ye07aepar.htm

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

SELECTED CONSOLIDATED FINANCIAL DATA

(in thousands)

	2007			2006		2005			2004		2003

STATEMENTS OF INCOME DATA
Total Revenues	$	2,607,269		$	2,394,028	$	2,176,273		$	1,957,846	$	1,950,867

Operating Income	$	320,826		$	365,643	$	283,388		$	328,561	$	416,410

Income Before Extraordinary Loss and Cumulative Effect of Accounting Changes	$	133,499		$	181,449	$	135,832		$	153,115	$	202,783
Extraordinary Loss, Net of Tax		(78,763	) (a)		-		-			-		-
Cumulative Effect of Accounting Changes, Net of Tax		-			-		(2,256	)		-		77,257	(b)
Net Income	$	54,736		$	181,449	$	133,576		$	153,115	$	280,040

BALANCE SHEETS DATA
Property, Plant and Equipment	$	8,738,446		$	8,000,278	$	7,176,961		$	6,563,207	$	6,174,158
Accumulated Depreciation and Amortization		2,591,833			2,476,290		2,524,855			2,456,417		2,334,013
Net Property, Plant and Equipment	$	6,146,613		$	5,523,988	$	4,652,106		$	4,106,790	$	3,840,145

Total Assets	$	7,629,330		$	7,016,316	$	6,254,093		$	5,239,918	$	4,977,011

Common Shareholder’s Equity	$	2,082,032		$	2,036,174	$	1,803,701		$	1,409,718	$	1,336,987

Long-term Debt (c)	$	2,847,299		$	2,598,664	$	2,151,378		$	1,784,598	$	1,864,081

Cumulative Preferred Stock Not Subject to Mandatory Redemption	$	17,752		$	17,763	$	17,784		$	17,784	$	17,784

Cumulative Preferred Stock Subject to Mandatory Redemption	$	-		$	-	$	-		$	-	$	5,360

Obligations Under Capital Leases (c)	$	11,101		$	11,859	$	14,892		$	19,878	$	25,352

(a)	Extraordinary Item, Net of Tax for 2007 reflects a change in Virginia law that made SFAS 71 applicable to generation assets. See “Virginia Restructuring” section of Note 4.
(b)	Cumulative Effect of Accounting Changes, Net of Tax for 2003 reflects the adoption of SFAS 143 as it applies to nonregulated assets.
(c)	Including portion due within one year.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

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 956,000 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. As a member of the AEP Power Pool, APCo shares the revenues and the costs of the AEP Power Pool's sales to neighboring utilities and power marketers. APCo also sells power at wholesale to municipalities.

The cost of the AEP Power Pool’s generating capacity is allocated among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. The capacity reserve relationship of the AEP Power Pool members changes as generating assets are added, retired or sold and relative peak demand changes. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool 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 member load ratio (MLR), which determines each member’s percentage share of revenues and costs.

Prior to April 1, 2006, under the SIA, AEPSC allocated physical and financial revenues and expenses from neighboring utilities, power marketers and other power and gas risk management activities among AEP East companies and AEP West companies based on an allocation methodology established at the time of the AEP-CSW merger. Sharing in a calendar year was based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger. This activity resulted in an AEP East companies’ and AEP West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year were also based upon the relative generating capacity of the AEP East companies and AEP West companies in the event the pre-merger activity level was exceeded. The capacity-based allocation mechanism was triggered in July 2005, resulting in an allocation factor of approximately 70% and 30% for the AEP East companies and AEP West companies, respectively, for the remainder of the year.

Effective April 1, 2006, under the SIA, AEPSC allocates physical and financial revenues and expenses from 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 and ERCOT 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. Accordingly, the 2006 results of operations and cash flows reflect nine months of the SIA change.

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 existing power pool 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, over-the-counter 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, PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA.

Results of Operations

2007 Compared to 2006

Reconciliation of Year Ended December 31, 2006 to Year Ended December 31, 2007

Income Before Extraordinary Loss and Cumulative Effect of Accounting Change

(in millions)

Year Ended December 31, 2006			$	181

Changes in Gross Margin:
Retail Margins	(47	)
Off-system Sales	35
Transmission Revenues	2
Other	4
Total Change in Gross Margin				(6	)

Changes in Operating Expenses and Other:
Other Operation and Maintenance	(49	)
Depreciation and Amortization	8
Taxes Other Than Income Taxes	2
Carrying Costs Income	5
Other Income	(11	)
Interest Expense	(36	)
Total Change in Operating Expenses and Other				(81	)

Income Tax Expense				39

Year Ended December 31, 2007			$	133

Income Before Extraordinary Loss and Cumulative Effect of Accounting Change decreased $48 million to $133 million in 2007. The key drivers of the decrease were a $6 million decrease in Gross Margin and an $81 million increase in Operating Expenses and Other, partially offset by a decrease in Income Tax Expense of $39 million.

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 power were as follows:

Retail Margins decreased $47 million primarily due to higher capacity settlement expenses under the Interconnection Agreement. This decrease was partially offset by increases due to the impact of the Virginia base rate order issued in May 2007, the Virginia E&R and fuel cost recovery filings and increased demand in the residential class associated with favorable weather conditions. Cooling degree days increased 40% and heating degree days increased 18%.

Margins from Off-system Sales increased $35 million primarily due to higher physical sales margins and higher trading margins.

Operating Expenses and Other and Income Taxes changed between years as follows:

·	Other Operation and Maintenance expenses increased $49 million primarily due to the following:
	·	A $26 million increase resulting from the settlement between AEP and the Federal EPA regarding alleged violations of the NSR provisions of the CAA. The $26 million represents APCo’s allocation of the settlement. See “Federal EPA Complaint and Notice of Violation” section of Note 6.
	·	A $15 million increase in steam maintenance expenses resulting from forced and planned outages in 2007 at the Amos and Kanawha River Plants.
	·	A $6 million increase primarily related to an increase in uncollectible accounts under a contract dispute with Verizon Communications, Inc. related to pole attachment revenues.

·	Depreciation and Amortization expenses decreased $8 million primarily due to the following:
	·	A $6 million decrease resulting primarily from lower Virginia depreciation rates implemented retroactively to January 2006 partially offset by additional depreciation expense for the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006, and the Mountaineer scrubber, which was placed in service in February 2007.
	·	A $9 million decrease resulting from a net deferral of ARO costs as a regulatory asset as approved in APCo’s Virginia base rate case.
	These decreases were partially offset by:
	·	A $7 million increase in net E&R deferrals and amortization.
·	Carrying Costs Income increased $5 million primarily due to carrying costs associated with the Virginia E&R case.
·	Other Income, Net decreased $11 million primarily due to lower interest income from the Utility Money Pool of $4 million. In addition, the equity component of AFUDC decreased $5 million resulting from lower CWIP balance after the Wyoming-Jacksons Ferry 765 kV line and the Mountaineer scrubber were placed into service.
·	Interest Expense increased $36 million primarily due to a $22 million increase in interest expense from long-term debt issuances and short-term borrowings, an $11 million decrease in the debt component of AFUDC resulting from a lower CWIP balance after the Wyoming-Jackson Ferry 765 kV line and Mountaineer scrubber were placed into service and the reapplication of SFAS 71 and a $4 million increase in the interest on the Virginia provision for revenue collected subject to refund.
·	Income Tax Expense decreased $39 million primarily due to a decrease in pretax book income and state income tax adjustments.

2006 Compared to 2005

Reconciliation of Year Ended December 31, 2005 to Year Ended December 31, 2006

Income Before Extraordinary Loss and Cumulative Effect of Accounting Change

(in millions)

Year Ended December 31, 2005			$	136

Changes in Gross Margin:
Retail Margins	57
Off-system Sales	51
Transmission Revenues	(42	)
Other	11
Total Change in Gross Margin				77

Changes in Operating Expenses and Other:
Other Operation and Maintenance	20
Depreciation and Amortization	(15	)
Carrying Costs Income	11
Other Income	10
Interest Expense	(23	)
Total Change in Operating Expenses and Other				3

Income Tax Expense				(35	)

Year Ended December 31, 2006			$	181

Income Before Extraordinary Loss and Cumulative Effect of Accounting Change increased $45 million to $181 million in 2006 primarily due to an increase in Gross Margin of $77 million, partially offset by an increase in Income Tax Expense of $35 million.

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 power were as follows:

·	Retail Margins increased $57 million in comparison to 2005 primarily due to:
	·	A $71 million increase in retail revenues primarily related to a new industrial customer transferred from an affiliate in 2006 and new rates implemented in relation to APCo’s Virginia general rate case subject to refund. See the “Virginia Base Rate Case” section of Note 4.
	·	A $27 million reduction in capacity settlement payments under the Interconnection Agreement due to APCo’s lower MLR share and increased capacity, partially from APCo’s purchase of the Ceredo Generating Station in 2005.
	·	A $20 million increase in fuel recovery mainly caused by the reactivation of the West Virginia fuel clause in July 2006.
	These increases were partially offset by:
	·	A $45 million decrease related to the Expanded Net Energy Cost (ENEC) mechanism with West Virginia retail customers primarily due to pass-through of off-system sales margins. The mechanism was reinstated in West Virginia effective July 1, 2006 in conjunction with APCo’s West Virginia rate case.
	·	An $18 million decrease in retail sales primarily due to decreased demand in the residential class associated with unfavorable weather conditions. Heating degree days decreased 19% and cooling degree days decreased 12%.
·	Margins from Off-system Sales increased $51 million primarily due to a $51 million increase in physical sales margins and a $26 million increase in APCo’s allocation of off-system sales margins under the SIA, offset by a $26 million decrease in margins from optimization activities. The change in allocation methodology of the SIA occurred on April 1, 2006.
·	Transmission Revenues decreased $42 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $11 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors.
·	Other revenue increased $11 million primarily due to the reversal of previously deferred gains on sales of allowances associated with the Virginia Environmental and Reliability Costs (E&R) case. See “Virginia E&R Costs Recovery Filing” section of Note 4.

Operating Expenses and Other and Income Taxes changed between years as follows:

·	Other Operation and Maintenance expenses decreased $20 million mainly due to a decrease in expenses associated with the Transmission Equalization Agreement with the addition of the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006.
·	Depreciation and Amortization expenses increased $15 million primarily due to the disallowance of certain depreciation expenses previously capitalized in APCo’s E&R case. See “Virginia E&R Costs Recovery Filing” section of Note 4.
·	Carrying Costs Income increased $11 million related to carrying costs associated with the E&R case. See “Virginia E&R Costs Recovery Filing” section of Note 4.
·	Other Income increased $10 million primarily due to interest income related to an increase in Advances to Affiliates during the year and an increase in AFUDC related to APCo’s environmental investment program.
·	Interest Expense increased $23 million primarily due to long-term debt issuances in 2006, partially offset by an increase in allowance for borrowed funds used during construction.
·	Income Tax Expense increased $35 million primarily due to an increase in pretax book income and state income taxes.

Financial Condition

Credit Ratings

S&P and Fitch currently have APCo on stable outlook, while Moody’s placed APCo on negative outlook in January 2008. Current ratings are as follows:

	Moody’s	S&P	Fitch

Senior Unsecured Debt	Baa2	BBB	BBB+

Cash Flow

Cash flows for 2007, 2006 and 2005 were as follows:

	Years Ended December 31,
	2007			2006			2005
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	2,318		$	1,741		$	1,543
Cash Flows from (Used for):
Operating Activities		325,629			468,275			151,474
Investing Activities		(735,949	)		(880,397	)		(687,515	)
Financing Activities		410,197			412,699			536,239
Net Increase (Decrease) in Cash and Cash Equivalents		(123	)		577			198
Cash and Cash Equivalents at End of Period	$	2,195		$	2,318		$	1,741

Operating Activities

Net Cash Flows from Operating Activities were $326 million in 2007. APCo produced income of $55 million during the period and noncash expense items of $197 million for Depreciation and Amortization, $79 million for Extraordinary Loss, Net of Tax, $49 million for Deferred Income Taxes and $30 million for Carrying Costs Income. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital had no significant items in 2007.

Net Cash Flows from Operating Activities were $468 million in 2006. APCo produced income of $181 million during the period and noncash expense items of $206 million for Depreciation and Amortization and $17 million for Deferred Income Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital had no significant items in 2006.

Net Cash Flows from Operating Activities were $151 million in 2005. APCo produced income of $134 million during the period and noncash expense items of $191 million for Depreciation and Amortization and $73 million for Deferred Income Taxes offset by an increase in Pension Contributions to Qualified Plan Trusts of $129 million. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital had one significant item, a decrease in Accrued Taxes, Net of $74 million. During 2005, APCo made federal income tax payments of $75 million.

Investing Activities

Net Cash Flows Used for Investing Activities during 2007, 2006, and 2005 primarily reflect APCo’s construction expenditures of $746 million, $893 million, and $598 million, respectively. Construction expenditures are primarily for projects to improve service reliability for transmission and distribution, as well as environmental upgrades. Environmental upgrades include the installation of selective catalytic reduction equipment on APCo’s plants and the flue gas desulfurization project at the Amos and Mountaineer Plants. In February 2007, the flue gas desulfurization project was completed at the Mountaineer Plant. In 2006, capital projects for transmission expenditures were primarily related to the Wyoming-Jacksons Ferry 765 KV line placed into service in June 2006.

Financing Activities

Net Cash Flows from Financing Activities were $410 million in 2007. APCo issued $500 million in Senior Unsecured Notes and $75 million in Pollution Control Bonds. APCo increased short-term borrowings from the Utility Money Pool by $240 million. APCo retired $325 million of Senior Unsecured Notes. In addition, APCo paid $44 million related to a long-term coal purchase contract amended in March 2006.

Net Cash Flows from Financing Activities were $413 million in 2006. APCo issued $500 million in Senior Unsecured Notes and $50 million in Pollution Control Bonds. APCo also received Capital Contributions from AEP of $100 million and retired $100 million of First Mortgage Bonds. APCo reduced short-term borrowings from the Utility Money Pool by $159 million. In addition, APCo received funds of $68 million related to a long-term coal purchase contract amended in March 2006, partially offset by repayments of $24 million.

Net Cash Flows from Financing Activities were $536 million in 2005. APCo issued Senior Unsecured Notes of $850 million and Notes Payable - Affiliated of $100 million. APCo also received Capital Contributions from AEP of $200 million. APCo retired $450 million of Senior Unsecured Notes and three series of First Mortgage Bonds totaling $125 million. APCo reduced short-term borrowings from the Utility Money Pool by $17 million.

Summary Obligation Information

APCo’s contractual obligations include amounts reported on APCo’s Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes APCo’s contractual cash obligations at December 31, 2007:

Payments Due by Period

(in millions)

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Advances from Affiliates (a)	$	275.3	$	-	$	-	$	-	$	275.3
Interest on Fixed Rate Portion of Long-term Debt (b)		142.7		259.1		215.4		1,541.0		2,158.2
Fixed Rate Portion of Long-term Debt (c)		199.7		400.0		500.0		1,552.0		2,651.7
Variable Rate Portion of Long-term Debt (d)		40.0		-		-		172.8		212.8
Capital Lease Obligations (e)		5.2		5.4		0.8		0.4		11.8
Noncancelable Operating Leases (e)		15.0		26.3		19.3		37.1		97.7
Fuel Purchase Contracts (f)		589.3		754.9		489.6		975.2		2,809.0
Energy and Capacity Purchase Contracts (g)		-		6.1		5.5		-		11.6
Construction Contracts for Capital Assets (h)		180.5		280.6		259.6		77.1		797.8
Total	$	1,447.7	$	1,732.4	$	1,490.2	$	4,355.6	$	9,025.9

(a)	Represents short-term borrowings from the Utility Money Pool.
(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2007 and do not reflect anticipated future refinancings, early redemptions or debt issuances.
(c)	See Note 15. Represents principal only excluding interest.
(d)	See Note 15. Represents principal only excluding interest. Variable rate debt had interest rates that ranged between 4.40% and 6.00% at December 31, 2007.
(e)	See Note 14.
(f)	Represents contractual obligations to purchase coal and other consumables as fuel for electric generation along with related transportation of the fuel.
(g)	Represents contractual cash flows of energy and capacity purchase contracts.
(h)	Represents only capital assets that are contractual obligations.

APCo’s FIN 48 liabilities of $19 million are not included above because APCo cannot reasonably estimate the cash flows by period.

As discussed in Note 9, APCo’s minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trust.

As of December 31, 2007, APCo has no outstanding standby letters of credit or guarantees of performance.

