		Life Ranges			Equipment		Depreciation		Rate	Life Ranges
	(in thousands)							(in years)			(in thousands)					(in years)
Generation	$	3,888,230		$	1,092,566	2.2	%	35	-	65	$	-	$	-	NA	NA
Transmission		1,115,795			301,159	2.3	%	50	-	70		-		-	NA	NA
Distribution		1,758,988			556,904	2.6	%	25	-	65		-		-	NA	NA
CWIP		99,783	(a)		(8,294)	NM		NM				-		-	NA	NA
Other		397,643			225,254	6.6	%	7	-	47		290,611		116,669	NM	NM
Total	$	7,260,439		$	2,167,589						$	290,611	$	116,669

2011	Regulated										Nonregulated
						Annual									Annual
Functional	Property,					Composite					Property,				Composite
Class of	Plant and			Accumulated		Depreciation		Depreciable			Plant and		Accumulated		Depreciation	Depreciable
Property	Equipment			Depreciation		Rate		Life Ranges			Equipment		Depreciation		Rate	Life Ranges
	(in thousands)							(in years)			(in thousands)					(in years)
Generation	$	2,326,102		$	1,060,825	2.1	%	35	-	68	$	-	$	-	NA	NA
Transmission		988,534			285,785	2.3	%	50	-	70		-		-	NA	NA
Distribution		1,675,764			535,565	2.6	%	25	-	65		-		-	NA	NA
CWIP		1,419,216	(a)		(3,527)	NM		NM				24,353		-	NM	NM
Other		400,492			229,695	6.9	%	7	-	47		236,527		103,569	NM	NM
Total	$	6,810,108		$	2,108,343						$	260,880	$	103,569

2010

Regulated

Nonregulated

Annual Composite

Depreciation

Depreciable

Depreciation

Depreciable

Functional Class of Property

Rate

Life Ranges

Rate

Life Ranges

(in years)

Generation

1.9

Transmission

2.4

Distribution

2.7

CWIP

Other

7.7

(a) Includes CWIP related to SWEPCo's Arkansas jurisdictional share of the Turk Plant.

NA Not applicable.

NM Not meaningful.

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 rate-regulated operations, the composite depreciation rate generally includes a component for nonasset 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.

346

Asset Retirement Obligations (ARO)

The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries 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 Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected.

As of December 31, 2012 and 2011, I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.2 billion and $979 million, respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2012 and 2011, the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.4 billion and $1.3 billion, respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets.

The following is a reconciliation of the 2012 and 2011 aggregate carrying amounts of ARO by Registrant Subsidiary:

	ARO as of								Revisions in		ARO as of
	December 31,		Accretion		Liabilities		Liabilities		Cash Flow		December 31,
Company	2011		Expense		Incurred		Settled		Estimates		2012
	(in thousands)
APCo (a)(d)	$	112,767	$	7,264	$	-	$	(8,921)	$	4,058	$	115,168
I&M (a)(b)(d)		1,013,122		53,848		-		(806)		126,149		1,192,313
OPCo (a)(d)		241,828		15,113		-		(8,294)		21,293		269,940
PSO (a)(d)		19,623		1,572		84		(949)		1,669		21,999
SWEPCo (a)(c)(d)(e)		67,183		5,511		17,380		(3,831)		(8,226)		78,017

	ARO as of								Revisions in		ARO as of
	December 31,		Accretion		Liabilities		Liabilities		Cash Flow		December 31,
Company	2010		Expense		Incurred		Settled		Estimates		2011
	(in thousands)
APCo (a)(d)	$	141,924	$	9,534	$	3	$	(3,600)	$	(35,094)	$	112,767
I&M (a)(b)(d)		963,029		51,308		-		(1,370)		155		1,013,122
OPCo (a)(d)		189,271		13,499		165		(4,872)		43,765		241,828
PSO (a)(d)		21,557		1,708		-		(414)		(3,228)		19,623
SWEPCo (a)(c)(d)(e)		59,382		4,114		7,063		(14,947)		11,571		67,183

(a)	Includes ARO related to ash disposal facilities.

(b)	Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.2 billion and $979 million as of December 31, 2012 and 2011, respectively.

(c)	Includes ARO related to Sabine and DHLC.

(d)	Includes ARO related to asbestos removal.

(e)	The current portion of SWEPCo’s ARO totaling $1.5 million as of December 31, 2011 is included in Other Current Liabilities on SWEPCo’s balance sheets.

347

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

The Registrant Subsidiaries’ amounts of allowance for equity funds used during construction are summarized in the following table:

	Years Ended December 31,
Company	2012		2011		2010
	(in thousands)
APCo	$	1,684	$	9,212	$	2,967
I&M		9,724		15,395		15,678
OPCo		3,492		5,549		5,949
PSO		2,007		1,317		804
SWEPCo		57,054		48,731		45,646

The Registrant Subsidiaries’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table:

	Years Ended December 31,
Company	2012		2011		2010
	(in thousands)
APCo	$	1,347	$	6,257	$	2,251
I&M		4,717		7,838		8,500
OPCo		9,046		2,350		3,786
PSO		1,098		822		572
SWEPCo		48,499		40,904		33,668

348

Jointly-owned Electric Facilities

The Registrant Subsidiaries have electric facilities that are jointly-owned with affiliated and nonaffiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of any such jointly-owned facilities in the same proportion as its ownership interest. Each Registrant Subsidiary’s proportionate share of the operating costs associated with such 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:

					Company’s Share as of December 31, 2012
							Construction
		Fuel	Percent of		Utility Plant		Work in		Accumulated
Company		Type	Ownership		in Service		Progress		Depreciation
					(in thousands)
APCo
John E. Amos Generating Station (Unit No. 3) (a)		Coal	33.33	%	$	563,470	$	14,188	$	108,441

I&M
Rockport Generating Plant (Unit No. 1) (b)		Coal	50.0	%	$	762,737	$	55,420	$	456,436

OPCo
John E. Amos Generating Station (Unit No. 3) (a)		Coal	66.67	%	$	995,005	$	14,093	$	213,163
W.C. Beckjord Generating Station		Coal	12.5	%		-		-		-
2	(Unit No. 6) (c)
Conesville Generating Station (Unit No. 4) (d)		Coal	43.5	%		310,342		26,067		58,677
J.M. Stuart Generating Station (e)		Coal	26.0	%		541,719		11,151		180,687
Wm. H. Zimmer Generating Station (c)		Coal	25.4	%		807,431		1,817		387,209
Transmission		NA	(f)			69,148		4,101		50,516
Total					$	2,723,645	$	57,229	$	890,252

PSO
Oklaunion Generating Station (Unit No. 1) (g)		Coal	15.6	%	$	93,218	$	939	$	57,060

SWEPCo
Dolet Hills Generating Station (Unit No. 1) (h)		Lignite	40.2	%	$	262,649	$	7,523	$	195,336
Flint Creek Generating Station (Unit No. 1) (i)		Coal	50.0	%		121,052		14,272		64,348
Pirkey Generating Station (Unit No. 1) (i)		Lignite	85.9	%		513,833		16,029		371,015
Turk Generating Plant (j)		Coal	73.33	%		1,612,618		(2,669)		59
Total					$	2,510,152	$	35,155	$	630,758

349

					Company’s Share as of December 31, 2011
							Construction
		Fuel	Percent of		Utility Plant		Work in		Accumulated
Company		Type	Ownership		in Service		Progress		Depreciation
					(in thousands)
APCo
John E. Amos Generating Station (Unit No. 3) (a)		Coal	33.33	%	$	554,555	$	16,987	$	93,404

I&M
Rockport Generating Plant (Unit No. 1) (b)		Coal	50.0	%	$	759,033	$	19,357	$	443,857

OPCo
John E. Amos Generating Station (Unit No. 3) (a)		Coal	66.67	%	$	988,510	$	15,344	$	188,820
W.C. Beckjord Generating Station		Coal	12.5	%		19,131		108		8,476
	(Unit No. 6) (c)
Conesville Generating Station (Unit No. 4) (d)		Coal	43.5	%		309,771		11,633		53,980
J.M. Stuart Generating Station (e)		Coal	26.0	%		528,271		13,292		171,830
Wm. H. Zimmer Generating Station (c)		Coal	25.4	%		771,158		19,949		376,585
Transmission		NA	(f)			63,115		5,805		49,487
Total					$	2,679,956	$	66,131	$	849,178

PSO
Oklaunion Generating Station (Unit No. 1) (g)		Coal	15.6	%	$	92,805	$	446	$	56,539

SWEPCo
Dolet Hills Generating Station (Unit No. 1) (h)		Lignite	40.2	%	$	264,487	$	465	$	193,565
Flint Creek Generating Station (Unit No. 1) (i)		Coal	50.0	%		118,163		6,532		62,988
Pirkey Generating Station (Unit No. 1) (i)		Lignite	85.9	%		512,557		674		361,667
Turk Generating Plant (j)		Coal	73.33	%		-		1,326,013		-
Total					$	895,207	$	1,333,684	$	618,220

(a) Operated by APCo.

(b) Operated by I&M.

(c)	Operated by Duke Energy Corporation, a nonaffiliated company. AEP's portion of this unit was impaired in the fourth quarter of 2012. See "Impairments" section of Note 5.

(d) Operated by OPCo.

(e) Operated by The Dayton Power & Light Company, a nonaffiliated company.

(f) Varying percentages of ownership.

(g) Operated by PSO and also jointly-owned (54.7%) by TNC.

(h) Operated by CLECO, a nonaffiliated company.

(i) Operated by SWEPCo.

(j)

Turk Generating Plant was placed in service in December 2012. SWEPCo jointly owns the plant with Arkansas Electric Cooperative Corporation (11.67%), East Texas Electric Cooperative (8.33%) and Oklahoma Municipal Power Authority (6.67%). Through December 2012, construction costs totaling $457 million have been billed to the other owners.

NA Not applicable.

350

16. COST REDUCTION PROGRAMS

2012 Sustainable Cost Reductions

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

The Registrant Subsidiaries recorded a charge to expense during 2012 related to the sustainable cost reductions initiative.