Significant Factors

Virginia Restructuring

In April 2007, the Virginia legislature adopted a comprehensive law providing for the re-regulation on a cost basis of electric utilities’ generation and supply rates after the December 31, 2008 expiration of capped rates. The legislation provides for, among other things, biennial rate reviews beginning in 2009; rate adjustment clauses for the recovery of the costs of (a) transmission services and new transmission investments, (b) demand side management, load management, and energy efficiency programs, (c) renewable energy programs, and (d) environmental retrofit and new generation investments. It also provided for significant return on equity enhancements for investments in new generation and, subject to Virginia SCC approval, certain environmental retrofits, and a minimum allowed return on equity which will be based on the average earned return on equities of regional vertically integrated electric utilities. In addition, effective September 1, 2007, APCo is allowed to retain a minimum of 25% of the margins from off-system sales with the remaining margins from such sales credited against fuel factor expenses with a true-up to actual. The legislation also allows APCo to continue to defer and recover incremental environmental and reliability costs incurred through December 31, 2008. The new legislation should result in significant positive effects on APCo’s future earnings and cash flows resulting from the mandated enhanced future returns on equity, the reduction of regulatory lag from the opportunities to adjust base rates on a biennial basis and the new opportunities to request timely recovery of certain new costs not included in base rates.

Litigation and Regulatory Activity

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 state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrue a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to materially affect APCo’s results of operations, financial condition and cash flows.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of relevant factors.

Critical Accounting Estimates

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

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Risk management assets and liabilities are managed by AEPSC as agent. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on APCo.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in APCo’s Consolidated Balance Sheet as of December 31, 2007 and the reasons for changes in total MTM value as compared to December 31, 2006.

Reconciliation of MTM Risk Management Contracts to

Consolidated Balance Sheet

December 31, 2007

(in thousands)

	MTM Risk Management Contracts			Cash Flow & Fair Value Hedges			DETM Assignment (a)			Total
Current Assets	$	60,934		$	3,773		$	-		$	64,707
Noncurrent Assets		74,729			225			-			74,954
Total MTM Derivative Contract Assets		135,663			3,998			-			139,661

Current Liabilities		(47,714	)		(3,004	)		(4,237	)		(54,955	)
Noncurrent Liabilities		(42,079	)		(135	)		(5,202	)		(47,416	)
Total MTM Derivative Contract Liabilities		(89,793	)		(3,139	)		(9,439	)		(102,371	)

Total MTM Derivative Contract Net Assets (Liabilities)	$	45,870		$	859		$	(9,439	)	$	37,290

(a)	See “Natural Gas Contracts with DETM” section of Note 16.

MTM Risk Management Contract Net Assets

Year Ended December 31, 2007

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2006	$	52,489
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		(20,365	)
Fair Value of New Contracts at Inception When Entered During the Period (a)		-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period		503
Changes in Fair Value Due to Market Fluctuations During the Period (b)		3,330
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		9,913
Total MTM Risk Management Contract Net Assets		45,870
Net Cash Flow & Fair Value Hedge Contracts		859
DETM Assignment (d)		(9,439	)
Total MTM Risk Management Contract Net Assets at December 31, 2007	$	37,290

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(d)	See “Natural Gas Contracts with DETM” section of Note 16.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents:

·	The method of measuring fair value used in determining the carrying amount of total MTM asset or liability (external sources or modeled internally).
·	The maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash.

Maturity and Source of Fair Value of MTM

Risk Management Contract Net Assets

Fair Value of Contracts as of December 31, 2007

(in thousands)

	2008			2009		2010		2011		2012		After 2012			Total
Prices Actively Quoted – Exchange Traded Contracts	$	(5,937	)	$	2,098	$	1,414	$	-	$	-	$	-		$	(2,425	)
Prices Provided by Other External Sources – OTC Broker Quotes (a)		19,953			13,535		10,053		1,203		-		-			44,744
Prices Based on Models and Other Valuation Methods (b)		(796	)		1,141		269		906		2,033		(2	)		3,551
Total	$	13,220		$	16,774	$	11,736	$	2,109	$	2,033	$	(2	)	$	45,870

(a)	“Prices Provided by Other External Sources – OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)	“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.

	Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Consolidated Balance Sheet

APCo is exposed to market fluctuations in energy commodity prices impacting power operations. Management monitors these risks on future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. Management does not hedge all commodity price risk.

Management uses interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt. Management does not hedge all interest rate risk.

Management uses forward contracts and collars as cash flow hedges to lock-in prices on certain transactions denominated in foreign currencies where deemed necessary. Management does not hedge all foreign currency exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on APCo’s Consolidated Balance Sheets and the reasons for the changes from December 31, 2006 to December 31, 2007. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Year Ended December 31, 2007

(in thousands)

	Power			Interest Rate			Foreign Currency			Total
Beginning Balance in AOCI December 31, 2006	$	5,332		$	(7,715	)	$	(164	)	$	(2,547	)
Changes in Fair Value		1,062			(313	)		32			781
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled		(5,611	)		1,426			7			(4,178	)
Ending Balance in AOCI December 31, 2007	$	783		$	(6,602	)	$	(125	)	$	(5,944	)

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $846 thousand loss.

Credit Risk

Counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at December 31, 2007, a near term typical change in commodity prices is not expected to have a material effect on results of operations, cash flows or financial condition.

The following table shows the end, high, average, and low market risk as measured by VaR for the years ended:

December 31, 2007				December 31, 2006
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$455	$2,328	$569	$117	$756	$1,915	$658	$358

Management back-tests its VaR results against performance due to actual price moves. Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days. Management’s backtesting results show that its actual performance exceeded VaR far fewer than once every 20 trading days. As a result, management believes APCo’s VaR calculation is conservative.

As APCo’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand its exposure to extreme price moves. Management employs a historically-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translate into the largest potential mark-to-market loss. Management can then research the underlying positions, price moves and market event that created the most significant exposure.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which APCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. For 2008, the estimated EaR on APCo’s debt portfolio was $3.3 million.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	2007			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	2,333,448		$	2,145,639		$	1,845,170
Sales to AEP Affiliates		263,066			238,592			322,333
Other		10,755			9,797			8,770
TOTAL		2,607,269			2,394,028			2,176,273

EXPENSES
Fuel and Other Consumables Used for Electric Generation		708,127			638,862			549,773
Purchased Electricity for Resale		165,901			123,592			110,693
Purchased Electricity from AEP Affiliates		600,293			492,756			453,600
Other Operation		319,260			284,350			315,605
Maintenance		204,763			190,697			179,119
Depreciation and Amortization		197,259			205,666			191,128
Taxes Other Than Income Taxes		90,840			92,462			92,967
TOTAL		2,286,443			2,028,385			1,892,885

OPERATING INCOME		320,826			365,643			283,388

Other Income (Expense):
Interest Income		2,676			8,648			2,540
Carrying Costs Income		30,179			25,666			14,438
Allowance for Equity Funds Used During Construction		7,337			12,014			7,956
Interest Expense		(165,405	)		(129,106	)		(106,301	)

INCOME BEFORE INCOME TAXES		195,613			282,865			202,021

Income Tax Expense		62,114			101,416			66,189

INCOME BEFORE EXTRAORDINARY LOSS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		133,499			181,449			135,832

EXTRAORDINARY LOSS – REAPPLICATION OF REGULATORY ACCOUNTING FOR GENERATION, NET OF TAX		(78,763	)		-			-

CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX		-			-			(2,256	)

NET INCOME		54,736			181,449			133,576

Preferred Stock Dividend Requirements Including Capital Stock Expense and Other		952			952			2,178

EARNINGS APPLICABLE TO COMMON STOCK	$	53,784		$	180,497		$	131,398

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

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004	$	260,458	$	722,314	$	508,618		$	(81,672	)	$	1,409,718

Capital Contribution from Parent				200,000								200,000
Common Stock Dividends						(5,000	)					(5,000	)
Preferred Stock Dividends						(800	)					(800	)
Capital Stock Expense and Other				2,523		(1,378	)					1,145
TOTAL												1,605,063

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $3,821									(7,097	)		(7,097	)
Minimum Pension Liability, Net of Tax of $38,855									72,159			72,159
NET INCOME						133,576						133,576
TOTAL COMPREHENSIVE INCOME												198,638

DECEMBER 31, 2005		260,458		924,837		635,016			(16,610	)		1,803,701

Capital Contribution from Parent				100,000								100,000
Common Stock Dividends						(10,000	)					(10,000	)
Preferred Stock Dividends						(800	)					(800	)
Capital Stock Expense and Other				157		(152	)					5
TOTAL												1,892,906

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $7,471									13,874			13,874
Minimum Pension Liability, Net of Tax of $7									(14	)		(14	)
NET INCOME						181,449						181,449
TOTAL COMPREHENSIVE INCOME												195,309
Minimum Pension Liability Elimination, Net of Tax of $109									203			203
SFAS 158 Adoption, Net of Tax of $28,132									(52,244	)		(52,244	)

DECEMBER 31, 2006		260,458		1,024,994		805,513			(54,791	)		2,036,174

FIN 48 Adoption, Net of Tax						(2,685	)					(2,685	)
Common Stock Dividends						(25,000	)					(25,000	)
Preferred Stock Dividends						(799	)					(799	)
Capital Stock Expense and Other				155		(153	)					2
TOTAL												2,007,692

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $1,829									(3,397	)		(3,397	)
SFAS 158 Adoption Costs Established as a Regulatory Asset Related to the Reapplication of SFAS 71, Net of Tax of $6,055									11,245			11,245
Pension and OPEB Funded Status, Net of Tax of $6,330									11,756			11,756
NET INCOME						54,736						54,736
TOTAL COMPREHENSIVE INCOME												74,340

DECEMBER 31, 2007	$	260,458	$	1,025,149	$	831,612		$	(35,187	)	$	2,082,032

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2007 and 2006

(in thousands)

	2007			2006
CURRENT ASSETS
Cash and Cash Equivalents	$	2,195		$	2,318
Accounts Receivable:
Customers		176,834			180,190
Affiliated Companies		113,582			98,237
Accrued Unbilled Revenues		38,397			46,281
Miscellaneous		2,823			3,400
Allowance for Uncollectible Accounts		(13,948	)		(4,334	)
Total Accounts Receivable		317,688			323,774
Fuel		82,203			77,077
Materials and Supplies		76,685			56,235
Risk Management Assets		64,707			105,376
Regulatory Asset for Under-Recovered Fuel Costs		-			29,526
Prepayments and Other		19,675			23,874
TOTAL		563,153			618,180

PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		3,625,788			2,844,803
Transmission		1,675,081			1,620,512
Distribution		2,372,687			2,237,887
Other		351,827			339,450
Construction Work in Progress		713,063			957,626
Total		8,738,446			8,000,278
Accumulated Depreciation and Amortization		2,591,833			2,476,290
TOTAL - NET		6,146,613			5,523,988

OTHER NONCURRENT ASSETS
Regulatory Assets		652,739			622,153
Long-term Risk Management Assets		74,954			88,906
Deferred Charges and Other		191,871			163,089
TOTAL		919,564			874,148

TOTAL ASSETS	$	7,629,330		$	7,016,316

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

December 31, 2007 and 2006

	2007			2006
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	275,257		$	34,975
Accounts Payable:
General		241,871			296,437
Affiliated Companies		106,852			105,525
Long-term Debt Due Within One Year – Nonaffiliated		239,732			324,191
Risk Management Liabilities		54,955			81,114
Customer Deposits		50,260			56,364
Accrued Taxes		58,519			60,056
Other		181,175			172,943
TOTAL		1,208,621			1,131,605

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		2,507,567			2,174,473
Long-term Debt – Affiliated		100,000			100,000
Long-term Risk Management Liabilities		47,416			64,909
Deferred Income Taxes		948,891			957,229
Regulatory Liabilities and Deferred Investment Tax Credits		505,556			309,724
Deferred Credits and Other		211,495			224,439
TOTAL		4,320,925			3,830,774

TOTAL LIABILITIES		5,529,546			4,962,379

Cumulative Preferred Stock Not Subject to Mandatory Redemption		17,752			17,763

Commitments and Contingencies (Note 6)

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		1,025,149			1,024,994
Retained Earnings		831,612			805,513
Accumulated Other Comprehensive Income (Loss)		(35,187	)		(54,791	)
TOTAL		2,082,032			2,036,174

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	7,629,330		$	7,016,316

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	2007			2006			2005
OPERATING ACTIVITIES
Net Income	$	54,736		$	181,449		$	133,576
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		197,259			205,666			191,128
Deferred Income Taxes		48,962			17,225			72,763
Cumulative Effect of Accounting Change, Net of Tax		-			-			2,256
Extraordinary Loss, Net of Tax		78,763			-			-
Carrying Costs Income		(30,179	)		(25,666	)		(14,438	)
Allowance for Equity Funds Used During Construction		(7,337	)		(12,014	)		(7,956	)
Mark-to-Market of Risk Management Contracts		4,834			2,824			(13,701	)
Pension Contributions to Qualified Plan Trusts		-			-			(129,117	)
Change in Other Noncurrent Assets		(27,671	)		(55,851	)		(7,053	)
Change in Other Noncurrent Liabilities		9,042			54,745			(13,741	)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		(10,370	)		21,412			(26,665	)
Fuel, Materials and Supplies		(8,435	)		(13,688	)		(25,419	)
Accounts Payable		(13,226	)		37,533			61,086
Customer Deposits		(6,104	)		(23,490	)		37,032
Accrued Taxes, Net		(2,740	)		39,454			(73,550	)
Fuel Over/Under-Recovery, Net		41,967			11,532			(36,499	)
Other Current Assets		1,888			25,252			(24,831	)
Other Current Liabilities		(5,760	)		1,892			26,603
Net Cash Flows from Operating Activities		325,629			468,275			151,474

INVESTING ACTIVITIES
Construction Expenditures		(745,830	)		(892,816	)		(597,808	)
Change in Other Cash Deposits, Net		1,061			(945	)		(24	)
Purchase of Ceredo Generating Station		-			-			(100,000	)
Proceeds from Sales of Assets		9,020			13,364			10,317
Other		(200	)		-			-
Net Cash Flows Used for Investing Activities		(735,949	)		(880,397	)		(687,515	)

FINANCING ACTIVITIES
Capital Contributions from Parent		-			100,000			200,000
Issuance of Long-term Debt – Nonaffiliated		568,778			561,710			840,469
Issuance of Long-term Debt – Affiliated		-			-			100,000
Change in Advances from Affiliates, Net		240,282			(159,158	)		(16,927	)
Retirement of Long-term Debt – Nonaffiliated		(325,013	)		(117,511	)		(575,010	)
Retirement of Cumulative Preferred Stock		(9	)		(16	)		-
Principal Payments for Capital Lease Obligations		(4,402	)		(5,166	)		(6,493	)
Funds from Amended Coal Contract		-			68,078			-
Amortization of Funds from Amended Coal Contract		(43,640	)		(24,438	)		-
Dividends Paid on Common Stock		(25,000	)		(10,000	)		(5,000	)
Dividends Paid on Cumulative Preferred Stock		(799	)		(800	)		(800	)
Net Cash Flows from Financing Activities		410,197			412,699			536,239

Net Increase (Decrease) in Cash and Cash Equivalents		(123	)		577			198
Cash and Cash Equivalents at Beginning of Period		2,318			1,741			1,543
Cash and Cash Equivalents at End of Period	$	2,195		$	2,318		$	1,741

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	148,805		$	118,220		$	91,373
Net Cash Paid for Income Taxes		26,189			50,830			75,160
Noncash Acquisitions Under Capital Leases		3,636			3,017			1,988
Construction Expenditures Included in Accounts Payable at December 31,		107,001			130,558			82,640

In connection with the acquisition of Ceredo Generating Station in December 2005, APCo assumed $556 thousand of liabilities.

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

	Footnote Reference

Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Change	Note 2
Rate Matters	Note 4
Effects of Regulation	Note 5
Commitments, Guarantees and Contingencies	Note 6
Company-wide Staffing and Budget Review	Note 7
Acquisitions, Dispositions, Asset Impairments and Assets Held for Sale	Note 8
Benefit Plans	Note 9
Business Segments	Note 11
Derivatives, Hedging and Financial Instruments	Note 12
Income Taxes	Note 13
Leases	Note 14
Financing Activities	Note 15
Related Party Transactions	Note 16
Property, Plant and Equipment	Note 17
Unaudited Quarterly Financial Information	Note 18

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Appalachian Power Company:

We have audited the accompanying consolidated balance sheets of Appalachian Power Company and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2007. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 2 and 9 to the consolidated financial statements, respectively, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”, effective January 1, 2007, and FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2008

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.

APCo’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control- Integrated Framework. Based on our assessment, the Company’s internal control over financial reporting was effective as of December 31, 2007.

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

COLUMBUS SOUTHERN POWER COMPANY

AND SUBSIDIARIES

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

As a public utility, CSPCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 746,000 retail customers in central and southern Ohio. CSPCo consolidates Colomet, Inc., Conesville Coal Preparation Company and Simco, Inc., its wholly-owned subsidiaries. As a member of the AEP Power Pool, CSPCo shares the revenues and the costs of the AEP Power Pool’s sales to neighboring utilities and power marketers.

In March 2007, CSPCo 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. CSPCo 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.

AEPSC conducts power, gas, coal and emission allowance risk management activities on CSPCo’s behalf. CSPCo 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 existing power pool agreement and the SIA. CSPCo 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, over-the-counter 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.