	Expense		Incurred for				Remaining
	Allocation from		Registrant				Balance as of
	AEPSC		Subsidiaries		Settled		December 31, 2012
	(in thousands)
APCo	$	6,452	$	2,020	$	(7,151)	$	1,321
I&M		4,167		1,511		(4,321)		1,357
OPCo		9,225		4,273		(10,048)		3,450
PSO		3,020		655		(3,023)		652
SWEPCo		4,199		1,510		(5,082)		627

These expenses relate primarily to severance benefits. They are included primarily in Other Operation expense on the statement of income and Other Current Liabilities on the balance sheet.

2010 Cost Reduction Initiatives

In April 2010, management began initiatives to decrease both labor and non-labor expenses with a goal of achieving significant reductions in operation and maintenance expenses. A total of 2,461 positions was eliminated across the AEP System as a result of process improvements, streamlined organizational designs and other efficiencies. Many of these eliminated positions resulted from employees that elected retirement through voluntary severance. Most of the affected employees terminated employment as of May 31, 2010. The severance program provided two weeks of base pay for every year of service along with other severance benefits.

The Registrant Subsidiaries recorded a charge to Other Operation expense during 2010 primarily related to severance benefits as the result of headcount reduction initiatives. The total amount incurred in 2010 by Registrant Subsidiary was as follows:

Company	Total Cost Incurred
	(in thousands)
APCo	$	56,925
I&M		45,036
OPCo		85,400
PSO		24,005
SWEPCo		29,662

For the Registrant Subsidiaries who had cost reduction activity remaining as of December 31, 2011, the activity for 2012 is described in the following table:

	Balance as of						Balance as of
Company	December 31, 2011		Settled		Adjustments		December 31, 2012
	(in thousands)
APCo	$	92	$	-	$	(92)	$	-
OPCo		138		(138)		-		-

351

17. UNAUDITED QUARTERLY FINANCIAL INFORMATION

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 Subsidiary is as follows:

Quarterly Periods Ended:	APCo		I&M		OPCo			PSO		SWEPCo
	(in thousands)
March 31, 2012
Total Revenues	$	805,476	$	546,207	$	1,237,223		$	300,531	$	348,986
Operating Income		169,190		76,325		269,619			33,490		55,368
Net Income		75,311		39,221		150,830			12,648		36,395

June 30, 2012
Total Revenues	$	716,461	$	510,876	$	1,113,750		$	317,311	$	390,946
Operating Income		143,426		64,803		210,004			69,299		72,976
Net Income		62,332		29,810		101,423			35,211		54,902

September 30, 2012
Total Revenues	$	864,198	$	598,204	$	1,359,816		$	372,872	$	485,169
Operating Income		142,722		80,486		279,109			106,196		120,008
Net Income		63,191		39,254		151,510			58,103		89,218

December 31, 2012
Total Revenues	$	890,796	$	544,824	$	1,217,407		$	242,224	$	352,733
Operating Income (Loss)		142,122		26,080		(81,785)	(a)		21,965		27,544
Net Income (Loss)		56,669		10,172		(60,229)	(a)		8,179		21,998

Quarterly Periods Ended:	APCo			I&M		OPCo			PSO		SWEPCo
	(in thousands)
March 31, 2011
Total Revenues	$	831,820		$	560,492	$	1,394,190		$	288,003	$	362,955
Operating Income		116,061	(b)		95,994		299,396			38,881		54,528
Net Income		38,980	(b)		45,427		165,970			15,389		29,827

June 30, 2011
Total Revenues	$	751,445		$	521,478	$	1,285,558		$	328,588	$	399,534
Operating Income		88,567			64,351		261,534			64,185		80,054
Net Income		31,627			31,386		142,194			31,560		51,071

September 30, 2011
Total Revenues	$	858,336		$	611,232	$	1,540,231		$	457,586	$	534,982
Operating Income		122,716			100,352		210,453	(c)		103,006		128,406
Net Income		52,804			51,702		128,339	(c)		57,349		87,795

December 31, 2011
Total Revenues	$	763,624		$	521,568	$	1,211,132		$	289,211	$	356,355
Operating Income (Loss)		102,236	(d)		20,959		63,321	(e)		34,939		(12,731)	(f)
Net Income (Loss)		39,347	(d)		21,159		28,490	(e)		20,330		(3,567)	(f)

(a)	Includes pretax impairments for certain Ohio generation plants (see Note 5).

(b)

Includes a $41 million increase due to the pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC. This increase was partially offset by the $32 million decrease due to the deferral of 2010 costs related to storms and cost reduction initiatives as allowed by the WVPSC.

(c)	Includes pretax plant impairments for the Sporn Unit 5 shutdown and FGD project at Muskingum River Unit 5 (see Note 5). Also includes a $43 million provision for refund of POLR charges.

(d)

Includes a $31 million pretax write-off related to the disallowance of certain Virginia environmental costs incurred in 2009 and 2010 as a result of APCo’s November 2011 Virginia SCC order. Includes a $27 million increase due to a favorable Asset Retirement Obligation adjustment related to the early closure and previous write-off of the Mountaineer Carbon Capture and Storage Product Validation Facility.

(e)	Includes provisions related to the FAC, the 2010 SEET and the obligation to contribute to Partnership with Ohio and Ohio Growth Fund.

(f)	Includes a pretax plant impairment for the Turk Plant (see Note 5).

352

COMBINED MANAGEMENT’S NARRATIVE DISCUSSION

AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the Registrant Subsidiaries’ management’s discussion and analysis. The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (a) Management’s Narrative Discussion and Analysis of Results of Operations, (b) financial statements, (c) footnotes and (d) the schedules of each individual registrant.

EXECUTIVE OVERVIEW

Sustainable Cost Reductions

In April 2012, a process was initiated to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings. Management selected a consulting firm to conduct an organizational and process optimization evaluation and a second firm to evaluate the Registrant Subsidiaries’ current employee benefit programs. A charge was recorded to expense of $47 million ($30 million, net of tax) in 2012 related primarily to severance benefits. Management expects to complete the final phase of the sustainable cost reduction program by the end of the first quarter of 2013. Going forward, management anticipates that this program provides a behavioral foundation upon which additional process improvement projects will be implemented as a regular business practice. At this time, management is unable to estimate the total amount to be incurred in future periods related to this initiative or to quantify the effects on future earnings, cash flows and financial condition.

Customer Demand

In comparison to 2011, cooling degree days in 2012 were down 6% in AEP’s western region and up 4% in AEP’s eastern region. Heating degree days in 2012 were down in AEP’s western and eastern regions by 36% and 15%, respectively. Weather-normalized retail sales across the AEP System were down 0.7% compared to 2011. OPCo’s weather-normalized industrial sales declined 4.4% partially due to Ormet, a large aluminum company that lowered their production in the third quarter of 2012 by one-third. In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware.

In 2013, management anticipates slight increases in retail sales in AEP’s eastern region related to shale gas development and processing and in AEP’s western region related to oil and gas extraction. Management also anticipates decreases in OPCo’s industrial demand related to Ormet’s lower production levels discussed above.

LITIGATION

Potential Uninsured Losses

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 damage to the Cook Plant and costs of replacement power in the event of a nuclear incident at the Cook Plant. Future losses or liabilities, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition.

ENVIRONMENTAL ISSUES

The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements. The Registrant Subsidiaries will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, new proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.

The Registrant Subsidiaries are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of I&M’s nuclear units. AEP, various industry groups, affected states and other parties have

353

challenged some of the Federal EPA requirements in court. Management is also engaged in the development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change. Management believes that further analysis and better coordination of these future environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Recovery in Ohio will be dependent upon prevailing market conditions. If the Registrant Subsidiaries are unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of December 31, 2012, the AEP System had a total generating capacity of nearly 37,600 MWs, of which over 23,700 MWs are coal-fired. Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the coal-fired generating facilities. For the Registrant Subsidiaries, management’s current ranges of estimates of environmental investments to comply with these proposed requirements are listed below:

	2012 to 2020
	Estimated Environmental Investment
Company	Low		High
	(in millions)
APCo	$	330	$	440
I&M		510		610
OPCo		840		1,080
PSO		310		380
SWEPCo		1,430		1,750

For APCo, I&M and OPCo, the projected environmental investments above include the conversions of 470 MWs, 500 MWs and 585 MWs of coal generation to natural gas generation, respectively. If natural gas conversion is not completed, these units could be retired sooner than planned.

The preceding discussion of environmental investments and plans for future years reflects the ownership of plants as of December 31, 2012. The AEP East Companies have filed with the FERC to terminate the Interconnection Agreement and for OPCo to transfer facilities to APCo, KPCo and AEPGenCo. Management expects the transfers will be effective December 31, 2013.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules. The cost estimates for each Registrant Subsidiary will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose standards more stringent than the proposed rules, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.

354

Subject to the factors listed above and based upon management’s continuing evaluation, management has given notice to the applicable RTOs of intent to retire the following plants or units of plants before or during 2016:

		Generating
Company	Plant Name and Unit	Capacity
		(in MWs)
APCo	Clinch River Plant, Unit 3		235
APCo	Glen Lyn Plant		335
APCo	Kanawha River Plant		400
APCo/OPCo	Philip Sporn Plant, Units 1-4		600
I&M	Tanners Creek Plant, Units 1-3		495
OPCo	Kammer Plant		630
OPCo	Muskingum River Plant, Units 1-4		840
OPCo	Picway Plant		100
SWEPCo	Welsh Plant, Unit 2		528

Duke Energy Corporation, the operator of W. C. Beckjord Generating Station, has announced its intent to close the facility in 2015. OPCo owns 12.5% (53 MWs) of one unit at that station.

In September 2012, based upon an agreement in principle with the Federal EPA, the State of Oklahoma and other parties, PSO filed an environmental compliance plan with the OCC to retire Units 3 and 4 of the Northeastern Station, a total of 930 MWs, in 2026 and 2016, respectively. See “Oklahoma Environmental Compliance Plan” and “Regional Haze” sections below.

In December 2012, OPCo retired its 165 MW Conesville Plant, Unit 3.

A decline in natural gas prices, pending environmental rules and the proposed termination of the Interconnection Agreement had an adverse impact on the recoverability of the net book values of certain coal-fired units. In 2012, OPCo recorded a $287 million pretax impairment charge for the net book value of certain plants totaling 1,870 MWs in the table above and Beckjord and Conesville plants discussed above. See “Impairments” section of Note 5.