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

Results of Operations

2007 Compared to 2006

Reconciliation of Year Ended December 31, 2006 to Year Ended December 31, 2007

Income Before Cumulative Effect of Accounting Change

(in millions)

Year Ended December 31, 2006			$	186

Changes in Gross Margin:
Retail Margins	144
Off-system Sales	9
Transmission Revenues	(1	)
Other	(3	)
Total Change in Gross Margin				149

Changes in Operating Expenses and Other:
Other Operation and Maintenance	(29	)
Depreciation and Amortization	(4	)
Taxes Other Than Income Taxes	(6	)
Carrying Costs Income	1
Other Income	(6	)
Interest Expense	(4	)
Total Change in Operating Expenses and Other				(48	)

Income Tax Expense				(29	)

Year Ended December 31, 2007			$	258

Income Before Cumulative Effect of Accounting Change increased $72 million to $258 million in 2007. The key drivers of the increase were a $149 million increase in Gross Margin, partially offset by a $48 million increase in Operating Expenses and Other and a $29 million increase in Income Tax Expense.

·	Retail Margins increased $144 million primarily due to:
	·	An $84 million increase in capacity settlements due to recent plant acquisitions and changes in relative peak demands of AEP Power Pool members under the Interconnection Agreement.
	·	A $59 million increase in rate revenues related to a $54 million increase in CSPCo’s RSP and a $5 million increase related to recovery of storm costs. See “Ohio Rate Matters” section of Note 4.
	·	A $51 million increase in industrial revenue primarily due to the addition of Ormet, a major industrial customer. See “Ormet” section of Note 4.
	·	A $19 million increase in residential and commercial revenue primarily due to a 24% increase in heating degree days and a 37% increase in cooling degree days.
	These increases were partially offset by:
	·	A $29 million decrease in fuel margins.
	·	A $19 million decrease due to PJM’s revision of its pricing methodology for transmission line losses to marginal-loss pricing effective June 1, 2007. See “PJM Marginal-Loss Pricing” section of Note 4.
	·	A $14 million decrease in non-fuel costs associated with CSPCo’s Unit Power Agreement with the Lawrenceburg Plant, beginning in May 2007. See “Unit Power Agreement” section of Note 16.

·	Margins from Off-system Sales increased $9 million primarily due to higher trading margins, partially offset by lower physical sales margins.

Operating Expenses and Other and Income Taxes changed between years as follows:

·	Other Operation and Maintenance expenses increased $29 million primarily due to:
	·		A $21 million increase in expenses related to CSPCo’s Unit Power Agreement for AEGCo’s Lawrenceburg Plant, beginning in May 2007. See “Unit Power Agreement” section of Note 16.
	·		A $15 million increase due to the settlement agreement regarding alleged violations of the NSR provisions of the CAA. The $15 million represents CSPCo’s allocation of the settlement. See “Federal EPA Complaint and Notice of Violation” section of Note 6.
	·		A $7 million increase in overhead line expenses due to the 2006 recognition of a regulatory asset related to PUCO orders regarding distribution service reliability and restoration costs.
·		Depreciation and Amortization expense increased $4 million primarily due to an $11 million increase in depreciation expense resulting from the acquisition of the Darby Plant in April 2007 and the completion of the flue gas desulfurization inlet duct project on Unit 5 at the Conesville Plant in February 2007. The increase was partially offset by a $7 million decrease resulting from amortization of regulatory credits related to the recovery of rates paid by Ormet.
·		Taxes Other Than Income Taxes increased $6 million due to increases in state excise taxes, gross receipts taxes and property taxes.
·		Other Income decreased $6 million due to interest income on tax refunds received in 2006 for the years 1991 through 1996.
·		Interest Expense increased $4 million primarily due to increases in long-term borrowings and short-term borrowings from the Utility Money Pool.
·		Income Tax Expense increased $29 million primarily due to an increase in pretax book income, partially offset by the recording of state income tax adjustments.

Critical Accounting Estimates

Adoption of New Accounting Pronouncement

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Risk management assets and liabilities are managed by AEPSC as agent. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which CSPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. For 2008, the estimated EaR on CSPCo’s debt portfolio was $2 million.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	2007			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	1,893,045		$	1,715,542		$	1,413,056
Sales to AEP Affiliates		143,112			85,726			124,410
Other		7,155			5,467			4,866
TOTAL		2,043,312			1,806,735			1,542,332

EXPENSES
Fuel and Other Consumables Used for Electric Generation		342,149			294,841			255,913
Purchased Electricity for Resale		158,526			115,420			37,012
Purchased Electricity from AEP Affiliates		362,648			365,510			362,959
Other Operation		280,705			256,479			225,896
Maintenance		93,157			88,654			87,303
Asset Impairments and Other Related Charges		-			-			39,109
Depreciation and Amortization		197,303			193,251			142,346
Taxes Other Than Income Taxes		161,463			154,930			148,914
TOTAL		1,595,951			1,469,085			1,299,452

OPERATING INCOME		447,361			337,650			242,880

Other Income (Expense):
Interest Income		1,943			8,885			3,972
Carrying Costs Income		4,758			4,122			10,367
Allowance for Equity Funds Used During Construction		3,036			1,865			1,579
Interest Expense		(69,625	)		(66,100	)		(59,539	)

INCOME BEFORE INCOME TAXES		387,473			286,422			199,259

Income Tax Expense		129,385			100,843			61,460

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		258,088			185,579			137,799

CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX		-			-			(839	)

NET INCOME		258,088			185,579			136,960

Capital Stock Expense		157			157			2,620

EARNINGS APPLICABLE TO COMMONE STOCK	$	257,931		$	185,422		$	134,340

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

See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004	$	41,026	$	577,415	$	341,025		$	(60,816	)	$	898,650

Common Stock Dividends						(114,000	)					(114,000	)
Capital Stock Expense				2,620		(2,620	)					-
TOTAL												784,650

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $1,212									(2,252	)		(2,252	)
Minimum Pension Liability, Net of Tax of $33,486									62,188			62,188
NET INCOME						136,960						136,960
TOTAL COMPREHENSIVE INCOME												196,896

DECEMBER 31, 2005		41,026		580,035		361,365			(880	)		981,546

Common Stock Dividends						(90,000	)					(90,000	)
Capital Stock Expense				157		(157	)					-
TOTAL												891,546

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $2,292									4,257			4,257
Minimum Pension Liability, Net of Tax of $2									(4	)		(4	)
NET INCOME						185,579						185,579
TOTAL COMPREHENSIVE INCOME												189,832
Minimum Pension Liability Elimination, Net of Tax of $14									25			25
SFAS 158 Adoption, Net of Tax of $13,670									(25,386	)		(25,386	)

DECEMBER 31, 2006		41,026		580,192		456,787			(21,988	)		1,056,017

FIN 48 Adoption, Net of Tax						(3,022	)					(3,022	)
Common Stock Dividends						(150,000	)					(150,000	)
Capital Stock Expense				157		(157	)					-
TOTAL												902,995

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $2,180									(4,048	)		(4,048	)
Pension and OPEB Funded Status, Net of Tax of $3,900									7,242			7,242
NET INCOME						258,088						258,088
TOTAL COMPREHENSIVE INCOME												261,282

DECEMBER 31, 2007	$	41,026	$	580,349	$	561,696		$	(18,794	)	$	1,164,277

See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2007 and 2006

(in thousands)

	2007			2006
CURRENT ASSETS
Cash and Cash Equivalents	$	1,389		$	1,319
Other Cash Deposits		53,760			1,151
Accounts Receivable:
Customers		57,268			49,362
Affiliated Companies		32,852			62,866
Accrued Unbilled Revenues		14,815			11,042
Miscellaneous		9,905			4,895
Allowance for Uncollectible Accounts		(2,563	)		(546	)
Total Accounts Receivable		112,277			127,619
Fuel		35,849			37,348
Materials and Supplies		36,626			31,765
Emission Allowances		16,811			3,493
Risk Management Assets		34,564			66,238
Prepayments and Other		11,877			19,719
TOTAL		303,153			288,652

PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		2,072,564			1,896,073
Transmission		510,107			479,119
Distribution		1,552,999			1,475,758
Other		198,476			191,103
Construction Work in Progress		415,327			294,138
Total		4,749,473			4,336,191
Accumulated Depreciation and Amortization		1,697,793			1,611,043
TOTAL - NET		3,051,680			2,725,148

OTHER NONCURRENT ASSETS
Regulatory Assets		235,883			298,304
Long-term Risk Management Assets		43,352			56,206
Deferred Charges and Other		181,563			152,379
TOTAL		460,798			506,889

TOTAL ASSETS	$	3,815,631		$	3,520,689

See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDER’S EQUITY

December 31, 2007 and 2006

	2007			2006
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	95,199		$	696
Accounts Payable:
General		113,290			112,431
Affiliated Companies		65,292			59,538
Long-term Debt Due Within One Year – Nonaffiliated		112,000			-
Risk Management Liabilities		30,118			49,285
Customer Deposits		45,602			34,991
Accrued Taxes		179,831			166,551
Other		96,892			58,011
TOTAL		738,224			481,503

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		1,086,224			1,097,322
Long-term Debt – Affiliated		100,000			100,000
Long-term Risk Management Liabilities		27,454			40,477
Deferred Income Taxes		437,306			475,888
Regulatory Liabilities and Deferred Investment Tax Credits		165,635			179,048
Deferred Credits and Other		96,511			90,434
TOTAL		1,913,130			1,983,169

TOTAL LIABILITIES		2,651,354			2,464,672

Commitments and Contingencies (Note 6)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 24,000,000 Shares
Outstanding – 16,410,426 Shares		41,026			41,026
Paid-in Capital		580,349			580,192
Retained Earnings		561,696			456,787
Accumulated Other Comprehensive Income (Loss)		(18,794	)		(21,988	)
TOTAL		1,164,277			1,056,017

TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY	$	3,815,631		$	3,520,689

See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	2007			2006			2005
OPERATING ACTIVITIES
Net Income	$	258,088		$	185,579		$	136,960
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		197,303			193,251			142,346
Deferred Income Taxes		(20,874	)		(10,900	)		19,209
Cumulative Effect of Accounting Change, Net of Tax		-			-			839
Asset Impairments and Other Related Charges		-			-			39,109
Carrying Costs Income		(4,758	)		(4,122	)		(10,367	)
Allowance for Equity Funds Used During Construction		(3,036	)		(1,865	)		(1,579	)
Mark-to-Market of Risk Management Contracts		6,069			(1,299	)		(8,915	)
Pension Contributions to Qualified Plan Trusts		-			-			(85,871	)
Change in Other Noncurrent Assets		(44,346	)		(31,947	)		(25,132	)
Change in Other Noncurrent Liabilities		(11,030	)		16,013			9,979
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		6,242			(5,766	)		12,182
Fuel, Materials and Supplies		11,822			(13,015	)		2,030
Accounts Payable		9,176			29,063			3,075
Customer Deposits		10,611			(12,022	)		22,123
Accrued Taxes, Net		26,705			40,897			(78,278	)
Other Current Assets		(10,295	)		25,592			(12,001	)
Other Current Liabilities		19,170			6,738			5,525
Net Cash Flows from Operating Activities		450,847			416,197			171,234

INVESTING ACTIVITIES
Construction Expenditures		(338,097	)		(306,559	)		(165,452	)
Change in Other Cash Deposits, Net		(52,609	)		(1,151	)		-
Change in Advances to Affiliates, Net		-			-			141,550
Acquisition of Waterford Plant		-			-			(218,357	)
Acquisition of Monongahela Power’s Ohio Assets		-			-			(41,762	)
Acquisition of Darby Plant		(102,033	)		-			-
Proceeds from Sale of Assets		1,200			1,827			4,639
Net Cash Flows Used for Investing Activities		(491,539	)		(305,883	)		(279,382	)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated		99,173			-			244,733
Change in Advances from Affiliates, Net		94,503			(16,913	)		17,609
Retirement of Long-term Debt – Nonaffiliated		-			-			(36,000	)
Principal Payments for Capital Lease Obligations		(2,914	)		(3,022	)		(3,312	)
Dividends Paid on Common Stock		(150,000	)		(90,000	)		(114,000	)
Net Cash Flows from (Used for) Financing Activities		40,762			(109,935	)		109,030

Net Increase in Cash and Cash Equivalents		70			379			882
Cash and Cash Equivalents at Beginning of Period		1,319			940			58
Cash and Cash Equivalents at End of Period	$	1,389		$	1,319		$	940

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	65,552		$	62,806		$	54,767
Net Cash Paid for Income Taxes		144,101			92,295			136,239
Noncash Acquisitions Under Capital Leases		2,702			2,286			998
Construction Expenditures Included in Accounts Payable at December 31,		42,163			35,627			11,254
Noncash Assumption of Liabilities Related to Acquisition of Darby Plant		2,339			-			-
Noncash Assumption of Liabilities Related to Acquisition of Waterford Plant		-			-			2,295
Noncash Assumption of Liabilities Related to Acquisition of Monongahela Power’s Ohio Assets		-			-			1,839

See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

	Footnote Reference

Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Change	Note 2
Rate Matters	Note 4
Effects of Regulation	Note 5
Commitments, Guarantees and Contingencies	Note 6
Company-wide Staffing and Budget Review	Note 7
Acquisitions and Asset Impairment	Note 8
Benefit Plans	Note 9
Business Segments	Note 11
Derivatives, Hedging and Financial Instruments	Note 12
Income Taxes	Note 13
Leases	Note 14
Financing Activities	Note 15
Related Party Transactions	Note 16
Property, Plant and Equipment	Note 17
Unaudited Quarterly Financial Information	Note 18

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Columbus Southern Power Company:

We have audited the accompanying consolidated balance sheets of Columbus Southern Power Company and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2007. 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 Columbus Southern Power Company and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2008

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Columbus Southern Power Company and subsidiaries (CSPCo) 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. CSPCo’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.

CSPCo’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control- Integrated Framework. Based on our assessment, the Company’s internal control over financial reporting was effective as of December 31, 2007.

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

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 583,000 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. As a member of the AEP Power Pool, I&M shares the revenues and the costs of the AEP Power Pool's sales to neighboring utilities and power marketers. I&M also sells power at wholesale to municipalities and electric cooperatives. I&M’s River Transportation Division (RTD) provides barging services to affiliates and nonaffiliated companies. The revenues from barging are the majority of other revenues.

Under unit power agreements, 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 AEP Power Pool. An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo’s Rockport Plant capacity to KPCo through 2022. Therefore, 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 existing power pool 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, over-the-counter 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.

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

Results of Operations

2007 Compared to 2006

Reconciliation of Year Ended December 31, 2006 to Year Ended December 31, 2007

Net Income

(in millions)

Year Ended December 31, 2006			$	121

Changes in Gross Margin:
Retail Margins	(22	)
FERC Municipals and Cooperatives	49
Off-system Sales	8
Transmission Revenues	10
Other	(5	)
Total Change in Gross Margin				40

Changes in Operating Expenses and Other:
Other Operation and Maintenance	(46	)
Depreciation and Amortization	32
Taxes Other Than Income Taxes	(1	)
Other Income	(11	)
Interest Expense	(7	)
Total Change in Operating Expenses and Other				(33	)

Income Tax Expense				9

Year Ended December 31, 2007			$	137

Net Income increased $16 million to $137 million in 2007. The key drivers of the increase were a $40 million increase in Gross Margin and a $9 million decrease in Income Tax Expense partially offset by a $33 million increase in Operating Expenses and Other.

·	Retail Margins decreased $22 million primarily due to a reduction in capacity settlement revenues of $28 million under the Interconnection Agreement reflecting I&M’s change in MLR, lower revenues from financial transmission rights, net of congestion, of $22 million due to fewer constraints in the PJM market and increased costs of $19 million for PJM’s revision of its pricing methodology for transmission line losses to marginal-loss pricing effective June 1, 2007. See “PJM Marginal-Loss Pricing” section of Note 4. Higher retail sales of $35 million reflecting favorable weather conditions and higher fuel margins of $16 million partially offset the decreases. Heating and cooling degree days increased significantly in both the Indiana and Michigan jurisdictions. The Indiana fuel rate cap ended July 1, 2007 contributing to the higher fuel margins.
·	FERC Municipals and Cooperatives margins increased $49 million due to the addition of new municipal contracts including new rates and increased demand effective July 2006 and January 2007.
·	Margins from Off-system Sales increased $8 million primarily due to higher trading margins partially offset by lower physical sales margins.
·	Transmission Revenues increased $10 million primarily due to higher wholesale transmission revenue.

Operating Expenses and Other and Income Taxes changed between years as follows:

·	Other Operation and Maintenance expenses increased $46 million primarily due to a $24 million increase in steam plant maintenance and a $15 million increase in steam plant operating expenses. The increases are primarily due to coal-fired plant maintenance expenses resulting from planned outages at Rockport and Tanners Creek Plants and the settlement agreement regarding alleged violations of the NSR provisions of the CAA, of which $14 million was allocated to I&M. See “Federal EPA Complaint and Notice of Violation” section of Note 6.
·	Depreciation and Amortization decreased $32 million primarily due to reduced depreciation rates reflecting longer estimated lives for Cook and Tanners Creek Plants. Depreciation rates were reduced for the Indiana jurisdiction in June 2007 and the FERC and Michigan jurisdictions in October 2007. See “Indiana Depreciation Study Filing” and “Michigan Depreciation Study Filing” sections of Note 4.
·	Other Income decreased $11 million primarily due to a decrease in interest income related to 2006 tax accrual adjustments and lower equity AFUDC.
·	Interest Expense increased $7 million primarily due to an increase in outstanding long-term debt and higher interest rates.
·	Income Tax Expense decreased $9 million primarily due to recording federal and state income tax adjustments and changes in certain book/tax differences accounted for on a flow-through basis partially offset by an increase in pretax book income and a decrease in amortization of investment tax credits.

Critical Accounting Estimates

Adoption of New Accounting Pronouncement

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Risk management assets and liabilities are managed by AEPSC as agent. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which I&M’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short- term debt) as well as long-term debt issuances in the next twelve months. For 2008, the estimated EaR on I&M’s debt portfolio was $2.1 million.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	2007			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	1,708,198		$	1,601,135		$	1,445,866
Sales to AEP Affiliates		248,414			291,033			366,032
Other – Affiliated		59,213			52,598			46,719
Other – Nonaffiliated		27,367			32,181			33,985
TOTAL		2,043,192			1,976,947			1,892,602

EXPENSES
Fuel and Other Consumables Used for Electric Generation		374,256			373,741			327,263
Purchased Electricity for Resale		89,295			62,098			48,378
Purchased Electricity from AEP Affiliates		341,981			343,156			306,117
Other Operation		492,309			472,404			451,553
Maintenance		216,598			190,866			202,909
Depreciation and Amortization		176,611			208,633			196,037
Taxes Other Than Income Taxes		74,976			73,858			73,685
TOTAL		1,766,026			1,724,756			1,605,942

OPERATING INCOME		277,166			252,191			286,660

Other Income (Expense):
Interest Income		2,740			9,868			2,006
Allowance for Equity Funds Used During Construction		4,522			7,937			4,457
Interest Expense		(80,034	)		(72,723	)		(65,041	)

INCOME BEFORE INCOME TAXES		204,394			197,273			228,082

Income Tax Expense		67,499			76,105			81,230

NET INCOME		136,895			121,168			146,852

Preferred Stock Dividend Requirements Including Capital Stock Expense and Other		339			339			395

EARNINGS APPLICABLE TO COMMON STOCK	$	136,556		$	120,829		$	146,457

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

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004	$	56,584	$	858,835	$	221,330		$	(45,251	)	$	1,091,498

Common Stock Dividends						(62,000	)					(62,000	)
Preferred Stock Dividends						(339	)					(339	)
Capital Stock Expense and Other				2,455		(56	)					2,399
TOTAL												1,031,558

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $328									609			609
Minimum Pension Liability, Net of Tax of $22,116									41,073			41,073
NET INCOME						146,852						146,852
TOTAL COMPREHENSIVE INCOME												188,534

DECEMBER 31, 2005		56,584		861,290		305,787			(3,569	)		1,220,092

Common Stock Dividends						(40,000	)					(40,000	)
Preferred Stock Dividends						(339	)					(339	)
TOTAL												1,179,753

COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $2,959									(5,495	)		(5,495	)
Minimum Pension Liability, Net of Tax of $70									(129	)		(129	)
NET INCOME						121,168						121,168
TOTAL COMPREHENSIVE INCOME												115,544
Minimum Pension Liability Elimination, Net of Tax of $124									231			231
SFAS 158 Adoption, Net of Tax of $3,278									(6,089	)		(6,089	)

DECEMBER 31, 2006		56,584		861,290		386,616			(15,051	)		1,289,439

FIN 48 Adoption, Net of Tax						327						327
Common Stock Dividends						(40,000	)					(40,000	)
Preferred Stock Dividends						(339	)					(339	)
Gain on Reacquired Preferred Stock				1								1
TOTAL												1,249,428

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $1,717									(3,189	)		(3,189	)
Pension and OPEB Funded Status, Net of Tax of $1,381									2,565			2,565
NET INCOME						136,895						136,895
TOTAL COMPREHENSIVE INCOME												136,271

DECEMBER 31, 2007	$	56,584	$	861,291	$	483,499		$	(15,675	)	$	1,385,699

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2007 and 2006

(in thousands)

	2007			2006
CURRENT ASSETS
Cash and Cash Equivalents	$	1,139		$	1,369
Accounts Receivable:
Customers		70,995			82,102
Affiliated Companies		92,018			108,288
Accrued Unbilled Revenues		16,207			2,206
Miscellaneous		1,335			1,838
Allowance for Uncollectible Accounts		(2,711	)		(601	)
Total Accounts Receivable		177,844			193,833
Fuel		61,342			64,669
Materials and Supplies		141,384			129,953
Risk Management Assets		33,334			69,752
Accrued Tax Benefits		4,438			27,378
Prepayments and Other		12,932			15,170
TOTAL		432,413			502,124

PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		3,529,524			3,363,813
Transmission		1,078,575			1,047,264
Distribution		1,196,397			1,102,033
Other (including nuclear fuel and coal mining)		626,390			529,727
Construction Work in Progress		122,296			183,893
Total		6,553,182			6,226,730
Accumulated Depreciation, Depletion and Amortization		2,998,416			2,914,131
TOTAL - NET		3,554,766			3,312,599

OTHER NONCURRENT ASSETS
Regulatory Assets		246,435			314,805
Spent Nuclear Fuel and Decommissioning Trusts		1,346,798			1,248,319
Long-term Risk Management Assets		41,668			59,137
Deferred Charges and Other		128,623			109,453
TOTAL		1,763,524			1,731,714

TOTAL ASSETS	$	5,750,703		$	5,546,437

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

December 31, 2007 and 2006

	2007			2006
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	45,064		$	91,173
Accounts Payable:
General		184,435			146,733
Affiliated Companies		61,749			65,497
Long-term Debt Due Within One Year – Nonaffiliated		145,000			50,000
Risk Management Liabilities		29,078			52,083
Customer Deposits		28,855			34,946
Accrued Taxes		60,995			59,652
Obligations Under Capital Leases		43,382			15,983
Other		130,232			112,478
TOTAL		728,790			628,545

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		1,422,427			1,505,135
Long-term Risk Management Liabilities		26,382			42,641
Deferred Income Taxes		321,716			335,000
Regulatory Liabilities and Deferred Investment Tax Credits		789,346			753,402
Asset Retirement Obligations		852,646			809,853
Deferred Credits and Other		215,617			174,340
TOTAL		3,628,134			3,620,371

TOTAL LIABILITIES		4,356,924			4,248,916

Cumulative Preferred Stock Not Subject to Mandatory Redemption		8,080			8,082

Commitments and Contingencies (Note 6)

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		861,291			861,290
Retained Earnings		483,499			386,616
Accumulated Other Comprehensive Income (Loss)		(15,675	)		(15,051	)
TOTAL		1,385,699			1,289,439

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	5,750,703		$	5,546,437

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	2007			2006			2005
OPERATING ACTIVITIES
Net Income	$	136,895		$	121,168		$	146,852
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		176,611			208,633			196,037
Deferred Income Taxes		4,177			13,626			26,873
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net		12,974			(23,893	)		21,273
Allowance for Equity Funds Used During Construction		(4,522	)		(7,937	)		(4,457	)
Mark-to-Market of Risk Management Contracts		8,130			(2,059	)		(7,331	)
Amortization of Nuclear Fuel		65,166			50,313			56,038
Pension Contributions to Qualified Plan Trusts		-			-			(90,668	)
Change in Other Noncurrent Assets		(4,211	)		12,746			17,447
Change in Other Noncurrent Liabilities		60,720			26,822			22,288
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		6,427			(2,154	)		(785	)
Fuel, Materials and Supplies		2,736			(50,689	)		(13,373	)
Accounts Payable		(31,547	)		37,651			9,630
Customer Deposits		(6,091	)		(14,312	)		19,892
Accrued Taxes, Net		28,815			27,553			(118,438	)
Other Current Assets		2,173			16,208			(14,608	)
Other Current Liabilities		(4,455	)		11,951			25,476
Net Cash Flows from Operating Activities		453,998			425,627			292,146

INVESTING ACTIVITIES
Construction Expenditures		(294,687	)		(325,390	)		(298,632	)
Change in Advances to Affiliates, Net		-			-			5,093
Purchases of Investment Securities		(776,844	)		(691,956	)		(606,936	)
Sales of Investment Securities		695,918			630,555			556,667
Acquisitions of Nuclear Fuel		(74,304	)		(89,100	)		(52,579	)
Other		2,854			6,458			16,794
Net Cash Flows Used for Investing Activities		(447,063	)		(469,433	)		(379,593	)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated		-			443,743			123,761
Change in Advances from Affiliates, Net		(46,109	)		(2,529	)		93,702
Retirement of Long-term Debt – Nonaffiliated		-			(350,000	)		-
Retirement of Cumulative Preferred Stock		(2	)		(1	)		(61,445	)
Proceeds from Nuclear Fuel Sale/Leaseback		85,000			-			-
Principal Payments for Capital Lease Obligations		(5,715	)		(6,553	)		(5,889	)
Dividends Paid on Common Stock		(40,000	)		(40,000	)		(62,000	)
Dividends Paid on Cumulative Preferred Stock		(339	)		(339	)		(339	)
Net Cash Flows from (Used for) Financing Activities		(7,165	)		44,321			87,790

Net Increase (Decrease) in Cash and Cash Equivalents		(230	)		515			343
Cash and Cash Equivalents at Beginning of Period		1,369			854			511
Cash and Cash Equivalents at End of Period	$	1,139		$	1,369		$	854

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	69,841		$	84,354		$	59,339
Net Cash Paid for Income Taxes		37,803			56,506			184,061
Noncash Acquisitions Under Capital Leases		93,590			5,968			2,639
Construction Expenditures Included in Accounts Payable at December 31,		28,642			37,287			38,523
Acquisition of Nuclear Fuel Included in Accounts Payable at December 31,		83,918			210			24,053

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

	Footnote Reference

Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Change	Note 2
Rate Matters	Note 4
Effects of Regulation	Note 5
Commitments, Guarantees and Contingencies	Note 6
Company-wide Staffing and Budget Review	Note 7
Benefit Plans	Note 9
Nuclear	Note 10
Business Segments	Note 11
Derivatives, Hedging and Financial Instruments	Note 12
Income Taxes	Note 13
Leases	Note 14
Financing Activities	Note 15
Related Party Transactions	Note 16
Property, Plant and Equipment	Note 17
Unaudited Quarterly Financial Information	Note 18

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders 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, 2007 and 2006, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2007. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2008

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.

I&M’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control- Integrated Framework. Based on our assessment, the Company’s internal control over financial reporting was effective as of December 31, 2007.

OHIO POWER COMPANY CONSOLIDATED

SELECTED CONSOLIDATED FINANCIAL DATA

(in thousands)

	2007		2006		2005			2004		2003
STATEMENTS OF INCOME DATA
Total Revenues	$	2,814,212	$	2,724,875	$	2,634,549		$	2,372,725	$	2,250,132

Operating Income	$	526,352	$	425,291	$	425,487		$	419,539	$	491,844

Income Before Cumulative Effect of Accounting Changes	$	268,564	$	228,643	$	250,419		$	210,116	$	251,031
Cumulative Effect of Accounting Changes, Net of Tax		-		-		(4,575	)		-		124,632	(a)
Net Income	$	268,564	$	228,643	$	245,844		$	210,116	$	375,663

BALANCE SHEETS DATA
Property, Plant and Equipment	$	9,140,357	$	8,405,645	$	7,523,288		$	6,858,771	$	6,575,577
Accumulated Depreciation and Amortization		2,967,285		2,836,584		2,738,899			2,633,203		2,500,918
Net Property, Plant and Equipment	$	6,173,072	$	5,569,061	$	4,784,389		$	4,225,568	$	4,074,659

Total Assets	$	7,343,663	$	6,818,733	$	6,330,670		$	5,593,265	$	5,374,518

Common Shareholder’s Equity	$	2,291,017	$	2,008,342	$	1,767,947		$	1,473,838	$	1,464,025

Cumulative Preferred Stock Not Subject to Mandatory Redemption	$	16,627	$	16,630	$	16,639		$	16,641	$	16,645

Cumulative Preferred Stock Subject to Mandatory Redemption	$	-	$	-	$	-		$	5,000	$	7,250

Long-term Debt (b)	$	2,849,598	$	2,401,741	$	2,199,670		$	2,011,060	$	2,039,940

Obligations Under Capital Leases (b)	$	29,077	$	34,966	$	39,924		$	40,733	$	34,688

(a)	Cumulative Effect of Accounting Changes, Net of Tax for 2003 reflects the adoption of SFAS 143 as it applies to nonregulated assets.
(b)	Including portion due within one year.

OHIO POWER COMPANY CONSOLIDATED

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

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 712,000 retail customers in the northwestern, east central, eastern and southern sections of Ohio. OPCo consolidates JMG Funding LP, a variable interest entity. As a member of the AEP Power Pool, OPCo shares in the revenues and the costs of the AEP Power Pool’s sales to neighboring utilities and power marketers.

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 existing power pool 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, over-the-counter 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.

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

Results of Operations

2007 Compared to 2006

Reconciliation of Year Ended December 31, 2006 to Year Ended December 31, 2007

Income Before Cumulative Effect of Accounting Change

(in millions)

Year Ended December 31, 2006			$	229

Changes in Gross Margin:
Retail Margins	157
Off-system Sales	(28	)
Transmission Revenues	(3	)
Other	(19	)
Total Change in Gross Margin				107

Changes in Operating Expenses and Other:
Other Operation and Maintenance	13
Depreciation and Amortization	(18	)
Taxes Other Than Income Taxes	(1	)
Other Income	(1	)
Interest Expense	(30	)
Total Change in Operating Expenses and Other				(37	)

Income Tax Expense				(30	)

Year Ended December 31, 2007			$	269

Income Before Cumulative Effect of Accounting Change increased $40 million to $269 million in 2007. The key driver of the increase was a $107 million increase in Gross Margin partially offset by a $37 million increase in Operating Expenses and Other and a $30 million increase in Income Tax Expense.

·	Retail Margins increased $157 million primarily due to the following:
	·	A $44 million increase in capacity settlements under the Interconnection Agreement related to certain affiliates’ peaks and the June 2006 expiration of OPCo’s supplemental capacity and energy obligation to Buckeye Power, Inc. under the Cardinal Station Agreement.
	·	A $40 million increase in rate revenues primarily related to a $36 million increase in OPCo’s RSP and a $6 million increase related to rate recovery of storm costs. See “Ohio Rate Matters” section of Note 4. The increase in rate recovery of storm costs was offset by the amortization of deferred expenses in Other Operation and Maintenance.
	·	A $43 million increase in industrial revenue due to the addition of Ormet, a major industrial customer, effective January 1, 2007. See “Ormet” section of Note 4.
	·	An $18 million increase in residential and commercial revenue primarily due to a 33% increase in cooling degree days and a 22% increase in heating degree days.
	The increases were partially offset by:
	·	A $23 million decrease due to PJM’s revision of its pricing methodology for transmission line losses to marginal-loss pricing effective June 1, 2007. See “PJM Marginal-Loss Pricing” section of Note 4.
·	Margins from Off-system Sales decreased $28 million primarily due to lower physical sales of which $30 million related to OPCo’s purchase power and sale agreement with Dow Chemical Company (Dow) which ended in November 2006. The decreased physical results were partially offset by higher trading margins. See “Plaquemine Cogeneration Facility” section of “Significant Factors” for additional discussion of Dow.
·	Other revenues decreased $19 million primarily due to an $8 million decrease in gains on sales of emission allowances and a $7 million decrease related to the April 2006 expiration of an obligation to sell supplemental capacity and energy to Buckeye Power, Inc. under the Cardinal Station Agreement.

Operating Expenses and Other and Income Taxes changed between years as follows:

·	Other Operation and Maintenance expenses decreased $13 million primarily due to the following:
	·	A $30 million decrease in maintenance and rental expenses related to OPCo’s purchase power and sale agreement with Dow which ended in November 2006. This decrease was offset by a corresponding decrease in margins from Off-system Sales. See “Plaquemine Cogeneration Facility” section of “Significant Factors” for additional discussion of Dow.
	·	A $15 million decrease in maintenance from planned and forced outages at the Gavin, Kammer, Mitchell and Muskingum River Plants related to boiler tube inspections in 2006.
	These decreases were partially offset by:
	·	A $17 million increase due to the settlement agreement regarding alleged violations of the NSR provisions of the CAA. See “Federal EPA Complaint and Notice of Violation” section of Note 6.
	·	A $10 million increase due to adjustments in 2006 of liabilities related to sold coal companies.
	·	A $7 million increase in overhead line expenses primarily due to the 2006 recognition of a regulatory asset related to PUCO orders regarding distribution service reliability and restoration costs and the amortization of deferred storm expenses recovered through a cost-recovery rider. The increase in the amortization of deferred storm expenses was offset by a corresponding increase in Retail Margins.
·	Depreciation and Amortization increased $18 million primarily due to a $25 million increase in depreciation related to environmental improvements placed in service at the Mitchell Plant. These increases were partially offset by a $7 million decrease from the amortization of a regulatory liability related to Ormet. See “Ormet” section of Note 4.
·	Interest Expense increased $30 million primarily due to increases in long-term borrowings.
·	Income Tax Expense increased $30 million primarily due to an increase in pretax book income and state income taxes.