Plans for and the timing of conversion of some of the coal units to natural gas, installing emission control equipment on other units and closure of existing units will be impacted by changes in emission requirements and demand for power. To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows.

Modification of the NSR Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle all claims that the AEP subsidiaries violated the NSR provisions of the CAA when they undertook various equipment repair and replacement projects over a period of nearly 20 years. The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOx emissions from the AEP System and various mitigation projects.

The consent decree requires certain types of control equipment to be installed at Muskingum River Plant, Unit 5 and Big Sandy Plant, Unit 2 in 2015 and the two units of the Rockport Plant in 2017 and 2019. In February 2013, an agreement to modify the consent decree was reached and filed with the court. The terms of the modification include more options for the affected units (including alternative control technologies, re-fueling and/or retirement), more stringent SO2 emission caps for the AEP System and additional mitigation measures. The Federal EPA will seek public comments on the modification prior to its entry by the court. Under the terms of the modification, the units of Rockport Plant will be equipped with dry sorbent injection systems in 2015 and have options to retrofit additional SO2 controls, refuel, repower or retire in 2025 and 2028. Muskingum River Plant, Unit 5 will have options to cease burning coal and retire in 2015 or cease burning coal in 2015 and complete a refueling project no later than June 2017. I&M will secure an additional 200 MWs of renewable power resources by December 2014 and provide $8.5 million for additional mitigation projects.

355

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 NOx emissions from power plants. In 2008, the District of Columbia Circuit Court of Appeals issued a decision remanding CAIR to the Federal EPA. The Federal EPA issued the Cross-State Air Pollution Rule (CSAPR) (discussed in detail below) in August 2011 to replace CAIR. The CSAPR was challenged in the courts. The United States Court of Appeals for the District of Columbia Circuit issued an order in December 2011 staying the effective date of the rule pending judicial review. In August 2012, a panel of the United States 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 the CAIR until a replacement rule is finalized. Nearly all of the states in which the Registrant Subsidiaries’ power plants are located are covered by CAIR.

The Federal EPA issued final maximum achievable control technology (MACT) standards for coal and oil-fired power plants (discussed in detail below) in February 2012.

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas. BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. CAVR will be implemented through individual state implementation plans (SIPs) or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs). The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas and Oklahoma. The Federal EPA finalized a FIP for Oklahoma that contains more stringent control requirements for SO2 emissions from affected units in that state. The Arkansas SIP was disapproved and the state is developing a revised submittal. In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the CSAPR trading programs to use those programs in place of source-specific BART for SO2 and NOx 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 United States Court of Appeals for the District of Columbia Circuit and its fate is uncertain given recent developments in the CSAPR litigation.

In 2009, the Federal EPA issued a final mandatory reporting rule for CO2 and other greenhouse gases covering a broad range of facilities emitting in excess of 25,000 tons of CO2 emissions per year. The Federal EPA issued a final endangerment finding for greenhouse gas emissions from new motor vehicles in 2009. The Federal EPA determined that greenhouse gas emissions from stationary sources will be subject to regulation under the CAA beginning January 2011 and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, SIP calls and FIPs. The Federal EPA is reconsidering whether to include CO2 emissions in a number of stationary source standards, including standards that apply to new electric utility units and agreed to specific deadlines to issue proposed new source performance standards for utility boilers.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for SO2, NO2 and lead, and is currently reviewing the NAAQS for ozone and PM. States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for facilities as a result of those evaluations. Management cannot currently predict the nature, stringency or timing of those requirements.

Notable developments in significant CAA regulatory requirements affecting the Registrant Subsidiaries’ operations are discussed in the following sections.

356

Cross-State Air Pollution Rule (CSAPR)

In August 2011, the Federal EPA issued CSAPR. Certain revisions to the rule were finalized in March 2012. CSAPR relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states. Interstate trading of allowances is allowed on a restricted sub-regional basis. Arkansas and Louisiana are subject only to the seasonal NOx program in the rule. Texas is subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program. The annual SO2 allowance budgets in Indiana, Ohio and West Virginia were reduced significantly in the rule. A supplemental rule includes Oklahoma in the seasonal NOx program. The supplemental rule was finalized in December 2011 with an increased NOx emission budget for the 2012 compliance year. 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 United States Court of Appeals for the District of Columbia Circuit. Several of the petitioners filed motions to stay the implementation of the rule pending judicial review. In December 2011, the court granted the motions for stay. In August 2012, the panel issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the CAIR until a replacement rule is finalized. The majority determined that the CAA does not allow the Federal EPA to “over control” emissions in an upwind state and that the Federal EPA exceeded its statutory authority by failing to allow states an opportunity to develop their own implementation plans before issuing a FIP. The Federal EPA and other respondents filed petitions for rehearing but in January 2013, the United States Court of Appeals for the District of Columbia Circuit denied all petitions for rehearing. Separate appeals of the supplemental rule, the Error Corrections Rule and the further revisions have been filed, but are being held in abeyance.

The time frames and stringency of the required emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and its electric utility customers. Management cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants Regulation

In February 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis. In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. The effective date of the final rule was April 16, 2012 and compliance is required within three years. The AEP System is participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed. In November 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards. It is uncertain whether any of the information generated during the reconsideration process will affect the standards for existing sources.

The final rule contains a slightly less stringent PM limit than the original proposal and allows operators to exclude periods of startup and shutdown from the emissions averaging periods. The compliance time frame remains a serious concern. A one-year administrative extension may be available if the extension is necessary for the installation of controls or to avoid a serious reliability problem. In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades. Management is concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines. The AEP System is participating in petitions for review filed in the United States Court of Appeals for the District of Columbia Circuit by several organizations of which companies in the AEP System are members. Certain issues related to the standards for new coal-fired units have been severed from the main case and are being held in abeyance pending completion of the Federal EPA’s reconsideration proceeding. The case is proceeding on the remaining issues and briefing is scheduled to be completed by April 2013.

357

Regional Haze – Oklahoma Affecting PSO

In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze SIP submitted by the State of Oklahoma through the Department of Environmental Quality. The Federal EPA proposed to approve all of the NOx control measures in the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO. The Federal EPA proposed a FIP that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP. The Federal EPA finalized the FIP in December 2011 that mirrored the proposed rule but established a five-year compliance schedule. PSO filed a petition for review of the FIP in the Tenth Circuit Court of Appeals and engaged in settlement discussions with the Federal EPA, the State of Oklahoma and other parties. In November 2012, PSO notified the court that the parties had reached agreement on a settlement that would provide for submission of a revised Regional Haze SIP requiring the retirement of one coal-fired unit of PSO’s Northeastern Station no later than 2016, installation of emission controls on the second coal-fired Northeastern unit in 2016 and retirement of the second unit no later than 2026. Notice of the proposed settlement was published in the Federal Register in November 2012 and the comment period has closed. The Tenth Circuit Court of Appeals is holding the appeal in abeyance pending implementation of the settlement.

CO2 Regulation

In March 2012, the Federal EPA issued a proposal to regulate CO2 emissions from new fossil fuel-fired electricity generating units. The proposed rule establishes a new source performance standard of 1,000 pounds of CO2 per megawatt hour of electricity generated, a rate that most natural gas combined cycle units can meet, but that is substantially below the emission rate of a new pulverized coal generator or an integrated gas combined cycle unit that uses coal for fuel. As proposed, the rule does not apply to new gas-fired stationary combustion turbines used as peaking units, does not apply to existing, modified or reconstructed sources and does not apply to units whose CO2 emission rate increases as a result of the addition of pollution control equipment to control criteria pollutant emissions or HAPs. The rule is not anticipated to have a significant immediate impact on the AEP System since it does not apply to existing units or units that have already commenced construction. The comment period closed in June 2012. New source performance standards affect units that have not yet received permits, but complete the permitting process while the proposal is pending. The proposed standards were challenged in the United States Court of Appeals for the District of Columbia Circuit. That case was dismissed because the court determined that no final agency action had yet been taken. The Federal EPA is expected to finalize these standards in 2013.

In June 2012, the United States Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO2 emissions from new motor vehicles and its plan to phase-in regulation of CO2 emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. A petition for rehearing was filed which the court denied in December 2012. Petitioners may seek further review in the U.S. Supreme Court.

The Federal EPA also finalized a rule in June 2012 that retains the current thresholds for permitting stationary sources under the PSD and Title V operating permit programs at 100,000 tons per year for new sources and 75,000 tons per year for modified sources. The Federal EPA also confirmed that it will re-evaluate these thresholds during its five-year review in 2016. The AEP System’s generating units are large sources of CO2 emissions and management will continue to evaluate permitting obligations in light of these thresholds.

Coal Combustion Residual Rule

In June 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units. The rule contains two alternative proposals. One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management. Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule. In 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling

358

analyses to update its risk assessment. The Federal EPA has also announced its intention to complete a risk assessment of various beneficial uses of coal ash. Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule. The Federal EPA opposed the petition and is seeking additional time to coordinate the issuance of a final rule with the issuance of new effluent limitations under the Clean Water Act for utility facilities.

Currently, approximately 40% of the coal ash and other residual products from the AEP System’s generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses. Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes. In addition, surface impoundments and landfills to manage these materials are currently used at the generating facilities. The Registrant Subsidiaries will incur significant costs to upgrade or close and replace their existing facilities under the proposed solid waste management alternative. Regulation of these materials as hazardous wastes would significantly increase these costs. As the rule is not final, management is unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

Clean Water Act Regulations

In April 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress. The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement. Compliance with this standard is required within eight years of the effective date of the final rule. The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment. The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling. Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority. Management is evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at the AEP System’s facilities. In June 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments. The AEP System submitted comments in July 2012. Issuance of a final rule is not expected until June 2013. Management is preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

In addition, the Federal EPA issued an information collection request and is developing revised effluent limitation guidelines for electricity generating facilities. A proposed rule is expected in 2013 and a final rule in 2014. Management is unable to predict the impact of these changes but expect the costs to be significant.

Climate Change

National public policy makers and regulators in the 10 states the Registrant Subsidiaries serve have diverse views on climate change. Management is currently focused on responding to these emerging views with prudent actions, such as improving energy efficiency, investing in developing cost-effective and less carbon-intensive technologies and evaluating assets across a range of plausible scenarios and outcomes. Management is also an active participant in a variety of public policy discussions at state and federal levels to assure that proposed new requirements are feasible and the economies of the states served are not placed at a competitive disadvantage.