2006 Compared to 2005

Reconciliation of Year Ended December 31, 2005 to Year Ended December 31, 2006

Income Before Cumulative Effect of Accounting Change

(in millions)

Year Ended December 31, 2005			$	250

Changes in Gross Margin:
Retail Margins	59
Off-system Sales	55
Transmission Revenues	(32	)
Other	3
Total Change in Gross Margin				85

Changes in Operating Expenses and Other:
Other Operation and Maintenance	(63	)
Depreciation and Amortization	(19	)
Taxes Other Than Income Taxes	(2	)
Carrying Costs Income	(35	)
Interest Expense	6
Total Change in Operating Expenses and Other				(113	)

Income Tax Expense				7

Year Ended December 31, 2006			$	229

Income Before Cumulative Effect of Accounting Change decreased $21 million to $229 million in 2006. The key driver of the decrease was a $113 million increase in Operating Expenses and Other partially offset by an $85 million increase in Gross Margin.

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

·	Retail Margins increased $59 million primarily due to the following:
	·	A $120 million increase related to the RSP rate increase effective January 1, 2006.
	·	A $20 million increase in capacity settlements under the Interconnection Agreement related to an increase in an affiliate’s peak.
	·	An $11 million decrease in allowance expenses driven by a decrease in the average unit price of allowances.
	·	A $6 million decrease in consumables primarily due to a decrease in commodity prices.
	These increases were partially offset by:
	·	An $87 million decrease related to a decrease in fuel margins primarily due to higher fuel costs and a decrease in industrial revenue due to the transfer of a significant customer to an affiliate.
	·	An $8 million decrease in revenues associated with SO2 allowances received from Buckeye Power, Inc. under the Cardinal Station Allowance Agreement.
·	Margins from Off-system Sales increased $55 million primarily due to an increase in physical sales margins and a $20 million increase in OPCo’s allocation of off-system sales margins under the SIA. These increases were partially offset by a decrease in margins from optimization activities. The change in allocation methodology of the SIA occurred on April 1, 2006. Margins from Off-system Sales also increased as a result of decreased fuel costs and favorable optimization activities related to OPCo’s purchase power and sale agreement with the Dow Chemical Company (Dow). This increase in margin related to Dow was offset by a corresponding increase in Other Operation and Maintenance expenses. See “Plaquemine Cogeneration Facility” section of “Significant Factors” for additional discussion of Dow.
·	Transmission Revenues decreased $32 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $8 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors.

Operating Expenses and Other and Income Taxes changed between years as follows:

·	Other Operation and Maintenance expenses increased $63 million primarily due to the following:
	·	A $30 million increase in maintenance from planned and forced outages at the Gavin, Muskingum River, Kammer and Sporn Plants related to major boiler and turbine overhauls and boiler tube inspections.
	·	A $21 million unfavorable variance due to increased maintenance costs and increased rental expense related to the purchase power and sale agreement with Dow. These increases in Other Operation and Maintenance expenses, which includes an indemnification adjustment related to the purchase power and sale agreement with Dow were offset by a corresponding increase in margins from Off-system Sales. See “Plaquemine Cogeneration Facility” section of “Significant Factors” for additional discussion of Dow.
	·	An $8 million increase in removal costs related to maintenance.
	These increases were partially offset by:
	·	A $10 million variance due to the reduction of liabilities related to sold coal companies.
·	Depreciation and Amortization increased $19 million primarily due to a $17 million increase in amortization of regulatory assets partially offset by the 2005 establishment of a $7 million regulatory liability to benefit low-income customers and for economic development, as ordered in OPCo’s RSP. In addition, an $8 million increase in depreciation is attributable to a higher depreciable base in electric utility assets.
·	Carrying Costs Income decreased $35 million primarily due to the completion of deferrals of the environmental carrying costs from 2004 and 2005 that are now being recovered during 2006 through 2008 according to the RSP.
·	Interest Expense decreased $6 million primarily due to a $26 million increase in AFUDC partially offset by a $17 million increase in interest due to long-term debt issuances since November 2005.
·	Income Tax Expense decreased $7 million primarily due to a decrease in pretax book income and state income taxes offset in part by tax return and tax reserve adjustments and changes in certain book/tax differences accounted for on a flow-through basis.

Financial Condition

Credit Ratings

S&P and Fitch currently have OPCo on stable outlook, while Moody’s placed OPCo on negative outlook in January 2008. Current ratings are as follows:

	Moody’s	S&P	Fitch

Senior Unsecured Debt	A3	BBB	BBB+

Cash Flow

Cash flows for 2007, 2006 and 2005 were as follows:

	Years Ended December 31,
	2007			2006			2005
	(in thousands)

Cash and Cash Equivalents at Beginning of Period	$	1,625		$	1,240		$	9,337
Cash Flows from (Used for):
Operating Activities		572,995			626,246			368,805
Investing Activities		(923,981	)		(986,095	)		(571,184	)
Financing Activities		356,027			360,234			194,282
Net Increase (Decrease) in Cash and Cash Equivalents		5,041			385			(8,097	)
Cash and Cash Equivalents at End of Period	$	6,666		$	1,625		$	1,240

Operating Activities

Net Cash Flows from Operating Activities were $573 million in 2007. OPCo produced Net Income of $269 million during the period and a noncash expense item of $340 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items, including a $55 million outflow in Accounts Receivable, Net. Accounts Receivable, Net increased primarily due to an increase in heating degree days and timing differences of payments from customers.

Net Cash Flows from Operating Activities were $626 million in 2006. OPCo produced Net Income of $229 million during the period and a noncash expense item of $322 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items, including a $116 million inflow in Accounts Receivable, Net. Accounts Receivable, Net decreased due to the collection of receivables related to power sales to affiliates, settled litigation and emission allowances.

Net Cash Flows from Operating Activities were $369 million in 2005. OPCo produced Net Income of $246 million during the period and a noncash expense item of $302 million for Depreciation and Amortization. OPCo made contributions of $132 million to their pension trust fund. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items including a $114 million outflow in Accrued Taxes, Net. During 2005, OPCo made federal income tax payments of $198 million.

Investing Activities

Net Cash Flows Used for Investing Activities in 2007, 2006 and 2005 were $924 million, $986 million and $571 million, respectively, primarily due to Construction Expenditures for environmental upgrades, as well as projects to improve service reliability for transmission and distribution. Environmental upgrades include the installation of selective catalytic reduction equipment and flue gas desulfurization projects at the Cardinal, Amos and Mitchell Plants. In January 2007, environmental upgrades were completed for Unit 1 and 2 at the Mitchell Plant.

Financing Activities

Net Cash Flows from Financing Activities were $356 million in 2007. OPCo issued $400 million of Senior Unsecured Notes and $65 million of Pollution Control Bonds. OPCo reduced borrowings by $80 million from the Utility Money Pool.

Net Cash Flows from Financing Activities were $360 million in 2006. OPCo issued $350 million of Senior Unsecured Notes and $65 million of Pollution Control Bonds. OPCo received a capital contribution from Parent of $70 million. These amounts were partially offset by a $200 million retirement of affiliated notes payable.

Net Cash Flows from Financing Activities were $194 million in 2005. OPCo issued $353 million of Pollution Control Bonds and $200 million of Senior Unsecured Notes. These amounts were partially offset by a $353 million retirement of Pollution Control Bonds.

Summary Obligation Information

OPCo’s contractual obligations include amounts reported on OPCo’s Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes OPCo’s contractual cash obligations at December 31, 2007:

Payment Due by Period

(in millions)

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Advances from Affiliates (a)	$	101.5	$	-	$	-	$	-	$	101.5
Short-term Debt (b)		0.7		-		-		-		0.7
Interest on Fixed Rate Portion of Long- term Debt (c)		114.7		214.0		189.9		897.8		1,416.4
Fixed Rate Portion of Long-term Debt (d)		55.2		277.5		-		1,654.1		1,986.8
Variable Rate Portion of Long-term Debt (e)		-		400.0		-		468.0		868.0
Capital Lease Obligations (f)		7.5		9.9		3.7		19.3		40.4
Noncancelable Operating Leases (f)		25.3		46.3		38.5		92.4		202.5
Fuel Purchase Contracts (g)		787.4		1,256.2		1,010.6		2,852.0		5,906.2
Energy and Capacity Purchase Contracts (h)		-		4.2		3.7		-		7.9
Construction Contracts for Capital Assets (i)		122.3		179.1		118.0		23.7		443.1
Total	$	1,214.6	$	2,387.2	$	1,364.4	$	6,007.3	$	10,973.5

(a)	Represents short-term borrowing from the Utility Money Pool.
(b)	Represents principal only excluding interest.
(c)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2007 and do not reflect anticipated future refinancings, early redemptions or debt issuances.
(d)	See Note 15. Represents principal only excluding interest.
(e)	See Note 15. Represents principal only excluding interest. Variable rate debt had interest rates that ranged between 3.70% and 5.80% at December 31, 2007.
(f)	See Note 14.
(g)	Represents contractual obligations to purchase coal and other consumables as fuel for electric generation along with related transportation of the fuel.
(h)	Represents contractual cash flows of energy and capacity purchase contracts.
(i)	Represents only capital assets that are contractual obligations.

OPCo’s FIN 48 liabilities of $24 million are not included above because OPCo cannot reasonably estimate the cash flows by period.

As discussed in Note 9, OPCo’s minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trust.

In addition to the amounts disclosed in the contractual cash obligations table above, OPCo makes additional commitments in the normal course of business. OPCo’s commitments outstanding at December 31, 2007 under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period

(in millions)

Other Commercial Commitments			Less Than 1 year			2-3 years			4-5 years			After 5 years			Total
Guarantees of OPCo’s Performance (a)			$	-		$	-		$	-		$	50.0		$	50.0

(a)	OPCo issued performance guarantees for energy trading.

Other

Coal Contract Amendment

In January 2008, OPCo terminated a coal contract for deliveries of coal through 2012 and additional optional tonnage through 2017. The contracted prices were below current market prices. OPCo also entered into a new contract for reduced deliveries of comparable coal for 2009-2010, with an option for tonnage with firm pricing in 2011. Consideration received by OPCo for the significant tonnage reduction consisted of noncash consideration of approximately $70 million. A significant portion of the consideration will be recognized in 2008 as a decrease to fuel expense. The remaining amount will be amortized to fuel expense as coal is delivered under the new contract in 2009-2010.

Significant Factors

Plaquemine Cogeneration Facility

In 2000, Juniper Capital L.P. financed AEP’s nonregulated ownership interest in the Plaquemine Cogeneration Facility (the Facility) near Plaquemine, Louisiana. AEP subleased the Facility to Dow Chemical Company (Dow). As outlined in the “OPCo Indemnification Agreement with AEP Resources” section of Note 16, OPCo entered into a purchase power and sale agreement with Dow and a corresponding indemnification agreement with a nonutility subsidiary of AEP. As a result, OPCo’s results of operations included sales to nonaffiliated companies and offsetting maintenance expense with no effect on OPCo’s Net Income. In the fourth quarter of 2006, AEP sold the Facility to Dow. With the sale of the Facility, OPCo terminated its purchase power and sale agreement with Dow. This sale did not have an impact on OPCo’s 2006 results of operations. In 2006, the operation of the facility affected revenues, Fuel and Other Consumables Used for Electric Generation, Purchased Electricity for Resale, Other Operation expense and Maintenance expense by approximately $157 million, $134 million, ($7) million, $19 million and $11 million, respectively, with no effect on net income. These revenues and expenses did not recur in 2007.

Litigation and Regulatory Activity

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 state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrue a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to materially affect OPCo’s results of operations, financial condition and cash flows.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of relevant factors.

Critical Accounting Estimates

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in OPCo’s Consolidated Balance Sheet as of December 31, 2007 and the reasons for changes in total MTM value as compared to December 31, 2006.

Reconciliation of MTM Risk Management Contracts to

Consolidated Balance Sheet

December 31, 2007

(in thousands)

	MTM Risk Management Contracts			Cash Flow Hedges			DETM Assignment (a)			Total
Current Assets	$	44,856		$	634		$	-		$	45,490
Noncurrent Assets		51,182			152			-			51,334
Total MTM Derivative Contract Assets		96,038			786			-			96,824

Current Liabilities		(37,159	)		(2,720	)		(2,861	)		(42,740	)
Noncurrent Liabilities		(28,631	)		(91	)		(3,512	)		(32,234	)
Total MTM Derivative Contract Liabilities		(65,790	)		(2,811	)		(6,373	)		(74,974	)

Total MTM Derivative Contract Net Assets (Liabilities)	$	30,248		$	(2,025	)	$	(6,373	)	$	21,850

(a)	See “Natural Gas Contracts with DETM” section of Note 16.

MTM Risk Management Contract Net Assets

Year Ended December 31, 2007

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2006	$	33,042
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		(9,511	)
Fair Value of New Contracts at Inception When Entered During the Period (a)		3,231
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period		340
Changes in Fair Value Due to Market Fluctuations During the Period (b)		3,146
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		-
Total MTM Risk Management Contract Net Assets		30,248
Net Cash Flow Hedge Contracts		(2,025	)
DETM Assignment (d)		(6,373	)
Total MTM Risk Management Contract Net Assets at December 31, 2007	$	21,850

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(d)	See “Natural Gas Contracts with DETM” section of Note 16.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents:

·	The method of measuring fair value used in determining the carrying amount of total MTM asset or liability (external sources or modeled internally).
·	The maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash.

Maturity and Source of Fair Value of MTM

Risk Management Contract Net Assets

Fair Value of Contracts as of December 31, 2007

(in thousands)

	2008			2009		2010		2011		2012		After 2012			Total
Prices Actively Quoted – Exchange Traded Contracts	$	(4,510	)	$	1,557	$	924	$	-	$	-	$	-		$	(2,029	)
Prices Provided by Other External Sources – OTC Broker Quotes (a)		13,598			9,531		6,812		812		-		-			30,753
Prices Based on Models and Other Valuation Methods (b)		(1,391	)		752		179		612		1,373		(1	)		1,524
Total	$	7,697		$	11,840	$	7,915	$	1,424	$	1,373	$	(1	)	$	30,248

(a)	“Prices Provided by Other External Sources – OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)	“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.

	Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Consolidated Balance Sheet

OPCo is exposed to market fluctuations in energy commodity prices impacting power operations. Management monitors these risks on future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. Management does not hedge all commodity price risk.

Management uses interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt. Management does not hedge all interest rate risk.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on OPCo’s Consolidated Balance Sheets and the reasons for the changes from December 31, 2006 to December 31, 2007. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Year Ended December 31, 2007

(in thousands)

	Power			Interest Rate			Foreign Currency			Total
Beginning Balance in AOCI December 31, 2006	$	4,040		$	3,553		$	(331	)	$	7,262
Changes in Fair Value		(976	)		(573	)		64			(1,485	)
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled		(3,820	)		(813	)		13			(4,620	)
Ending Balance in AOCI December 31, 2007	$	(756	)	$	2,167		$	(254	)	$	1,157

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $657 thousand loss.

Credit Risk

Counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

The following table shows the end, high, average, and low market risk as measured by VaR for the years ended:

December 31, 2007				December 31, 2006
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$325	$2,054	$490	$90	$573	$1,451	$500	$271

Management back-tests its VaR results against performance due to actual price moves. Based on the assumed 95% confidence interval, performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days. Management’s backtesting results show that its actual performance exceeded VaR far fewer than once every 20 trading days. As a result, management believes OPCo’s VaR calculation is conservative.

As OPCo’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand its exposure to extreme price moves. Management employs a historically-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translate into the largest potential mark-to-market loss. Management can then research the underlying positions, price moves and market event that created the most significant exposure.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which OPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. For 2008, the estimated EaR on OPCo’s debt portfolio was $3.6 million.