While comprehensive economy-wide regulation of CO2 emissions might be achieved through future legislation, Congress has yet to enact such legislation. The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA.

359

Several states have adopted programs that directly regulate CO2 emissions from power plants. The majority of the states where the Registrant Subsidiaries have generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements. The Registrant Subsidiaries are taking steps to comply with these requirements. In order to meet these requirements and as a key part of AEP’s corporate sustainability effort, management pledged to increase wind power. By the end of 2012, the AEP System secured, through power purchase agreements, 1,994 MW of wind and solar power.

The AEP System has taken measurable, voluntary actions to reduce and offset CO2 emissions. The AEP System participates in a number of voluntary programs to monitor, mitigate and reduce CO2 emissions, but many of these programs have been discontinued due to anticipated legislative or regulatory actions. Management estimates that 2012 emissions were approximately 122 million metric tons.

Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others. The Registrant Subsidiaries have been named in pending lawsuits, which management is defending. It is not possible to predict the outcome of these lawsuits or their impact on operations or financial condition. See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 4.

Future 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 the Registrant Subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets. Public perception may ultimately have a significant impact on future legislation and regulation that could adversely affect the Registrant Subsidiaries’ ability to recover their investments in coal-fired plants.

Climate change and its resultant impact on weather patterns could modify the Registrant Subsidiaries’ customers’ power usage. Customers’ energy needs currently vary with weather conditions and the economy. Increased or decreased energy usage could require the acquisition or construction of more generation and transmission assets or cause early retirement of such assets. The timing and duration of extreme weather conditions may require more system backup and contribute to increased system stresses, including service interruptions and increased storm restoration costs. Extreme weather conditions that create high energy demand could raise electricity prices, which could increase the cost of energy provided to customers and could provide opportunity for increased wholesale sales and higher margins.

To the extent climate change impacts a region's economic health, it could also affect revenues. The Registrant Subsidiaries’ financial performance is tied to the health of the regional economies served. The price of energy, as a factor in a region's cost of living as well as an important input into the cost of goods, has an impact on the economic health of communities served. The cost of additional regulatory requirements would normally be borne by consumers through higher prices for energy and purchased goods.

FINANCIAL CONDITION

BUDGETED CONSTRUCTION EXPENDITURES

The 2013 estimated construction expenditures by Registrant Subsidiary include generation, transmission and distribution related investments, as well as expenditures for compliance with environmental regulations as follows:

	2013 Budgeted Construction Expenditures
Company	Environmental		Generation		Transmission		Distribution		Other		Total
		(in millions)
APCo	$	59	$	87	$	67	$	145	$	12	$	370
I&M		42		293		49		89		11		484
OPCo		191		99		79		216		32		617
PSO		64		48		48		127		8		295
SWEPCo		143		82		86		79		8		398

360

For 2014 and 2015, management forecasts annual construction expenditures for the AEP System of $3.8 billion each year. The budgeted amounts exclude equity AFUDC and capitalized interest. The projected increases are generally the result of required environmental investment to comply with Federal EPA rules and additional transmission spending. 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. These construction expenditures will be funded 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.

SIGNIFICANT TAX LEGISLATION

The Small Business Jobs Act, enacted in September 2010, included a one-year extension of the 50% bonus depreciation provision. The Tax Relief, Unemployment Insurance Reauthorization and the Job Creation Act of 2010 extended the life of research and development, employment and several energy tax credits originally scheduled to expire at the end of 2010. In addition, this act extended the time for claiming bonus depreciation and increased the deduction to 100% starting in September 2010 through 2011 and decreased the deduction to 50% for 2012. 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 50% bonus depreciation to 2013.

The enacted provisions had no material impact on the Registrant Subsidiaries’ net income, financial condition or cash flows in 2012, but are expected to result in material future cash flow benefits.

CYBER SECURITY

Cyber security presents a heightened risk for electric utility systems because a cyber-attack could affect critical energy infrastructure. Breaches to the cyber security of the grid or 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 the functions in cyber security as well as redefine how the government interfaces with critical infrastructure, such as the electric grid. The AEP System already operates under regulatory cyber security standards to protect critical infrastructure. The cyber security framework that will be developed through this executive order will be reviewed by the FERC. Management expects the AEP System to participate in the process and will share best practices already in place. Critical cyber assets, such as data centers and transmission operations centers and business network 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, cyber security tools and processes are continually assessed to determine where defenses might need strengthened.

In recent years, management has taken several steps to enhance capabilities for identifying risks or threats. AEP became the first utility in the country to build a Cyber Security Operations Center. Funding was included as part of a larger American Recovery and Reinvestment Act Department of Energy Smart Grid Demonstration Project grant. This facility is designed as a pilot cyber threat and information-sharing center specifically for the electric sector.

AEP has partnered with a nonaffiliated entity to leverage their experience and technical capabilities, which were 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 and with the Department of Homeland Security. AEP also worked with a nonaffiliated entity to conduct several seminars in 2011 about recognizing and investigating cyber vulnerabilities. Through these types of efforts, AEP is working to protect itself while helping the industry advance its cyber security capabilities.

In March 2012, AEP signed a cooperative research and development agreement with the Department of Homeland Security’s Office of Cyber Security and Communications, further enhancing the ability to directly exchange information about cyber threats. In addition, AEP continues to partner with a number of federal and industry groups to advance the national capabilities of cyber security. Among them is the U.S. Department of Energy, where AEP is working on several pilot projects covering advanced cyber security and assessment tools.

361

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.

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 the Registrant Subsidiaries’ 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 financial statements of the Registrant Subsidiaries with cost-based rate-regulated operations (APCo, I&M, PSO, SWEPCo and a portion of OPCo) 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 Registrant Subsidiaries 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 Registrant Subsidiaries match the timing of expense and income recognition 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, the Registrant Subsidiaries record them as regulatory assets on the balance sheet. Management reviews the probability of recovery at each balance sheet date and whenever new events occur. Similarly, the Registrant Subsidiaries record regulatory liabilities 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 3 for further detail related to regulatory assets and liabilities.

362

Revenue Recognition – Unbilled Revenues

Nature of Estimates Required

The Registrant Subsidiaries record 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. In accordance with the applicable state commission regulatory treatment in Arkansas, Louisiana, Oklahoma and Texas, PSO and SWEPCo do not record the fuel portion of unbilled revenue.

The changes in unbilled electricity utility revenues for the years ended December 31, 2012, 2011 and 2010 were as follows:

	Years Ended December 31,
Company	2012		2011		2010
	(in thousands)
APCo	$	8,047	$	(41,979)	$	30,337
I&M		(1,233)		(2,628)		2,194
OPCo		(14,721)		(20,449)		9,864
PSO		5,213		641		(4,159)
SWEPCo		2,302		643		(1,175)

Assumptions and Approach Used

For each Registrant Subsidiary, the monthly estimate for unbilled revenues is computed as net generation less the current month’s billed KWh plus the prior month’s unbilled KWh. However, due to meter reading issues, meter drift and other anomalies, a separate monthly calculation limits the unbilled estimate within a range of values. This limiter calculation is derived from an allocation of billed KWh to the current month and previous month, on a cycle-by-cycle basis, and dividing the current month aggregated result by the billed KWh. The limits are statistically set at one standard deviation from this percentage to determine the upper and lower limits of the range. The unbilled estimate is compared to the limiter calculation and adjusted for variances exceeding the upper and lower limits.

Effect if Different Assumptions Used

Significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. A 1% change in the limiter calculation when it is outside the range would increase or decrease unbilled revenues by 1% of the accrued unbilled revenues.

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 Registrant Subsidiaries 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

363

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.

The Registrant Subsidiaries 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 8 and 9. 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 Registrant Subsidiaries 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 Registrant Subsidiaries 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 Registrant Subsidiary records 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, management estimates 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

364

asset or liability at the measurement date. Such characteristics include, for example, the condition and location of the asset or restrictions of the use of the asset. Management performs 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 as 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. The Registrant Subsidiaries participate in the Plans.

The following table shows the net periodic cost by Registrant Subsidiary for the Plans:

							Other Postretirement
	Pension Plans						Benefit Plans
	Years Ended December 31,
Net Periodic Cost	2012		2011		2010		2012		2011		2010
		(in thousands)
APCo	$	16,646	$	15,146	$	15,818	$	15,540	$	13,301	$	19,048
I&M		16,563		15,205		20,138		11,358		9,360		13,857
OPCo		18,978		19,418		19,701		20,282		16,651		24,112
PSO		7,495		7,388		5,439		4,821		3,881		7,443
SWEPCo		8,307		7,488		7,096		5,928		4,841		7,574

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 2013, 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 6.5% for the Qualified Plan and 7% for the Postretirement Plans.

365

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

							Other Postretirement
	Pension Plans						Benefit Plans
				Assumed/						Assumed/
	2013			Expected			2013			Expected
	Target			Long-Term			Target			Long-Term
	Asset			Rate of			Asset			Rate of
	Allocation			Return			Allocation			Return
Equity		40	%		9.00	%		66	%		8.60	%
Fixed Income		50	%		4.00	%		33	%		3.50	%
Other Investments		10	%		8.80	%		-	%		-	%
Cash and Cash Equivalents		-	%		-	%		1	%		1.50	%
Total		100	%					100	%

Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation. Management believes that 6.5% and 7% are reasonable estimates of the long-term rate of return on the Plans’ assets. The Pension Plans’ assets had an actual gain of 13.8% and 8.1% for the years ended December 31, 2012 and 2011, respectively. The Postretirement Plans’ assets had an actual gain of 15.4% and 0.4% for the years ended December 31, 2012 and 2011, respectively. 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, 2012, AEP had cumulative gains of approximately $302 million that remain to be recognized in the calculation of the market-related value of assets. These unrecognized net actuarial gains may result in decreases in the future pension costs depending on several factors, including whether such gains at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance. See the table below for the amount of cumulative gains by Registrant Subsidiary.

Cumulative Gains –
Deferred Asset Gain	December 31, 2012
	(in thousands)
APCo		$	39,913
I&M			35,447
OPCo			65,183
PSO			17,005
SWEPCo			17,960

366

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, 2012 under this method was 3.95% for the Qualified Plan, 3.8% for the Nonqualified Plans and 3.95% for the Postretirement Plans. Due to the effect of the unrecognized actuarial gains and based on an expected rate of return on the Pension Plans’ assets of 6.5%, a discount rate of 3.95% and 3.8% and various other assumptions, management estimates that the pension costs by Registrant Subsidiary for all pension plans will approximate the amounts in the following table. Based on an expected rate of return on the OPEB plans’ assets of 7%, a discount rate of 3.95% and various other assumptions, management estimates Postretirement Plan costs (credits) by Registrant Subsidiary will approximate the amounts in the following table.

							Other Postretirement
	Pension Plans						Benefit Plans
Estimated Postretirement	Years Ended December 31,
Plan Costs (Credits)	2013		2014		2015		2013		2014		2015
		(in thousands)
APCo	$	22,556	$	16,753	$	12,791	$	106	$	(886)	$	(2,195)
I&M		21,881		16,332		12,428		(3,101)		(3,598)		(4,370)
OPCo		27,866		19,771		14,214		1,994		770		(713)
PSO		10,656		8,423		7,037		(1,653)		(1,851)		(2,202)
SWEPCo		11,394		8,758		7,002		(2,134)		(2,356)		(2,739)

Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to each Registrant Subsidiary’s 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.

In November 2012, management announced changes to the retiree medical coverage. Effective for retirements after December 2012, management capped contributions to retiree medical costs reducing the Registrant Subsidiaries’ future exposure to medical cost inflation. Effective for employees hired after December 2013, retiree medical coverage will not be provided. This change will reduce costs of the plan beginning in 2013 as shown by the estimated credits for Postretirement Plans in the previous table.

The value of AEP’s Pension Plans’ assets increased to $4.7 billion as of December 31, 2012 from $4.3 billion as of December 31, 2011 primarily due to investment returns and a $200 million contribution from AEP System companies. During 2012, the Qualified Plan paid $367 million and the Nonqualified Plans paid $16 million in benefits to plan participants. The value of AEP’s Postretirement Plans’ assets increased to $1.6 billion as of December 31, 2012 from $1.4 billion as of December 31, 2011 primarily due to investment returns and contributions from AEP System companies and the participants. The Postretirement Plans paid $151 million in benefits to plan participants during 2012. See Note 6 for complete details by Registrant Subsidiary.

Nature of Estimates Required

The Registrant Subsidiaries participate in AEP sponsored 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.

367

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:

APCo					Other Postretirement
	Pension Plans				Benefit Plans
	+0.5%		-0.5%		+0.5%		-0.5%
	(in thousands)
Effect on December 31, 2012 Benefit Obligations
Discount Rate	$	(38,174)	$	42,021	$	(19,078)	$	21,054
Compensation Increase Rate		1,060		(951)		NA		NA
Cash Balance Crediting Rate		3,318		(2,813)		NA		NA
Health Care Cost Trend Rate		NA		NA		9,317		(10,984)

Effect on 2012 Periodic Cost
Discount Rate		(2,274)		2,464		(2,014)		2,238
Compensation Increase Rate		589		(539)		NA		NA
Cash Balance Crediting Rate		1,524		(1,346)		NA		NA
Health Care Cost Trend Rate		NA		NA		3,648		(3,259)
Expected Return on Plan Assets		(3,037)		3,037		(1,145)		1,151

I&M					Other Postretirement
	Pension Plans				Benefit Plans
	+0.5%		-0.5%		+0.5%		-0.5%
	(in thousands)
Effect on December 31, 2012 Benefit Obligations
Discount Rate	$	(34,813)	$	38,485	$	(11,845)	$	13,093
Compensation Increase Rate		1,557		(1,420)		NA		NA
Cash Balance Crediting Rate		4,281		(3,694)		NA		NA
Health Care Cost Trend Rate		NA		NA		3,951		(5,297)

Effect on 2012 Periodic Cost
Discount Rate		(1,964)		2,128		(1,266)		1,402
Compensation Increase Rate		508		(466)		NA		NA
Cash Balance Crediting Rate		1,317		(1,162)		NA		NA
Health Care Cost Trend Rate		NA		NA		2,302		(2,064)
Expected Return on Plan Assets		(2,623)		2,623		(830)		834

368

OPCo					Other Postretirement
	Pension Plans				Benefit Plans
	+0.5%		-0.5%		+0.5%		-0.5%
	(in thousands)
Effect on December 31, 2012 Benefit Obligations
Discount Rate	$	(54,592)	$	59,980	$	(27,795)	$	31,043
Compensation Increase Rate		1,869		(1,705)		NA		NA
Cash Balance Crediting Rate		4,727		(4,301)		NA		NA
Health Care Cost Trend Rate		NA		NA		15,452		(17,221)

Effect on 2012 Periodic Cost
Discount Rate		(3,406)		3,690		(2,692)		2,990
Compensation Increase Rate		882		(807)		NA		NA
Cash Balance Crediting Rate		2,282		(2,015)		NA		NA
Health Care Cost Trend Rate		NA		NA		4,880		(4,361)
Expected Return on Plan Assets		(4,542)		4,542		(1,567)		1,574

PSO					Other Postretirement
	Pension Plans				Benefit Plans
	+0.5%		-0.5%		+0.5%		-0.5%
	(in thousands)
Effect on December 31, 2012 Benefit Obligations
Discount Rate	$	(13,015)	$	14,209	$	(5,439)	$	6,010
Compensation Increase Rate		941		(864)		NA		NA
Cash Balance Crediting Rate		2,842		(3,629)		NA		NA
Health Care Cost Trend Rate		NA		NA		1,705		(2,369)

Effect on 2012 Periodic Cost
Discount Rate		(913)		990		(578)		639
Compensation Increase Rate		237		(217)		NA		NA
Cash Balance Crediting Rate		612		(540)		NA		NA
Health Care Cost Trend Rate		NA		NA		1,051		(943)
Expected Return on Plan Assets		(1,218)		1,218		(387)		389

SWEPCo					Other Postretirement
	Pension Plans				Benefit Plans
	+0.5%		-0.5%		+0.5%		-0.5%
	(in thousands)
Effect on December 31, 2012 Benefit Obligations
Discount Rate	$	(13,402)	$	14,642	$	(6,135)	$	6,787
Compensation Increase Rate		1,068		(978)		NA		NA
Cash Balance Crediting Rate		4,688		(4,426)		NA		NA
Health Care Cost Trend Rate		NA		NA		1,580		(2,327)

Effect on 2012 Periodic Cost
Discount Rate		(929)		1,006		(637)		705
Compensation Increase Rate		241		(220)		NA		NA
Cash Balance Crediting Rate		622		(549)		NA		NA
Health Care Cost Trend Rate		NA		NA		1,160		(1,040)
Expected Return on Plan Assets		(1,238)		1,238		(427)		429

NA Not applicable.

369

ACCOUNTING PRONOUNCEMENTS

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, management cannot determine the impact on the reporting of the Registrant Subsidiaries’ operations and financial position that may result from any such future changes. The FASB is currently working on several projects including revenue recognition, financial instruments, leases, insurance, hedge accounting and consolidation policy. The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.

370

Term		Meaning

AEGCo		AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent		American Electric Power Company, Inc., an electric utility holding company.
AEP Consolidated		AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit		AEP Credit, Inc., a consolidated variable interest entity of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East Companies		APCo, I&M, KPCo and OPCo.
AEP Energy		AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States. BlueStar began doing business as AEP Energy, Inc. in June 2012.
AEPGenCo		AEP Generation Resources Inc., a nonregulated AEP subsidiary in the Generation and Marketing segment.
AEP System		American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP West Companies		PSO, SWEPCo, TCC and TNC.
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.
AEPSC		American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC		Allowance for Funds Used During Construction.
AOCI		Accumulated Other Comprehensive Income.
APCo		Appalachian Power Company, an AEP electric utility subsidiary.
APSC		Arkansas Public Service Commission.
BlueStar		BlueStar Energy Holdings, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States. BlueStar began doing business as AEP Energy, Inc. in June 2012.
BOA		Bank of America Corporation.
CAA		Clean Air Act.
CLECO		Central Louisiana Electric Company, a nonaffiliated utility company.
CO2		Carbon dioxide and other greenhouse gases.
Cook Plant		Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CRES		Competitive Retail Electric Service.
CSPCo		Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
CSW		Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW 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.
CWIP		Construction Work in Progress.
DCC Fuel		DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC and DCC Fuel V LLC, consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC		Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.

E&R		Environmental compliance and transmission and distribution system reliability.
EIS		Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entity of AEP.
ENEC		Expanded Net Energy Charge.
ERCOT		Electric Reliability Council of Texas regional transmission organization.
ESP		Electric Security Plans, filed with the PUCO, pursuant to the Ohio Amendments.
ETA		Electric Transmission America, LLC an equity interest joint venture with MidAmerican Energy Holdings Company America Transco, LLC formed to own and operate electric transmission facilities in North America outside of ERCOT.
ETT		Electric Transmission Texas, LLC, an equity interest joint venture between AEP and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FAC		Fuel Adjustment Clause.
FASB		Financial Accounting Standards Board.
Federal EPA		United States Environmental Protection Agency.
FERC		Federal Energy Regulatory Commission.
FGD		Flue Gas Desulfurization or scrubbers.
FTR		Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP		Accounting Principles Generally Accepted in the United States of America.
IEU		Industrial Energy Users-Ohio.
IGCC		Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement		An agreement by and among APCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
IRS		Internal Revenue Service.
IURC		Indiana Utility Regulatory Commission.
I&M		Indiana Michigan Power Company, an AEP electric utility subsidiary.
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.
NEIL		Nuclear Electric Insurance Limited insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks.
NOx		Nitrogen oxide.
Nonutility Money Pool		Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NSR		New Source Review.
OATT		Open Access Transmission Tariff.