OHIO POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	2007			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	2,019,632		$	2,006,279		$	1,922,280
Sales to AEP Affiliates		757,052			685,343			681,852
Other - Affiliated		22,705			16,775			15,437
Other - Nonaffiliated		14,823			16,478			14,980
TOTAL		2,814,212			2,724,875			2,634,549

EXPENSES
Fuel and Other Consumables Used for Electric Generation		908,317			960,119			975,180
Purchased Electricity for Resale		123,849			100,958			77,173
Purchased Electricity from AEP Affiliates		125,108			113,651			116,890
Other Operation		388,745			382,573			340,085
Maintenance		208,675			228,151			207,226
Depreciation and Amortization		339,817			321,954			302,495
Taxes Other Than Income Taxes		193,349			192,178			190,013
TOTAL		2,287,860			2,299,584			2,209,062

OPERATING INCOME		526,352			425,291			425,487

Other Income (Expense):
Interest Income		1,366			2,363			3,311
Carrying Costs Income		14,472			13,841			48,510
Allowance for Equity Funds Used During Construction		2,311			2,556			1,441
Interest Expense		(127,352	)		(97,084	)		(103,352	)

INCOME BEFORE INCOME TAXES		417,149			346,967			375,397

Income Tax Expense		148,585			118,324			124,978

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		268,564			228,643			250,419

CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX		-			-			(4,575	)

NET INCOME		268,564			228,643			245,844

Preferred Stock Dividend Requirements Including Capital Stock Expense		732			732			906

EARNINGS APPLICABLE TO COMMON STOCK	$	267,832		$	227,911		$	244,938

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

See Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004	$	321,201	$	462,485	$	764,416		$	(74,264	)	$	1,473,838

Common Stock Dividends						(30,000	)					(30,000	)
Preferred Stock Dividends						(732	)					(732	)
Other				4,152		(174	)					3,978
TOTAL												1,447,084

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $262									(486	)		(486	)
Minimum Pension Liability, Net of Tax of $40,657									75,505			75,505
NET INCOME						245,844						245,844
TOTAL COMPREHENSIVE INCOME												320,863

DECEMBER 31, 2005		321,201		466,637		979,354			755			1,767,947

Capital Contribution from Parent				70,000								70,000
Preferred Stock Dividends						(732	)					(732	)
Gain on Reacquired Preferred Stock				2								2
TOTAL												1,837,217

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $3,504									6,507			6,507
Minimum Pension Liability, Net of Tax of $110									(204	)		(204	)
NET INCOME						228,643						228,643
TOTAL COMPREHENSIVE INCOME												234,946
Minimum Pension Liability Elimination, Net of Tax of $110									204			204
SFAS 158 Adoption, Net of Tax of $34,475									(64,025	)		(64,025	)

DECEMBER 31, 2006		321,201		536,639		1,207,265			(56,763	)		2,008,342

FIN 48 Adoption, Net of Tax						(5,380	)					(5,380	)
Preferred Stock Dividends						(732	)					(732	)
Gain on Reacquired Preferred Stock				1								1
TOTAL												2,002,231

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $3,287									(6,105	)		(6,105	)
Pension and OPEB Funded Status, Net of Tax of $14,176									26,327			26,327
NET INCOME						268,564						268,564
TOTAL COMPREHENSIVE INCOME												288,786

DECEMBER 31, 2007	$	321,201	$	536,640	$	1,469,717		$	(36,541	)	$	2,291,017

See Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2007 and 2006

(in thousands)

	2007			2006
CURRENT ASSETS
Cash and Cash Equivalents	$	6,666		$	1,625
Accounts Receivable:
Customers		104,783			86,116
Affiliated Companies		119,560			108,214
Accrued Unbilled Revenues		26,819			10,106
Miscellaneous		1,578			1,819
Allowance for Uncollectible Accounts		(3,396	)		(824	)
Total Accounts Receivable		249,344			205,431
Fuel		92,874			120,441
Materials and Supplies		108,447			84,612
Risk Management Assets		45,490			86,947
Prepayments and Other		20,532			41,941
TOTAL		523,353			540,997

PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		5,641,537			4,413,340
Transmission		1,068,387			1,030,934
Distribution		1,394,988			1,322,103
Other		318,805			299,637
Construction Work in Progress		716,640			1,339,631
Total		9,140,357			8,405,645
Accumulated Depreciation and Amortization		2,967,285			2,836,584
TOTAL - NET		6,173,072			5,569,061

OTHER NONCURRENT ASSETS
Regulatory Assets		323,105			414,180
Long-term Risk Management Assets		51,334			70,092
Deferred Charges and Other		272,799			224,403
TOTAL		647,238			708,675

TOTAL ASSETS	$	7,343,663		$	6,818,733

See Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

December 31, 2007 and 2006

	2007			2006
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	101,548		$	181,281
Accounts Payable:
General		141,196			250,025
Affiliated Companies		137,389			145,197
Short-term Debt – Nonaffiliated		701			1,203
Long-term Debt Due Within One Year – Nonaffiliated		55,188			17,854
Risk Management Liabilities		42,740			73,386
Customer Deposits		33,615			31,465
Accrued Taxes		185,011			165,338
Accrued Interest		41,880			35,497
Other		149,658			123,631
TOTAL		888,926			1,024,877

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		2,594,410			2,183,887
Long-term Debt – Affiliated		200,000			200,000
Long-term Risk Management Liabilities		32,234			52,929
Deferred Income Taxes		914,170			911,221
Regulatory Liabilities and Deferred Investment Tax Credits		160,721			185,895
Deferred Credits and Other		229,635			219,127
TOTAL		4,131,170			3,753,059

TOTAL LIABILITIES		5,020,096			4,777,936

Minority Interest		15,923			15,825

Cumulative Preferred Stock Not Subject to Mandatory Redemption		16,627			16,630

Commitments and Contingencies (Note 6)

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		536,640			536,639
Retained Earnings		1,469,717			1,207,265
Accumulated Other Comprehensive Income (Loss)		(36,541	)		(56,763	)
TOTAL		2,291,017			2,008,342

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	7,343,663		$	6,818,733

See Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	2007			2006			2005
OPERATING ACTIVITIES
Net Income	$	268,564		$	228,643		$	245,844
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		339,817			321,954			302,495
Deferred Income Taxes		16,238			(43,997	)		59,593
Cumulative Effect of Accounting Change, Net of Tax		-			-			4,575
Carrying Costs Income		(14,472	)		(13,841	)		(48,510	)
Allowance for Equity Funds Used During Construction		(2,311	)		(2,556	)		(1,441	)
Mark-to-Market of Risk Management Contracts		664			6,545			(2,372	)
Pension Contributions to Qualified Plan Trusts		-			-			(132,496	)
Change in Other Noncurrent Assets		(39,513	)		1,821			7,247
Change in Other Noncurrent Liabilities		783			10,126			(15,180	)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		(54,730	)		116,496			(60,627	)
Fuel, Materials and Supplies		17,845			(21,914	)		(34,880	)
Accounts Payable		(19,536	)		(14,114	)		56,403
Customer Deposits		2,150			(19,744	)		28,589
Accrued Taxes, Net		41,623			23,620			(114,217	)
Other Current Assets		(1,798	)		24,862			46,737
Other Current Liabilities		17,671			8,345			27,045
Net Cash Flows from Operating Activities		572,995			626,246			368,805

INVESTING ACTIVITIES
Construction Expenditures		(933,162	)		(999,603	)		(710,536	)
Change in Advances to Affiliates, Net		-			-			125,971
Proceeds from Sales of Assets		9,023			15,443			13,410
Other		158			(1,935	)		(29	)
Net Cash Flows Used for Investing Activities		(923,981	)		(986,095	)		(571,184	)

FINANCING ACTIVITIES
Capital Contribution from Parent		-			70,000			-
Issuance of Long-term Debt – Nonaffiliated		461,912			408,710			545,746
Change in Short-term Debt, Net – Nonaffiliated		(502	)		(9,163	)		(13,132	)
Change in Advances from Affiliates, Net		(79,733	)		111,210			70,071
Retirement of Long-term Debt – Nonaffiliated		(17,854	)		(12,354	)		(365,354	)
Retirement of Long-term Debt – Affiliated		-			(200,000	)		-
Retirement of Cumulative Preferred Stock		(2	)		(7	)		(5,000	)
Principal Payments for Capital Lease Obligations		(7,062	)		(7,430	)		(7,317	)
Dividends Paid on Common Stock		-			-			(30,000	)
Dividends Paid on Cumulative Preferred Stock		(732	)		(732	)		(732	)
Net Cash Flows from Financing Activities		356,027			360,234			194,282

Net Increase (Decrease) in Cash and Cash Equivalents		5,041			385			(8,097	)
Cash and Cash Equivalents at Beginning of Period		1,625			1,240			9,337
Cash and Cash Equivalents at End of Period	$	6,666		$	1,625		$	1,240

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	122,591		$	94,051		$	102,656
Net Cash Paid for Income Taxes		110,197			142,895			198,078
Noncash Acquisitions Under Capital Leases		2,058			3,288			9,218
Construction Expenditures Included in Accounts Payable at December 31,		39,678			125,962			74,848

See Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

INDEX TO 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.

	Footnote Reference

Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Change	Note 2
Rate Matters	Note 4
Effects of Regulation	Note 5
Commitments, Guarantees and Contingencies	Note 6
Company-wide Staffing and Budget Review	Note 7
Benefit Plans	Note 9
Business Segments	Note 11
Derivatives, Hedging and Financial Instruments	Note 12
Income Taxes	Note 13
Leases	Note 14
Financing Activities	Note 15
Related Party Transactions	Note 16
Property, Plant and Equipment	Note 17
Unaudited Quarterly Financial Information	Note 18

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Ohio Power Company:

We have audited the accompanying consolidated balance sheets of Ohio Power Company Consolidated (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2007. 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 Consolidated as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”, effective January 1, 2007. As discussed in Note 9 to the consolidated financial statements, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006. As discussed in Note 17 to the consolidated financial statements, the Company adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” effective December 31, 2005.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2008

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Ohio Power Company Consolidated (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.

OPCo’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control- Integrated Framework. Based on our assessment, the Company’s internal control over financial reporting was effective as of December 31, 2007.

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

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 525,000 retail customers in its service territory in eastern and southwestern Oklahoma. As a member of the CSW Operating Agreement with SWEPCo, PSO shares in the revenues and expenses of the members’ sales to neighboring utilities and power marketers. PSO also sells electric power at wholesale to other utilities, municipalities and electric cooperatives.

Effective May 1, 2006, the FERC approved the removal of TCC and TNC from the CSW Operating Agreement. Under the Texas Restructuring Legislation, TCC and TNC completed the final stage of exiting the generation business and ceased serving retail load. TCC and TNC are no longer involved in the coordinated planning and operation of power supply facilities or share trading and marketing margins, as contemplated by both the CSW Operating Agreement and the SIA. Consequently, PSO’s proportionate share of trading and marketing margins increased, although the level of margins depends upon future market conditions. PSO shares these margins with its customers.

Members of the CSW Operating Agreement are 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, over-the-counter 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.

Effective January 1, 2007, PSO locked in margins on its ERCOT trading and marketing contracts and transferred commodity price risk to AEP Energy Partners, LP (AEPEP), a wholly-owned subsidiary of AEP. This was achieved by a combination of transferring certain existing ERCOT energy marketing contracts to AEPEP and entering into financial and physical purchase and sale agreements with AEPEP. PSO will not be a party to new contracts in ERCOT. As the contracts mature, PSO will realize the fixed margin on the portfolio of ERCOT contracts as it existed on December 31, 2006 and will not be exposed to commodity price risk and resulting earnings variations for these contracts.

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

Results of Operations

2007 Compared to 2006

Reconciliation of Year Ended December 31, 2006 to December 31, 2007

Net Income (Loss)

(in millions)

Year Ended December 31, 2006			$	37

Changes in Gross Margin:
Retail and Off-system Sales Margins	25
Transmission Revenues	2
Other	(5	)
Total Change in Gross Margin				22

Changes in Operating Expenses and Other:
Other Operation and Maintenance	(106	)
Depreciation and Amortization	(4	)
Taxes Other Than Income Taxes	(8	)
Other Income	3
Interest Expense	(6	)
Total Change in Operating Expenses and Other				(121	)

Income Tax Expense				38

Year Ended December 31, 2007			$	(24	)

Net Income (Loss) decreased $61 million in 2007. The key drivers of the decrease were a $121 million increase in Operating Expenses and Other, partially offset by a $22 million increase in Gross Margin and a $38 million decrease in Income Tax Expense.

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 power were as follows:

·	Retail and Off-system Sales Margins increased $25 million primarily due to:
	·	A $19 million increase in retail sales margins mainly due to base rate adjustments during the year.
	·	An $8 million increase in off-system margins retained from a net increase of $21 million from higher trading margins and decreased physical sales.
·	Other revenues decreased $5 million primarily due to a $2 million decrease in rental and pole attachment income and a $1 million decrease in gains on sales of emission allowances.

Operating Expenses and Other and Income Taxes changed between years as follows:

·	Other Operation and Maintenance expenses increased $106 million primarily due to:
	·	An $86 million increase in distribution expense resulting primarily from the ice storms in January and December 2007. See “Oklahoma 2007 Ice Storms” section of Note 4.
	·	An $11 million increase in generation expenses primarily due to scheduled maintenance outages.
	·	A $7 million increase in transmission expense primarily due to a $4 million increase in transmission services from other utilities and a $3 million increase in SPP charges and fees.
·	Depreciation and Amortization increased $4 million primarily due to the amortization of regulatory assets related to the Lawton settlement. See “Lawton and Peaking Generation Settlement Agreement” section of Note 4.
·	Taxes Other Than Income Taxes increased $8 million primarily due to a sales and use tax adjustment recorded in 2006.
·	Other Income increased $3 million primarily due to higher carrying charges on recovery of regulatory assets related to the Lawton Settlement. See “Lawton and Peaking Generation Settlement Agreement” section of Note 4.
·	Interest Expense increased $6 million primarily due to increased borrowings in support of capital spending.
·	Income Tax Expense decreased $38 million primarily due to a decrease in pretax book income and the recording of state income tax adjustments.

Critical Accounting Estimates

Adoption of New Accounting Pronouncement

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Risk management assets and liabilities are managed by AEPSC as agent. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which PSO’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. For 2008, the estimated EaR on PSO’s debt portfolio was $0.2 million.

PUBLIC SERVICE COMPANY OF OKLAHOMA

STATEMENTS OF OPERATIONS

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	2007			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	1,321,919		$	1,384,549		$	1,261,424
Sales to AEP Affiliates		69,106			51,993			39,678
Other		4,525			5,242			2,976
TOTAL		1,395,550			1,441,784			1,304,078

EXPENSES
Fuel and Other Consumables Used for Electric Generation		590,053			703,252			619,657
Purchased Electricity for Resale		246,928			199,094			116,345
Purchased Electricity from AEP Affiliates		66,324			69,406			105,361
Other Operation		179,700			170,201			156,451
Maintenance		185,554			88,676			67,077
Depreciation and Amortization		91,611			87,543			86,762
Taxes Other Than Income Taxes		40,215			32,619			34,409
TOTAL		1,400,385			1,350,791			1,186,062

OPERATING INCOME (LOSS)		(4,835	)		90,993			118,016

Other Income (Expense):
Interest Income		3,889			1,917			3,591
Allowance for Equity Funds Used During Construction		1,367			715			865
Interest Expense		(46,560	)		(40,778	)		(34,094	)

INCOME (LOSS) BEFORE INCOME TAXES		(46,139	)		52,847			88,378

Income Tax Expense (Credit)		(22,015	)		15,987			30,485

NET INCOME (LOSS)		(24,124	)		36,860			57,893

Preferred Stock Dividend Requirements		213			213			213

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK	$	(24,337	)	$	36,647		$	57,680

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

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004	$	157,230	$	230,016	$	141,935		$	75		$	529,256

Common Stock Dividends						(37,000	)					(37,000	)
Preferred Stock Dividends						(213	)					(213	)
TOTAL												492,043

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $814									(1,512	)		(1,512	)
Minimum Pension Liability, Net of Tax of $93									173			173
NET INCOME						57,893						57,893
TOTAL COMPREHENSIVE INCOME												56,554

DECEMBER 31, 2005		157,230		230,016		162,615			(1,264	)		548,597

Preferred Stock Dividends						(213	)					(213	)
TOTAL												548,384

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $22									42			42
Minimum Pension Liability, Net of Tax of $14									25			25
NET INCOME						36,860						36,860
TOTAL COMPREHENSIVE INCOME												36,927
Minimum Pension Liability Elimination, Net of Tax of $68									127			127

DECEMBER 31, 2006		157,230		230,016		199,262			(1,070	)		585,438

FIN 48 Adoption, Net of Tax						(386	)					(386	)
Capital Contribution from Parent				80,000								80,000
Preferred Stock Dividends						(213	)					(213	)
TOTAL												664,839

COMPREHENSIVE LOSS
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $99									183			183
NET LOSS						(24,124	)					(24,124	)
TOTAL COMPREHENSIVE LOSS												(23,941	)

DECEMBER 31, 2007	$	157,230	$	310,016	$	174,539		$	(887	)	$	640,898

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

BALANCE SHEETS

ASSETS

December 31, 2007 and 2006

(in thousands)

	2007		2006
CURRENT ASSETS
Cash and Cash Equivalents	$	1,370	$	1,651
Advances to Affiliates		51,202		-
Accounts Receivable:
Customers		74,330		70,319
Affiliated Companies		59,835		73,318
Miscellaneous		10,315		10,270
Allowance for Uncollectible Accounts		-		(5	)
Total Accounts Receivable		144,480		153,902
Fuel		19,394		20,082
Materials and Supplies		47,691		48,375
Risk Management Assets		33,338		100,802
Accrued Tax Benefits		31,756		4,679
Regulatory Asset for Under-Recovered Fuel Costs		-		7,557
Margin Deposits		9,119		35,270
Prepayments and Other		18,137		5,732
TOTAL		356,487		378,050

PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		1,110,657		1,091,910
Transmission		569,746		503,638
Distribution		1,337,038		1,215,236
Other		241,722		234,227
Construction Work in Progress		200,018		141,283
Total		3,459,181		3,186,294
Accumulated Depreciation and Amortization		1,182,171		1,187,107
TOTAL - NET		2,277,010		1,999,187

OTHER NONCURRENT ASSETS
Regulatory Assets		158,731		142,905
Long-term Risk Management Assets		3,376		17,066
Deferred Charges and Other		48,454		41,838
TOTAL		210,561		201,809

TOTAL ASSETS	$	2,844,058	$	2,579,046

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

December 31, 2007 and 2006

	2007			2006
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	-		$	76,323
Accounts Payable:
General		189,032			165,618
Affiliated Companies		80,316			65,134
Risk Management Liabilities		27,151			88,469
Customer Deposits		41,525			51,335
Accrued Taxes		18,374			19,984
Regulatory Liability for Over-Recovered Fuel Costs		11,697			-
Other		57,708			58,651
TOTAL		425,803			525,514

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		918,316			669,998
Long-term Risk Management Liabilities		2,914			11,448
Deferred Income Taxes		456,497			414,197
Regulatory Liabilities and Deferred Investment Tax Credits		338,788			315,584
Deferred Credits and Other		55,580			51,605
TOTAL		1,772,095			1,462,832

TOTAL LIABILITIES		2,197,898			1,988,346

Cumulative Preferred Stock Not Subject to Mandatory Redemption		5,262			5,262

Commitments and Contingencies (Note 6)

COMMON SHAREHOLDER’S EQUITY
Common Stock – $15 Par Value Per Share:
Authorized – 11,000,000 Shares
Issued – 10,482,000 Shares
Outstanding – 9,013,000 Shares		157,230			157,230
Paid-in Capital		310,016			230,016
Retained Earnings		174,539			199,262
Accumulated Other Comprehensive Income (Loss)		(887	)		(1,070	)
TOTAL		640,898			585,438

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	2,844,058		$	2,579,046

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	2007			2006			2005
OPERATING ACTIVITIES
Net Income (Loss)	$	(24,124	)	$	36,860		$	57,893
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:
Depreciation and Amortization		91,611			87,543			86,762
Deferred Income Taxes		31,362			(23,672	)		46,342
Allowance for Equity Funds Used During Construction		(1,367	)		(715	)		(865	)
Mark-to-Market of Risk Management Contracts		11,302			(3,737	)		557
Pension Contributions to Qualified Plan Trusts		-			-			(286	)
Change in Other Noncurrent Assets		(18,271	)		23,832			(29,737	)
Change in Other Noncurrent Liabilities		(24,761	)		(17,920	)		8,603
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		9,422			(32,580	)		(33,924	)
Fuel, Materials and Supplies		1,395			(13,481	)		(5,223	)
Margin Deposits		26,151			(25,219	)		(7,170	)
Accounts Payable		24,667			3,906			86,314
Customer Deposits		(9,810	)		(2,509	)		20,087
Accrued Taxes, Net		(27,650	)		4,857			(8,387	)
Fuel Over/Under-Recovery, Net		19,254			101,175			(108,366	)
Other Current Assets		2,747			(1,502	)		(911	)
Other Current Liabilities		1,010			5,529			16,511
Net Cash Flows from Operating Activities		112,938			142,367			128,200

INVESTING ACTIVITIES
Construction Expenditures		(314,568	)		(240,238	)		(134,358	)
Change in Advances to Affiliates, Net		(51,202	)		-			-
Proceeds from Sales of Assets		1,872			226			-
Other		3,044			6			(6	)
Net Cash Flows Used for Investing Activities		(360,854	)		(240,006	)		(134,364	)

FINANCING ACTIVITIES
Capital Contribution from Parent		80,000			-			-
Issuance of Long-term Debt – Nonaffiliated		258,339			148,695			74,405
Change in Advances from Affiliates, Net		(76,323	)		440			20,881
Retirement of Long-term Debt – Nonaffiliated		(12,660	)		-			(50,000	)
Retirement of Long-term Debt – Affiliated		-			(50,000	)		-
Principal Payments for Capital Lease Obligations		(1,508	)		(1,152	)		(668	)
Dividends Paid on Common Stock		-			-			(37,000	)
Dividends Paid on Cumulative Preferred Stock		(213	)		(213	)		(213	)
Net Cash Flows from Financing Activities		247,635			97,770			7,405

Net Increase (Decrease) in Cash and Cash Equivalents		(281	)		131			1,241
Cash and Cash Equivalents at Beginning of Period		1,651			1,520			279
Cash and Cash Equivalents at End of Period	$	1,370		$	1,651		$	1,520

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	40,692		$	32,652		$	29,607
Net Cash Paid (Received) for Income Taxes		(23,559	)		29,879			(5,244	)
Noncash Acquisitions Under Capital Leases		826			3,435			1,918
Construction Expenditures Included in Accounts Payable at December 31,		26,931			14,928			8,495

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

INDEX TO 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.

	Footnote Reference

Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Change	Note 2
Rate Matters	Note 4
Effects of Regulation	Note 5
Commitments, Guarantees and Contingencies	Note 6
Company-wide Staffing and Budget Review	Note 7
Benefit Plans	Note 9
Business Segments	Note 11
Derivatives, Hedging and Financial Instruments	Note 12
Income Taxes	Note 13
Leases	Note 14
Financing Activities	Note 15
Related Party Transactions	Note 16
Property, Plant and Equipment	Note 17
Unaudited Quarterly Financial Information	Note 18

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders 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, 2007 and 2006, and the related statements of operations, changes in common shareholder’s equity, and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2007. 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, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 2 and 9 to the financial statements, respectively, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”, effective January 1, 2007, and FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2008

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.

PSO’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control- Integrated Framework. Based on our assessment, the Company’s internal control over financial reporting was effective as of December 31, 2007.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

SELECTED CONSOLIDATED FINANCIAL DATA

(in thousands)

	2007			2006			2005			2004		2003
STATEMENTS OF INCOME DATA
Total Revenues	$	1,483,462		$	1,431,839		$	1,405,379		$	1,091,072	$	1,148,812

Operating Income	$	134,702		$	189,618		$	160,537		$	179,239	$	203,778

Income Before Cumulative Effect of Accounting Changes	$	66,264		$	91,723		$	75,190		$	89,457	$	89,624
Cumulative Effect of Accounting Changes, Net of Tax		-			-			(1,252	)		-		8,517
Net Income	$	66,264		$	91,723		$	73,938		$	89,457	$	98,141

BALANCE SHEETS DATA
Property, Plant and Equipment	$	4,876,912		$	4,328,247		$	4,006,639		$	3,892,508	$	3,804,600
Accumulated Depreciation and Amortization		1,939,044			1,834,145			1,776,216			1,710,850		1,619,178
Net Property, Plant and Equipment	$	2,937,868		$	2,494,102		$	2,230,423		$	2,181,658	$	2,185,422

Total Assets	$	3,488,615		$	3,190,968		$	2,797,347		$	2,646,849	$	2,581,727

Common Shareholder's Equity	$	972,955		$	821,202		$	782,378		$	768,618	$	696,660

Cumulative Preferred Stock Not Subject to Mandatory Redemption	$	4,697		$	4,697		$	4,700		$	4,700	$	4,700

Long-term Debt (a)	$	1,197,217	(b)	$	729,006		$	744,641		$	805,369	$	884,308

Obligations Under Capital Leases (a)	$	100,320	(c)	$	84,715	(c)	$	42,545		$	34,546	$	21,542

(a)	Including portion due within one year.
(b)	Increased primarily due to the construction of new generation.
(c)	Increased primarily due to new leases for coal handling equipment.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

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 467,000 retail customers in its service territory in northeastern Texas, northwestern Louisiana and western Arkansas. SWEPCo consolidates Southwest Arkansas Utilities Corporation and Dolet Hills Lignite Company, LLC, its wholly-owned subsidiaries. SWEPCo also consolidates Sabine Mining Company, a variable interest entity. As a member of the CSW Operating Agreement with PSO, SWEPCo shares in the revenues and expenses of the members’ sales to neighboring utilities and power marketers. SWEPCo also sells electric power at wholesale to other utilities, municipalities and electric cooperatives.

Effective May 1, 2006, the FERC approved the removal of TCC and TNC from the CSW Operating Agreement. Under the Texas Restructuring Legislation, TCC and TNC completed the final stage of exiting the generation business and ceased serving retail load. TCC and TNC are no longer involved in the coordinated planning and operation of power supply facilities or share trading and marketing margins, as contemplated by both the CSW Operating Agreement and the SIA. Consequently, SWEPCo’s proportionate share of trading and marketing margins increased, although the level of margins depends upon future market conditions. SWEPCo shares these margins with its customers.

Members of the CSW Operating Agreement are 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, over-the-counter 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.

Effective January 1, 2007, SWEPCo locked in margins on its ERCOT trading and marketing contracts and transferred commodity price risk to AEP Energy Partners, LP (AEPEP), a wholly-owned subsidiary of AEP. This was achieved by a combination of transferring certain existing ERCOT energy marketing contracts to AEPEP and entering into financial and physical purchase and sale agreements with AEPEP. SWEPCo will not be a party to new contracts in ERCOT. As the contracts mature, SWEPCo will realize the fixed margin on the portfolio of ERCOT contracts as it existed on December 31, 2006 and will not be exposed to commodity price risk and resulting earnings variations for these contracts.

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

Results of Operations

2007 Compared to 2006

Reconciliation of Year Ended December 31, 2006 to Year Ended December 31, 2007

Income Before Cumulative Effect of Accounting Change

(in millions)

Year Ended December 31, 2006			$	92

Changes in Gross Margin:
Retail and Off-system Sales Margins (a)	(13	)
Other	(13	)
Total Change in Gross Margin				(26	)

Changes in Operating Expenses and Other:
Other Operation and Maintenance	(19	)
Depreciation and Amortization	(7	)
Taxes Other Than Income Taxes	(3	)
Other Income	9
Interest Expense	(5	)
Total Change in Operating Expenses and Other				(25	)

Minority Interest Expense				(1	)
Income Tax Expense				26

Year Ended December 31, 2007			$	66

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

Income Before Cumulative Effect of Accounting Change decreased $26 million in 2007. The key drivers of the decrease were a $26 million decrease in Gross Margin and a $25 million increase in Operating Expenses and Other, partially offset by a $26 million decrease in Income Tax Expense.

·	Retail and Off-system Sales Margins decreased $13 million primarily due to:
	·	A $17 million provision related to a SWEPCo Texas fuel reconciliation proceeding (see “SWEPCo Fuel Reconciliation – Texas” section of Note 4).
	·	An $8 million decrease from higher sharing of net realized off-system sales margins.
	These decreases were partially offset by:
	·	A $16 million increase in retail sales margins related to a combination of higher average usage and increased retail customers.
·	Other revenues decreased $13 million primarily due to an $8 million decrease in gains on sales of emission allowances and a $3 million decrease in revenue from coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC, to outside parties. The decreased revenue from coal deliveries was offset by a corresponding decrease in Other Operation and Maintenance expenses from mining operations as discussed below.

Operating Expenses and Other and Income Taxes changed between years as follows:

·	Other Operation and Maintenance expenses increased $19 million primarily due to the following:
	·	A $14 million increase in maintenance expenses from planned and forced outages at the Welsh, Dolet Hills, Flint Creek, Knox Lee and Pirkey Plants.
	·	A $9 million increase in transmission expenses primarily related to higher SPP administration fees and transmission services from other utilities.
	These increases were partially offset by:
	·	A $4 million decrease in expenses primarily resulting from decreased coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC, due to planned and forced outages at the Dolet Hills Generating Station, which is jointly-owned by SWEPCo and Cleco Corporation, a nonaffiliated entity.
·	Depreciation and Amortization expense increased $7 million primarily due to higher depreciable asset balances.
·	Taxes Other Than Income Taxes increased $3 million primarily due to a sales and use tax adjustment recorded in 2006.
·	Other Income increased $9 million primarily due to an increase in the equity component of AFUDC as a result of new generation projects at the Turk Plant, Mattison Plant and Stall Unit. See Note 4.
·	Interest Expense increased $5 million primarily due to higher interest of $12 million related to higher long-term debt partially offset by an $8 million increase in the debt component of AFUDC due to new generation projects at the Turk Plant, Mattison Plant and Stall Unit. See Note 4.
·	Income Tax Expense decreased $26 million primarily due to a decrease in pretax book income and state income tax adjustments.

2006 Compared to 2005

Reconciliation of Year Ended December 31, 2005 to Year Ended December 31, 2006

Income Before Cumulative Effect of Accounting Change

(in millions)

Year Ended December 31, 2005			$	75

Changes in Gross Margin:
Retail and Off-system Sales Margins (a)	14
Transmission Revenues	2
Other	22
Total Change in Gross Margin				38

Changes in Operating Expenses and Other:
Other Operation and Maintenance	(11	)
Taxes Other Than Income Taxes	4
Interest Expense	(5	)
Total Change in Operating Expenses and Other				(12	)

Income Tax Expense				(9	)

Year Ended December 31, 2006			$	92

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

Income Before Cumulative Effect of Accounting Change increased $17 million in 2006. The key driver of the increase was a $38 million increase in Gross Margin, partially offset by a $12 million increase in Operating Expense and Other and a $9 million increase in Income Tax Expense.

·	Retail and Off-system Sales Margins increased $14 million primarily due to:
	·	A $22 million increase in retail margins primarily due to favorable prices, increased usage and new contracts related to wholesale sales and increased ancillary services, partially offset by:
	·	An $8 million decrease in off-system sales margins retained. Total off-system margins decreased $51 million due to decreased physical sales and a decrease in SWEPCo’s allocation of off-system sales margins under the SIA, partially offset by $38 million of the decrease flowing through the fuel adjustment clause, and having no impact on Gross Margin, and a $6 million increase in other off-system sales not flowed through the fuel adjustment clause. The change in allocation methodology of the SIA occurred on April 1, 2006.
·	Other revenues increased $22 million primarily due to gains on sales of emission allowances.

Operating Expenses and Other and Income Taxes changed between years as follows:

·	Other Operation and Maintenance expenses increased $11 million primarily due to an increase in employee-related expenses.
·	Taxes Other Than Income Taxes decreased $4 million primarily due to a sales and use tax adjustment recorded in 2006.
·	Interest Expense increased $5 million primarily due to increased Utility Money Pool borrowings in 2006.
·	Income Tax Expense increased $9 million primarily due to an increase in pretax book income and state income taxes, offset in part, by the recording of the tax return adjustments.

Financial Condition

Credit Ratings

S&P and Fitch currently have SWEPCo on stable outlook, while Moody’s placed SWEPCo on negative outlook in January 2008. Current ratings are as follows:

	Moody’s	S&P	Fitch

Senior Unsecured Debt	Baa1	BBB	A-

Cash Flow

Cash flows for 2007, 2006 and 2005 were as follows:

	Years Ended December 31,
	2007			2006			2005
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	2,618		$	3,049		$	3,715
Cash Flows from (Used for):
Operating Activities		164,626			210,136			208,153
Investing Activities		(503,819	)		(323,193	)		(115,073	)
Financing Activities		338,317			112,626			(93,746	)
Net Decrease in Cash and Cash Equivalents		(876	)		(431	)		(666	)
Cash and Cash Equivalents at End of Period	$	1,742		$	2,618			3,049

Operating Activities

Net Cash Flows from Operating Activities were $165 million in 2007. SWEPCo produced Net Income of $66 million during the period and had noncash expense items of $139 million for Depreciation and Amortization and $17 million related to the Provision for Fuel Disallowance recorded as the result of an ALJ ruling in SWEPCo’s Texas fuel reconciliation proceeding. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $21 million inflow from Accounts Receivable, Net was primarily due to the assignment of certain ERCOT contracts to an affiliate company. The $31 million inflow from Margin Deposits was due to decreased trading-related deposits resulting from normal trading activities. The $37 million outflow from Accounts Payable is primarily due to the timing of fuel payments at the end of the year. The $26 million outflow from Fuel Over/Under-Recovery, Net is due to under recovery of higher fuel costs.