OCC		Corporation Commission of the State of Oklahoma.
OPCo		Ohio Power Company, an AEP electric utility subsidiary.
OPEB		Other Postretirement Benefit Plans.
OTC		Over the counter.
OVEC		Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PJM		Pennsylvania – New Jersey – Maryland regional transmission organization.
PM		Particulate Matter.
POLR		Provider of Last Resort revenues.
PSO		Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO		Public Utilities Commission of Ohio.
PUCT		Public Utility Commission of Texas.
Registrant Subsidiaries		AEP subsidiaries which are SEC registrants; APCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts		Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant		A generating plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
RTO		Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine		Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEET		Significantly Excessive Earnings Test.
SEC		U.S. Securities and Exchange Commission.
SIA		System Integration Agreement, effective June 15, 2000, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF		Spent Nuclear Fuel.
SO2		Sulfur dioxide.
SPP		Southwest Power Pool regional transmission organization.
SSO		Standard service offer.
Stall Unit		J. Lamar Stall Unit at Arsenal Hill Plant, a 543 MW natural gas unit owned by SWEPCo.
SWEPCo		Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC		AEP Texas Central Company, an AEP electric utility subsidiary.
Texas Restructuring Legislation		Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC		AEP Texas North Company, an AEP electric utility subsidiary.
Transition Funding		AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas restructuring law.
True-up Proceeding		A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.
Turk Plant		John W. Turk, Jr. Plant, a 600 MW pulverized coal ultra-supercritical generating unit in Arkansas that is 73% owned by SWEPCo.
Utility Money Pool		Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE		Variable Interest Entity.
Virginia SCC		Virginia State Corporation Commission.
WPCo		Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC		Public Service Commission of West Virginia.

					Quarter-End
Quarter Ended	High		Low		Closing Price		Dividend
December 31, 2012	$	45.41	$	40.56	$	42.68	$	0.47
September 30, 2012		44.84		39.62		43.94		0.47
June 30, 2012		40.46		36.97		39.90		0.47
March 31, 2012		41.98		37.46		38.58		0.47

December 31, 2011	$	41.71	$	35.85	$	41.31	$	0.47
September 30, 2011		38.98		33.09		38.02		0.46
June 30, 2011		38.99		34.37		37.68		0.46
March 31, 2011		36.92		33.47		35.14		0.46

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA

			2012		2011		2010			2009		2008
			(dollars in millions, except per share amounts)
STATEMENTS OF INCOME DATA
Total Revenues			$	14,945	$	15,116	$	14,427		$	13,489	$	14,440

Operating Income			$	2,656	$	2,782	$	2,663		$	2,771	$	2,787

Income Before Discontinued Operations and Extraordinary Items			$	1,262	$	1,576	$	1,218		$	1,370	$	1,376
Discontinued Operations, Net of Tax				-		-		-			-		12
Income Before Extraordinary Items				1,262		1,576		1,218			1,370		1,388
Extraordinary Items, Net of Tax				-		373		-			(5)		-
Net Income				1,262		1,949		1,218			1,365		1,388

Net Income Attributable to Noncontrolling Interests				3		3		4			5		5

NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS				1,259		1,946		1,214			1,360		1,383

Preferred Stock Dividend Requirements of Subsidiaries Including
	Capital Stock Expense			-		5		3			3		3

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS			$	1,259	$	1,941	$	1,211		$	1,357	$	1,380

BALANCE SHEETS DATA
Total Property, Plant and Equipment			$	57,454	$	55,670	$	53,740		$	51,684	$	49,710
Accumulated Depreciation and Amortization				18,691		18,699		18,066			17,340		16,723
Total Property, Plant and Equipment – Net			$	38,763	$	36,971	$	35,674		$	34,344	$	32,987

Total Assets			$	54,367	$	52,223	$	50,455		$	48,348	$	45,155

Total AEP Common Shareholders’ Equity			$	15,237	$	14,664	$	13,622		$	13,140	$	10,693

Noncontrolling Interests			$	-	$	1	$	-		$	-	$	17

Cumulative Preferred Stock Not Subject to Mandatory Redemption			$	-	$	-	$	60		$	61	$	61

Long-term Debt (a)			$	17,757	$	16,516	$	16,811		$	17,498	$	15,983

Obligations Under Capital Leases (a)			$	449	$	458	$	474	(b)	$	317	$	325

AEP COMMON STOCK DATA
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders:

Income Before Discontinued Operations and Extraordinary Items			$	2.60	$	3.25	$	2.53		$	2.97	$	3.40
Discontinued Operations, Net of Tax				-		-		-			-		0.03
Income Before Extraordinary Items				2.60		3.25		2.53			2.97		3.43
Extraordinary Items, Net of Tax				-		0.77		-			(0.01)		-

Total Basic Earnings per Share Attributable to AEP Common Shareholders			$	2.60	$	4.02	$	2.53		$	2.96	$	3.43

Weighted Average Number of Basic Shares Outstanding (in millions)				485		482		479			459		402

Market Price Range:
		High	$	45.41	$	41.71	$	37.94		$	36.51	$	49.11
		Low	$	36.97	$	33.09	$	28.17		$	24.00	$	25.54

Year-end Market Price			$	42.68	$	41.31	$	35.98		$	34.79	$	33.28

Cash Dividends Declared per AEP Common Share			$	1.88	$	1.85	$	1.71		$	1.64	$	1.64

Dividend Payout Ratio				72.31%		46.02%		67.59%			55.41%		47.8%

Book Value per AEP Common Share			$	31.35	$	30.36	$	28.32		$	27.49	$	26.35

(a)		Includes portion due within one year.
(b)		Obligations Under Capital Leases increased primarily due to capital leases under new master lease agreements for property that was previously leased
		under operating leases.

		Page Number
Glossary of Terms		i

Forward-Looking Information		iv

AEP Common Stock and Dividend Information		vi

American Electric Power Company, Inc. and Subsidiary Companies:
	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	45-46
	Management's Report on Internal Control Over Financial Reporting	47
	Consolidated Financial Statements	48
	Index of Notes to Consolidated Financial Statements	54

Appalachian Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	142
	Report of Independent Registered Public Accounting Firm	147
	Management's Report on Internal Control Over Financial Reporting	148
	Consolidated Financial Statements	149
	Index of Notes to Financial Statements of Registrant Subsidiaries	155

Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	157
	Report of Independent Registered Public Accounting Firm	163
	Management's Report on Internal Control Over Financial Reporting	164
	Consolidated Financial Statements	165
	Index of Notes to Financial Statements of Registrant Subsidiaries	171

Ohio Power Company and Subsidiary:
	Management’s Narrative Discussion and Analysis of Results of Operations	173
	Report of Independent Registered Public Accounting Firm	180
	Management's Report on Internal Control Over Financial Reporting	181
	Consolidated Financial Statements	182
	Index of Notes to Financial Statements of Registrant Subsidiaries	188

Public Service Company of Oklahoma:
	Management’s Narrative Discussion and Analysis of Results of Operations	190
	Report of Independent Registered Public Accounting Firm	193
	Management's Report on Internal Control Over Financial Reporting	194
	Financial Statements	195
	Index of Notes to Financial Statements of Registrant Subsidiaries	201

Southwestern Electric Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations	203
	Report of Independent Registered Public Accounting Firm	208
	Management's Report on Internal Control Over Financial Reporting	209
	Consolidated Financial Statements	210
	Index of Notes to Financial Statements of Registrant Subsidiaries	216

Index of Notes to Financial Statements of Registrant Subsidiaries		217

Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries		353

·	The economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory.
·	Inflationary or deflationary interest rate trends.
·	Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·	The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
·	Electric load, customer growth and the impact of retail competition, particularly in Ohio.
·	Weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
·	Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·	Availability of necessary generating capacity and the performance of our generating plants.
·	Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·	Our ability to build or acquire generating capacity and transmission lines and facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.
·	New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants and related assets.
·	Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
·	A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
·	Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
·	Resolution of litigation.
·	Our ability to constrain operation and maintenance costs.
·	Our ability to develop and execute a strategy based on a view regarding prices of electricity, coal, natural gas and other energy-related commodities.
·	Prices and demand for power that we generate and sell at wholesale.
·	Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·	Our ability to recover through rates or market prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.
·	Volatility and changes in markets for electricity, coal, natural gas and other energy-related commodities.

·	Changes in utility regulation, including the implementation of ESPs and the transition to market and expected legal separation for generation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.
·	Our ability to successfully manage negotiations with stakeholders and obtain regulatory approval to terminate the Interconnection Agreement.
·	Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·	Actions of rating agencies, including changes in the ratings of our debt.
·	The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact on future funding requirements.
·	Accounting pronouncements periodically issued by accounting standard-setting bodies.
·	Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

·	Almost 37,600 megawatts of generating capacity, one of the largest complements of generation in the United States.
·	Approximately 40,000 miles of transmission lines, including 2,116 miles of 765kV lines, the backbone of the electric interconnection grid in the Eastern United States.
·	Approximately 221,000 miles of distribution lines that deliver electricity to 5.3 million customers.
·	Substantial commodity transportation assets (more than 7,600 railcars, approximately 3,100 barges, 60 towboats, 25 harbor boats and a coal handling terminal with approximately 18 million tons of annual capacity). Our commercial barging operations annually transport approximately 42 million tons of coal and dry bulk commodities. Approximately 38% of the barging is for transportation of agricultural products, 30% for coal, 18% for steel and 14% for other commodities.

	·	Generation of electricity for sale to U.S. retail and wholesale customers.
	·	Transmission and distribution of electricity through assets owned and operated by our ten utility operating companies.

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

(a)	While not considered a reportable segment, All Other includes:
	·	Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
	·	Tax and interest expense adjustments related to our UK operations, which were sold in 2004 and 2002.
	·	Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005. These contracts were financial derivatives which settled and expired in the fourth quarter of 2011.
	·	Revenue sharing related to the Plaquemine Cogeneration Facility, which ended in the fourth quarter of 2011.

·	A decrease in carrying costs income due to the recognition in 2011 of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005 and a related favorable 2011 resolution of contested tax items related to the TCC stranded cost settlement.
·	The 2012 impairment for certain Ohio generation plants.
·	The loss of retail customers in Ohio to various CRES providers.
·	A decrease in weather-related usage.
·	The elimination of POLR charges, effective June 2011, partially offset by the 2011 provision for refund of POLR charges. The refund provision was recorded as a result of the October 2011 PUCO remand order.
·	Expenses associated with the early retirement of Parent debt in 2012.
·	Expenses related to the 2012 sustainable cost reductions.
·	The 2012 adjustment of a UK windfall tax provision as a result of a recent related Supreme Court case.

·	Successful rate proceedings in our various jurisdictions.
·	Lower spending in 2012 as a result of our cost containment efforts.
·	A 2011 recording and subsequent 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of OPCo's modified stipulation.
·	The 2011 plant impairments for Sporn Plant Unit 5 and for the FGD project at Muskingum River Plant Unit 5.
·	The 2011 write-off related to SWEPCo's expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap as a result of the November 2011 Texas Court of Appeals decision.
·	A loss incurred in 2011 related to a settlement of litigation with BOA and Enron.

·	An increase in carrying costs income due to the recognition in 2011 of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005 and a related favorable 2011 resolution of contested tax items related to the TCC stranded cost settlement.
·	A decrease in expenses as a result of the 2010 cost reduction initiatives.
·	Successful rate proceedings in our various jurisdictions.

·	The loss of retail customers in Ohio to various CRES providers.
·	Various Ohio adjustments in 2011, including:
	·	The plant impairments for Sporn Plant Unit 5 and for the FGD project at Muskingum River Plant Unit 5.
	·	A net decrease due to unfavorable Ohio regulatory orders in 2011.
	·	The recording of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund.
·	The elimination of POLR charges, effective June 2011, partially offset by the 2011 provision for refund of POLR charges. The refund provision was recorded as a result of the October 2011 PUCO remand order.
·	A 2011 write-off related to SWEPCo's expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap as a result of the November 2011 Texas Court of Appeals decision.

Summary of KWh Energy Sales for Utility Operations

		Years Ended December 31,
		2012		2011		2010

		(in millions of KWhs)
Retail:
	Residential		58,780		61,655		61,944
	Commercial		50,464		50,767		50,748
	Industrial		59,154		59,667		57,333
	Miscellaneous		3,072		3,100		3,083
Total Retail (a)			171,470		175,189		173,108

Wholesale			41,892		40,519		32,581

Total KWhs			213,362		215,708		205,689

(a) Represents energy delivered to distribution customers.

Year Ended December 31, 2011	$	1,549

Changes in Gross Margin:
Retail Margins		23
Off-system Sales		(19)
Transmission Revenues		83
Other Revenues		(17)
Total Change in Gross Margin		70

Changes in Expenses and Other:
Other Operation and Maintenance		187
Asset Impairments and Other Related Charges		(161)
Depreciation and Amortization		(121)
Taxes Other Than Income Taxes		(16)
Interest and Investment Income		(22)
Carrying Costs Income		(340)
Allowance for Equity Funds Used During Construction		(13)
Interest Expense		4
Total Change in Expenses and Other		(482)

Income Tax Expense		162

Year Ended December 31, 2012	$	1,299

·	Retail Margins increased $23 million primarily due to the following:
	·	Successful rate proceedings in our service territories, which include:
		·	A $177 million rate increase for OPCo.
		·	An $87 million rate increase for APCo.
		·	A $17 million rate increase for I&M.
		·	A $13 million rate increase for PSO.
		·	An $11 million rate increase for WPCo.
				For the rate increases described above, $156 million relates to riders/trackers which have corresponding increases in other expense items below.
	·	A $71 million decrease in other variable electric generation expenses.
	·	A $35 million increase due to OPCo's 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
	·	A $33 million decrease in recoverable PJM expenses in Ohio.
	·	A $24 million write-off in 2011 related to APCo's disallowance of certain Virginia environmental costs incurred in 2009 and 2010 as a result of the November 2011 Virginia SCC order.
	·	A $9 million deferral of APCo's additional wind purchase costs as a result of the June 2012 Virginia SCC fuel factor order.
	·	A $9 million increase due to adjustments for previously disallowed environmental costs by the November 2011 Virginia SCC order subsequently determined in 2012 to be appropriate for recovery by the Supreme Court of Virginia.

	These increases were partially offset by:
	·	A $289 million decrease attributable to Ohio customers switching to alternative CRES providers. This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
	·	A $95 million decrease in weather-related usage in our eastern and western regions primarily due to decreases of 15% and 36%, respectively, in heating degree days and a 6% decrease in cooling degree days in our western region.
	·	An $85 million net decrease in regulated revenue due to the elimination of POLR charges, effective June 2011, partially offset by the 2011 provision for refund of POLR charges. The refund provision was recorded as a result of the October 2011 PUCO remand order.
·	Margins from Off-system Sales decreased $19 million primarily due to lower market prices, lower PJM capacity payments and reduced trading and marketing margins, partially offset by higher Ohio CRES capacity revenues.
·	Transmission Revenues increased $83 million primarily due to net rate increases in ERCOT and increased transmission revenues from Ohio customers who have switched to alternative CRES providers. The increase in transmission revenues related to CRES providers offsets the lost transmission revenues included in Retail Margins above.
·	Other Revenues decreased $17 million primarily due to a decrease in gains on miscellaneous sales, partially offset by an increase in revenues related to TCC's issuance of securitization bonds in March 2012. This increase in revenues from securitization bonds is partially offset by an increase in Depreciation and Amortization expense.

·	Other Operation and Maintenance expenses decreased $187 million primarily due to the following:
	·		A $141 million decrease in plant outage and other plant operating and maintenance expenses.
	·		A $72 million decrease in nonutility operations and distribution expenses due to prior year cost reduction measures.
	·		A $70 million decrease related to the 2011 recording and subsequent 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of the Ohio modified stipulation.
	·		A $41 million decrease due to the 2011 write-off of a portion of the West Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC.
	·		A $16 million decrease in administrative and general expenses.
	·		A $13 million decrease due to APCo's deferral of transmission costs for the Virginia Transmission Rate Adjustment Clause as allowed by the Virginia SCC recovered dollar-for-dollar within Gross Margin.
	These decreases were partially offset by:
	·		A $44 million increase due to expenses related to the 2012 sustainable cost reductions.
	·		A $42 million increase in energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
	·		A $33 million increase due to the 2011 deferral of 2009 storm costs and the 2010 cost reduction initiatives as allowed by the WVPSC.
	·		A $27 million increase due to the favorable 2011 asset retirement obligation adjustment for APCo related to the early closure and previous write-off of the Mountaineer Carbon Capture and Storage Product Validation Facility.
	·		A $15 million increase in storm-related expenses due to major storms in our eastern region.
	·		An $11 million gain from the sale of land in January 2011.
·	Asset Impairments and Other Related Charges increased $161 million primarily due to the following:
	·	A 2012 impairment of $287 million for certain Ohio generation plants, which includes $13 million of related materials and supplies inventory.
	·	A 2012 write-off of an additional $13 million related to SWEPCo's expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap.

	This increase was partially offset by:
	·	A 2011 write-off of $49 million related to SWEPCo's expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap as a result of the November 2011 Texas Court of Appeals decision.
	·	A 2011 plant impairment of $48 million for Sporn Plant Unit 5.
	·	A 2011 plant impairment of $42 million for FGD project at Muskingum River Plant Unit 5.
·	Depreciation and Amortization expenses increased $121 million primarily due to the following:
	·		A $58 million increase due to shortened depreciable lives for certain OPCo generating plants effective December 2011. The book value of these plants was fully impaired in November 2012.
	·		A $51 million increase due to TCC's issuance of securitization bonds in March 2012. The increase in TCC’s securitization related amortization is offset within Gross Margin.
	·		A $48 million combined increase in depreciation for APCo and I&M primarily due to increases in depreciation rates effective February 2012 (Virginia) and April 2012 (Michigan), respectively. The majority of this increase in depreciation is offset within Gross Margin.
	·		An $18 million increase in amortization primarily as a result of the Virginia Environmental Rate Adjustment Clause and the Virginia E&R surcharge, both effective February 2012. This increase in amortization is offset within Gross Margin.
	·		An $11 million increase in amortization of OPCo's Deferred Asset Recovery Rider assets as approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012. This increase in amortization is offset within Gross Margin.
	·		Overall higher depreciable property balances.
	These increases were partially offset by:
	·		A $39 million decrease due to an amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
	·		A $28 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO's July 2012 approval of OPCo's capacity rate.
	·		A $23 million decrease due to OPCo's amortization of carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances. The equity amortization was offset by amounts recognized in Carrying Costs Income.
	·		A $13 million decrease in OPCo's depreciation due to the 2011 plant impairment of Sporn Plant Unit 5.
·	Taxes Other Than Income Taxes increased $16 million primarily due to increased property taxes as a result of increased capital investments.
·	Interest and Investment Income decreased $22 million primarily due to interest income recorded in the third quarter of 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
·	Carrying Costs Income decreased $340 million primarily due to the recognition in 2011 of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005 and a related favorable 2011 resolution of contested tax items related to the TCC stranded cost settlement.
·	Allowance for Equity Funds Used During Construction decreased $13 million primarily due to the completion of APCo's Dresden Plant in January 2012 and I&M's nuclear fuel preparation for usage, partially offset by increases related to SWEPCo's construction of the Turk Plant.
·	Interest Expense decreased $4 million primarily due to lower long-term interest rates.
·	Income Tax Expense decreased $162 million primarily due to a decrease in pretax book income, partially offset by the recording of federal and state income tax adjustments.


Reconciliation of Year Ended December 31, 2010 to Year Ended December 31, 2011
Income from Utility Operations Before Extraordinary Item
(in millions)

Year Ended December 31, 2010	$	1,192

Changes in Gross Margin:
Retail Margins		(139)
Off-system Sales		44
Transmission Revenues		48
Other Revenues		(4)
Total Change in Gross Margin		(51)

Changes in Expenses and Other:
Other Operation and Maintenance		221
Asset Impairments and Other Related Charges		(139)
Depreciation and Amortization		(15)
Taxes Other Than Income Taxes		(1)
Interest and Investment Income		20
Carrying Costs Income		323
Allowance for Equity Funds Used During Construction		14
Interest Expense		56
Total Change in Expenses and Other		479

Income Tax Expense		(71)

Year Ended December 31, 2011	$	1,549

·	Retail Margins decreased $139 million primarily due to the following:
	·	A $132 million decrease attributable to Ohio customers switching to alternative CRES providers. This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
	·	An $87 million decrease in weather-related usage in our eastern region primarily due to a 13% decrease in heating degree days and a 7% decrease in cooling degree days.
	·	An $84 million decrease in rate related margins for APCo due to the expiration of E&R cost recovery in Virginia.
	·	A $60 million decrease due to the elimination of POLR charges, effective June 2011, in Ohio as a result of the October 2011 PUCO remand order.
	·	A $51 million net decrease due to unfavorable Ohio and Virginia regulatory orders.
	·	A $30 million increase in other variable electric generation expenses.
	These decreases were partially offset by:
	·	Successful rate proceedings in our service territories which include:
		·	A $120 million rate increase for OPCo.
		·	A $63 million rate increase for APCo.
		·	A $30 million rate increase for SWEPCo.
		·	A $27 million rate increase for KPCo.
		·	A $27 million rate increase for I&M.
				For the rate increases described above, $78 million relates to riders/trackers which have corresponding increases in other expense items below.
	·	A $38 million increase in weather-related usage in our western region primarily due to a 20% increase in cooling degree days, slightly offset by a 7% decrease in heating degree days.

	·	A $30 million increase due to increased SWEPCo gross margin from sales to customers previously served by Valley Electric Membership Corporation (VEMCO). SWEPCo acquired VEMCO assets and began serving VEMCO customers in October 2010.
	·	A $14 million increase related to TCC’s Transition Funding. This increase is offset by an increase in Depreciation and Amortization expenses.
·	Margins from Off-system Sales increased $44 million primarily due to an increase in PJM capacity revenues and higher physical sales volumes, partially offset by lower trading and marketing margins.
·	Transmission Revenues increased $48 million primarily due to net rate increases in PJM and increased transmission revenues for Ohio customers who have switched to alternative CRES providers. The increase in transmission revenues related to CRES providers offsets the lost transmission revenues included in Retail Margins above.

·	Other Operation and Maintenance expenses decreased $221 million primarily due to the following:
	·	A $280 million decrease due to expenses related to the cost reduction initiatives recorded in 2010.
	·	A $54 million decrease due to the 2010 write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC.
	·	A $42 million decrease in administrative and general expenses primarily due to a decrease in fringe benefit expenses.
	·	A $33 million decrease due to the 2011 deferral of 2010 costs related to storms and our cost reduction initiatives as allowed by the WVPSC.
	·	A $27 million decrease due to the favorable 2011 asset retirement obligation adjustment for APCo related to the early closure and previous write-off of the Mountaineer Carbon Capture and Storage Product Validation Facility.
	·	An $11 million gain from the sale of land in January 2011.
	These decreases were partially offset by:
	·	A $54 million increase in demand side management, energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
	·	A $41 million increase due to the 2011 write-off of a portion of the West Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC.
	·	A $35 million increase related to the 2011 recording of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the approved December 2011 Ohio stipulation agreement.
	·	A $33 million increase in storm-related expenses.
	·	A $33 million increase in plant outage and other plant operating and maintenance expenses.
	·	A $25 million increase due to the 2010 deferral of 2009 storm costs as allowed by the Virginia SCC.
·	Asset Impairments and Other Related Charges in 2011 included the following:
	·	A 2011 plant impairment of $48 million for Sporn Plant Unit 5.
	·	A 2011 plant impairment of $42 million for the FGD project at Muskingum River Plant Unit 5.
	·	A 2011 write-off of $49 million related to SWEPCo’s expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap as a result of the November 2011 Texas Court of Appeals decision.
·	Depreciation and Amortization expenses increased $15 million primarily due to the following:
	·	A $23 million increase due to the amortization of carrying costs on deferred fuel as a result of the October 2011 Ohio POLR remand order.
	·	A $20 million increase in depreciation and amortization for TCC primarily due to increased amortization of TCC’s Securitized Transition Assets. This increase is partially offset by an increase in revenues within Gross Margin.
	·	Overall higher depreciable property balances.
	These increases were partially offset by:
	·	A $34 million decrease in depreciation and amortization for APCo primarily due to the expiration of E&R amortization of deferred carrying costs in Virginia.
·	Interest and Investment Income increased $20 million primarily due to interest income recorded in 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.

·	Carrying Costs Income increased $323 million due to the 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005 and a related favorable 2011 resolution of contested tax items related to the TCC stranded cost settlement.
·	Allowance for Equity Funds Used During Construction increased $14 million primarily due to construction of the Turk and Dresden Plants and various environmental upgrades, partially offset by a decrease due to the completion of the Stall Unit in June 2010.
·	Interest Expense decreased $56 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·	Income Tax Expense increased $71 million primarily due to an increase in pretax book income, partially offset by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits and by the recording of federal and state income tax adjustments.

(a)	ETT’s investment in current and future projects in ERCOT over the next ten years is expected to be $3.056 billion. Future projects will be evaluated on a case-by-case basis.
(b)	AEP owns 25% of Prairie Wind Transmission, LLC (Prairie Wind) through its ownership interest in ETA. ETA is a 50/50 joint venture with MidAmerican Energy and AEP.
(c)	The Pioneer project consists of approximately 240 miles of new 765 kV transmission lines, which is estimated to cost $950 million at completion. In August 2012, Pioneer announced it would develop the first 66-mile segment jointly with Northern Indiana Public Service Company at a total estimated cost of $330 million, subject to regulatory approval. The projected completion date for the first 66-mile segment is 2018. The projected completion dates for the remaining segments have not been determined.
(d)	AEP owns 87.5% of RITELine Indiana, LLC (RITELine IN) through its ownership interest in RITELine Transmission Development, LLC (RTD) and AEP Transmission Holding Company, LLC (AEPTHC). AEP owns 12.5% of RITELine Illinois, LLC (RITELine IL) through its ownership interest in RTD. RTD is a 50/50 joint venture with Exelon Transmission Company, LLC and AEPTHC.
(e)	RITELine IN is a consolidated variable interest entity. RTD received an order from the FERC in October 2011 granting incentives for the RITELine IN and RITELine IL projects. The projects are currently under evaluation by PJM.
(f)	AEP owns 86.5% of Transource Missouri through its ownership interest in Transource Energy, LLC (Transource). Transource is a joint venture with AEPTHC and Great Plains Energy formed to pursue competitive transmission projects in PJM, SPP and MISO. AEPTHC and Great Plains Energy own 86.5% and 13.5% of Transource, respectively.
(g)	In August 2012, Transource Missouri requested at the FERC a base ROE of 10.6% plus incentives.

	2013
	Budgeted
	Construction
	Expenditures
	(in millions)
Environmental		$	544
Generation			647
Transmission			1,286
Distribution			1,009
Other			92
Total		$	3,578

Payments Due by Period

		Less Than						After
Contractual Cash Obligations		1 Year		2-3 Years		4-5 Years		5 Years		Total
		(in millions)
Short-term Debt (a)		$	981	$	-	$	-	$	-	$	981
Interest on Fixed Rate Portion of Long-term
	Debt (b)		861		1,527		1,308		6,011		9,707
Fixed Rate Portion of Long-term Debt (c)			1,410		2,425		2,493		10,513		16,841
Variable Rate Portion of Long-term Debt (d)			761		182		2		-		945
Capital Lease Obligations (e)			95		144		122		244		605
Noncancelable Operating Leases (e)			302		532		452		1,034		2,320
Fuel Purchase Contracts (f)			2,631		3,971		2,906		3,097		12,605
Energy and Capacity Purchase Contracts (g)			177		359		368		2,494		3,398
Construction Contracts for Capital Assets (h)			859		1,264		1,197		1,326		4,646
Total		$	8,077	$	10,404	$	8,848	$	24,719	$	52,048

(a)	Represents principal only excluding interest.
(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2012 and do not reflect anticipated future refinancing, early redemptions or debt issuances.
(c)	See “Long-term Debt” section of Note 13. Represents principal only excluding interest.
(d)	See “Long-term Debt” section of Note 13. Represents principal only excluding interest. Variable rate debt had interest rates that ranged between 0.11% and 2.18% as of December 31, 2012.
(e)	See Note 12.
(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 contractual obligations for energy and capacity purchase contracts.
(h)	Represents only capital assets for which we have 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.

Amount of Commitment Expiration Per Period

	Less Than						After
Other Commercial Commitments	1 Year		2-3 Years		4-5 Years		5 Years		Total
	(in millions)
Standby Letters of Credit (a)	$	131	$	-	$	-	$	-	$	131
Guarantees of the Performance of Outside Parties (b)		-		-		-		115		115
Guarantees of Our Performance (c)		604		15		10		62		691
Total Commercial Commitments	$	735	$	15	$	10	$	177	$	937

(a)	We enter into standby letters of credit (LOCs) with third parties. These LOCs cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP, on behalf of our subsidiaries, and/or the subsidiaries issued all of these LOCs in the ordinary course of business. There is no collateral held in relation to any guarantees in excess of our ownership percentages. In the event any LOC is drawn, there is no recourse to third parties. The maximum future payments of these LOCs are $131 million with maturities ranging from January 2013 to April 2014. See “Letters of Credit” section of Note 5.
(b)	See “Guarantees of Third-Party Obligations” section of Note 5.
(c)	We issued performance guarantees and indemnifications for energy trading and various sale agreements.

	MTM Risk Management Contract Net Assets (Liabilities)
	Year Ended December 31, 2012

				Generation
		Utility		and
		Operations		Marketing		Total
		(in millions)
Total MTM Risk Management Contract Net Assets
	as of December 31, 2011	$	59	$	132	$	191
(Gain) Loss from Contracts Realized/Settled During the Period and
	Entered in a Prior Period		-		(2)		(2)
Fair Value of New Contracts at Inception When Entered During the
	Period (a)		5		18		23
Acquisition of Supply Contracts (b)			-		(25)		(25)
Changes in Fair Value Due to Market Fluctuations During the
	Period (c)		3		5		8
Changes in Fair Value Allocated to Regulated Jurisdictions (d)			1		-		1
Total MTM Risk Management Contract Net Assets
	as of December 31, 2012	$	68	$	128		196
Commodity Cash Flow Hedge Contracts							(12)
Interest Rate and Foreign Currency Cash Flow Hedge Contracts							(37)
Collateral Deposits							43
Total MTM Derivative Contract Net Assets as of December 31, 2012						$	190

(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)	Reflects liabilities associated with the initial fair value of supply contracts from the BlueStar acquisition in March 2012.
(c)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(d)	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.