Net Cash Flows from Operating Activities were $210 million in 2006. SWEPCo produced Net Income of $92 million during the period and had a noncash expense item of $132 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $74 million inflow related to Fuel Over/Under-Recovery, Net was primarily due to the new fuel surcharges effective December 2005 in the Arkansas service territory and in January 2006 in the Texas service territory. The $67 million inflow from Accounts Payable was the result of higher energy purchases. The $52 million outflow from Accounts Receivable, Net was primarily due to an increase in the proportionate share of trading and marketing Accounts Receivable as a result of changes in the CSW Operating Agreement and the SIA. The $40 million outflow from Fuel, Materials and Supplies was the result of increased fuel purchases. The $28 million outflow for Margin Deposits was due to increased trading-related deposits resulting from the amended SIA.

Net Cash Flows from Operating Activities were $208 million in 2005. SWEPCo produced Net Income of $74 million during the period and had a noncash expense item of $132 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items. The most significant are Accounts Receivable, Accounts Payable, and Customer Deposits, all of which were driven by higher fuel-related costs. The $53 million outflow related to Fuel Over/Under-Recovery, Net was due to overall rising fuel costs. The $28 million outflow from Accounts Receivable, Net was due to higher affiliated energy sales. The $46 million inflow from Accounts Payable was primarily due to higher energy and fuel-related purchases as well as increased vendor-related payables.

Investing Activities

Net Cash Flows Used for Investing Activities during 2007, 2006 and 2005 were $504 million, $323 million and $115 million, respectively. The cash outflows during 2007 and 2006 were comprised primarily of Construction Expenditures related to the construction of the Turk Plant, Mattison Plant and Stall Unit, which are all new generation facilities. The cash outflows during 2006 were also comprised of Construction Expenditures related to projects for improved transmission and distribution service reliability. The cash outflows during 2005 were comprised primarily of Construction Expenditures related to projects for improved transmission and distribution service reliability offset by Advances to Affiliates.

Financing Activities

Net Cash Flows from Financing Activities were $338 million during 2007. SWEPCo issued $550 million of Senior Unsecured Notes and $25 million in Notes Payable. SWEPCo retired $90 million of First Mortgage Bonds. SWEPCo reduced its borrowings from the Utility Money Pool by $187 million and received a Capital Contribution from Parent of $85 million. SWEPCo also had a net decrease in short-term debt of $17 million.

Net Cash Flows from Financing Activities were $113 million during 2006. SWEPCo had a net increase of $161 million in borrowings from the Utility Money Pool during the fourth quarter. SWEPCo refinanced (retired and issued) $82 million of Pollution Control Bonds and retired $15 million of long-term debt. SWEPCo had a net increase in short-term debt of $16 million. In addition, SWEPCo paid $40 million in common stock dividends.

Net Cash Flows Used for Financing Activities were $94 million during 2005. During the year, SWEPCo issued $150 million of Senior Unsecured Notes. Proceeds were used to fund the July 2005 maturity of $200 million of Senior Unsecured Notes. In addition, SWEPCo had a net increase of $28 million in borrowings from the Utility Money Pool. SWEPCo paid $55 million in common stock dividends in 2005.

Summary Obligation Information

SWEPCo’s contractual obligations include amounts reported on SWEPCo’s Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes SWEPCo’s contractual cash obligations at December 31, 2007:

Payment Due by Period

(in millions)

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Advances from Affiliates (a)	$	1.6	$	-	$	-	$	-	$	1.6
Short-term Debt (b)		0.3		-		-		-		0.3
Interest on Fixed Rate Portion of Long-term Debt (c)		51.2		98.3		93.3		213.7		456.5
Fixed Rate Portion of Long-term Debt (d)		4.4		58.8		21.5		938.4		1,023.1
Variable Rate Portion of Long-term Debt (e)		1.5		-		41.1		135.2		177.8
Capital Lease Obligations (f)		16.8		29.0		21.2		73.0		140.0
Noncancelable Operating Leases (f)		8.0		12.2		6.7		7.2		34.1
Fuel Purchase Contracts (g)		381.5		709.2		624.3		2,034.1		3,749.1
Energy and Capacity Purchase Contracts (h)		11.1		14.8		8.4		58.8		93.1
Construction Contracts for Capital Assets (i)		316.4		498.5		385.5		124.2		1,324.6
Total	$	792.8	$	1,420.8	$	1,202.0	$	3,584.6	$	7,000.2

(a)	Represents short-term borrowings from the Utility Money Pool.
(b)	Represents principal only excluding interest.
(c)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2007 and do not reflect anticipated future refinancings, early redemptions or debt issuances.
(d)	See Note 15. Represents principal only excluding interest.
(e)	See Note 15. Represents principal only excluding interest. Variable rate debt had interest rates of 4.25% and 5.50 % at December 31, 2007.
(f)	See Note 14.
(g)	Represents contractual obligations to purchase coal, natural gas and other consumables as fuel for electric generation along with related transportation of the fuel.
(h)	Represents contractual cash flows of energy and capacity purchase contracts.
(i)	Represents only capital assets that are contractual obligations.

SWEPCo’s FIN 48 liabilities of $6 million are not included above because SWEPCo cannot reasonably estimate the cash flows by period.

As discussed in Note 9, SWEPCo’s minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trust.

In addition to the amounts disclosed in the contractual cash obligations table above, SWEPCo makes additional commitments in the normal course of business. SWEPCo’s commitments outstanding at December 31, 2007 under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period

(in millions)

Other Commercial Commitments	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Standby Letters of Credit (a)	$	4.0	$	-	$	-	$	-	$	4.0
Guarantees of the Performance of Outside Parties (b)		-		-		-		65.0		65.0
Total	$	4.0	$	-	$	-	$	65.0	$	69.0

(a)

SWEPCo has issued standby letters of credit to third parties. These letters of credit cover insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. All of these letters of credit were issued in SWEPCo’s ordinary course of business. The maximum future payments of these letters of credit are $4 million maturing in December 2008. There is no recourse to third parties in the event these letters of credit are drawn. See “Letters of Credit” section of Note 6.

(b)

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

Significant Factors

New Generation

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of relevant factors.

Litigation and Regulatory Activity

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 state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrue a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to materially affect SWEPCo’s results of operations, financial condition and cash flows.

Critical Accounting Estimates

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in SWEPCo’s Consolidated Balance Sheet as of December 31, 2007 and the reasons for changes in total MTM value as compared to December 31, 2006.

Reconciliation of MTM Risk Management Contracts to

Consolidated Balance Sheet

December 31, 2007

(in thousands)

	MTM Risk
	Management			Cash Flow			DETM
	Contracts			Hedges			Assignment (a)			Total
Current Assets	$	39,799		$	94		$	-		$	39,893
Noncurrent Assets		4,059			36			-			4,095
Total MTM Derivative Contract Assets		43,858			130			-			43,988

Current Liabilities		(32,482	)		(11	)		(175	)		(32,668	)
Noncurrent Liabilities		(3,245	)		-			(215	)		(3,460	)
Total MTM Derivative Contract Liabilities		(35,727	)		(11	)		(390	)		(36,128	)

Total MTM Derivative Contract Net Assets (Liabilities)	$	8,131		$	119		$	(390	)	$	7,860

(a)	See “Natural Gas Contracts with DETM” section of Note 16.

MTM Risk Management Contract Net Assets

Year Ended December 31, 2007

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2006	$	20,166
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		(13,710	)
Fair Value of New Contracts at Inception When Entered During the Period (a)		32
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period		-
Changes in Fair Value Due to Market Fluctuations During the Period (b)		580
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		1,063
Total MTM Risk Management Contract Net Assets		8,131
Net Cash Flow Hedge Contracts		119
DETM Assignment (d)		(390	)
Total MTM Risk Management Contract Net Assets at December 31, 2007	$	7,860

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(d)	See “Natural Gas Contracts with DETM” section of Note 16.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents:

·	The method of measuring fair value used in determining the carrying amount of total MTM asset or liability (external sources or modeled internally).
·	The maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash.

Maturity and Source of Fair Value of MTM

Risk Management Contract Net Assets

Fair Value of Contracts as of December 31, 2007

(in thousands)

	2008			2009			2010			2011		2012		After 2012		Total
Prices Actively Quoted – Exchange Traded Contracts	$	2,665		$	(228	)	$	(12	)	$	-	$	-	$	-	$	2,425
Prices Provided by Other External Sources - OTC Broker Quotes (a)		5,718			935			151			-		-		-		6,804
Prices Based on Models and Other Valuation Methods (b)		(1,066	)		(7	)		(45	)		20		-		-		(1,098	)
Total	$	7,317		$	700		$	94		$	20	$	-	$	-	$	8,131

(a)	“Prices Provided by Other External Sources – OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)	“Prices Based on Models and Other Valuation Methods” is used in absence of independent information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.

	Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available including values determinable by other third party transactions.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Consolidated Balance Sheet

SWEPCo is exposed to market fluctuations in energy commodity prices impacting power operations. Management monitors these risks on future operations and may use various commodity derivative instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. Management does not hedge all commodity price risk.

Management uses interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt. Management does not hedge all interest rate risk.

Management uses foreign currency derivatives to lock in prices on certain transactions denominated in foreign currencies where deemed necessary, and designate qualifying instruments as cash flow hedge strategies. Management does not hedge all foreign currency.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on SWEPCo’s Consolidated Balance Sheets and the reasons for the changes from December 31, 2006 to December 31, 2007. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Year Ended December 31, 2007

(in thousands)

	Interest Rate			Foreign Currency		Total
Beginning Balance in AOCI December 31, 2006	$	(6,435	)	$	25	$	(6,410	)
Changes in Fair Value		(1,020	)		604		(416	)
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled		805			-		805
Ending Balance in AOCI December 31, 2007	$	(6,650	)	$	629	$	(6,021	)

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $829 thousand loss.

Credit Risk

Counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

The following table shows the end, high, average, and low market risk as measured by VaR for the years ended:

December 31, 2007				December 31, 2006
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$17	$245	$75	$7	$447	$2,171	$794	$68

As SWEPCo’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand SWEPCo’s exposure to extreme price moves. Management employs a historically-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translate into the largest potential mark-to-market loss. Management can then research the underlying positions, price moves and market event that created the most significant exposure.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which SWEPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. For 2008, the estimated EaR on SWEPCo’s debt portfolio was $2.3 million.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	2007			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	1,428,613		$	1,386,653		$	1,338,882
Sales to AEP Affiliates		53,102			42,445			65,408
Other		1,747			2,741			1,089
TOTAL		1,483,462			1,431,839			1,405,379

EXPENSES
Fuel and Other Consumables Used for Electric Generation		515,565			471,418			527,525
Purchased Electricity for Resale		209,754			175,124			133,403
Purchased Electricity from AEP Affiliates		72,895			74,458			70,911
Other Operation		234,726			224,750			213,629
Maintenance		110,270			100,962			101,049
Depreciation and Amortization		139,241			132,261			131,620
Taxes Other Than Income Taxes		66,309			63,248			66,705
TOTAL		1,348,760			1,242,221			1,244,842

OPERATING INCOME		134,702			189,618			160,537

Other Income (Expense):
Interest Income		3,007			2,582			1,499
Allowance for Equity Funds Used During Construction		10,243			1,302			2,394
Interest Expense		(60,619	)		(55,213	)		(50,089	)

INCOME BEFORE INCOME TAXES, MINORITY INTEREST EXPENSE AND EQUITY EARNINGS		87,333			138,289			114,341

Income Tax Expense		17,561			43,697			34,922
Minority Interest Expense		3,507			2,868			4,226
Equity Earnings of Unconsolidated Subsidiaries		(1	)		(1	)		(3	)

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		66,264			91,723			75,190

CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX		-			-			(1,252	)

NET INCOME		66,264			91,723			73,938

Preferred Stock Dividend Requirements		229			229			229

EARNINGS APPLICABLE TO COMMON STOCK	$	66,035		$	91,494		$	73,709

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

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004	$	135,660	$	245,003	$	389,135		$	(1,180	)	$	768,618

Common Stock Dividends						(55,000	)					(55,000	)
Preferred Stock Dividends						(229	)					(229	)
TOTAL												713,389

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $2,709									(5,032	)		(5,032	)
Minimum Pension Liability, Net of Tax of $44									83			83
NET INCOME						73,938						73,938
TOTAL COMPREHENSIVE INCOME												68,989

DECEMBER 31, 2005		135,660		245,003		407,844			(6,129	)		782,378

Common Stock Dividends						(40,000	)					(40,000	)
Preferred Stock Dividends						(229	)					(229	)
TOTAL												742,149

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $515									(558	)		(558	)
Minimum Pension Liability, Net of Tax of $35									65			65
NET INCOME						91,723						91,723
TOTAL COMPREHENSIVE INCOME												91,230
Minimum Pension Liability Elimination, Net of Tax of $114									212			212
SFAS 158 Adoption, Net of Tax of $6,671									(12,389	)		(12,389	)

DECEMBER 31, 2006		135,660		245,003		459,338			(18,799	)		821,202

FIN 48 Adoption, Net of Tax						(1,642	)					(1,642	)
Capital Contribution from Parent				85,000								85,000
Preferred Stock Dividends						(229	)					(229	)
TOTAL												904,331

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $210									389			389
Pension and OPEB Funded Status, Net of Tax of $1,061									1,971			1,971
NET INCOME						66,264						66,264
TOTAL COMPREHENSIVE INCOME												68,624

DECEMBER 31, 2007	$	135,660	$	330,003	$	523,731		$	(16,439	)	$	972,955

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2007 and 2006

(in thousands)

	2007			2006
CURRENT ASSETS
Cash and Cash Equivalents	$	1,742		$	2,618
Accounts Receivable:
Customers		91,379			88,245
Affiliated Companies		33,196			59,679
Miscellaneous		10,544			8,595
Allowance for Uncollectible Accounts		(143	)		(130	)
Total Accounts Receivable		134,976			156,389
Fuel		75,662			69,426
Materials and Supplies		48,673			46,001
Risk Management Assets		39,893			120,036
Regulatory Asset for Under-Recovered Fuel Costs		5,859			-
Margin Deposits		10,814			41,579
Prepayments and Other		28,147			18,256
TOTAL		345,766			454,305

PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		1,743,198			1,576,200
Transmission		737,975			668,008
Distribution		1,312,746			1,228,948
Other		631,765			595,429
Construction Work in Progress		451,228			259,662
Total		4,876,912			4,328,247
Accumulated Depreciation and Amortization		1,939,044			1,834,145
TOTAL - NET		2,937,868			2,494,102

OTHER NONCURRENT ASSETS
Regulatory Assets		133,617			156,420
Long-term Risk Management Assets		4,095			20,531
Deferred Charges and Other		67,269			65,610
TOTAL		204,981			242,561

TOTAL ASSETS	$	3,488,615		$	3,190,968

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

December 31, 2007 and 2006

	2007			2006
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	1,565		$	188,965
Accounts Payable:
General		152,305			140,424
Affiliated Companies		51,767			68,680
Short-term Debt – Nonaffiliated		285			17,143
Long-term Debt Due Within One Year – Nonaffiliated		5,906			102,312
Risk Management Liabilities		32,668			109,578
Customer Deposits		37,537			48,277
Accrued Taxes		26,494			31,591
Regulatory Liability for Over-Recovered Fuel Costs		22,879			26,012
Other		76,554			85,086
TOTAL		407,960			818,068

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		1,141,311			576,694
Long-term Debt – Affiliated		50,000			50,000
Long-term Risk Management Liabilities		3,460			14,083
Deferred Income Taxes		361,806			374,548
Regulatory Liabilities and Deferred Investment Tax Credits		334,014			346,774
Deferred Credits and Other		210,725			183,087
TOTAL		2,101,316			1,545,186

TOTAL LIABILITIES		2,509,276			2,363,254

Minority Interest		1,687			1,815

Cumulative Preferred Stock Not Subject to Mandatory Redemption		4,697			4,697

Commitments and Contingencies (Note 6)

COMMON SHAREHOLDER’S 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		330,003			245,003
Retained Earnings		523,731			459,338
Accumulated Other Comprehensive Income (Loss)		(16,439	)		(18,799	)
TOTAL		972,955			821,202

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	3,488,615		$	3,190,968

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2007, 2006 and 2005

(in thousands)

	2007			2006			2005
OPERATING ACTIVITIES
Net Income	$	66,264		$	91,723		$	73,938
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		139,241			132,261			131,620
Deferred Income Taxes		(21,935	)		(23,667	)		(4,942	)
Provision for Fuel Disallowance		17,011			-			-
Cumulative Effect of Accounting Change, Net of Tax		-			-			1,252
Allowance for Equity Funds Used During Construction		(10,243	)		(1,302	)		(2,394	)
Mark-to-Market of Risk Management Contracts		12,425			(3,779	)		1,140
Change in Other Noncurrent Assets		23,530			31,204			(25,038	)
Change in Other Noncurrent Liabilities		(21,656	)		(30,580	)		25,625
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		21,413			(52,212	)		(27,835	)
Fuel, Materials and Supplies		(8,877	)		(40,273	)		6,690
Margin Deposits		30,765			(27,839	)		(10,321	)
Accounts Payable		(37,214	)		67,452			45,742
Customer Deposits		(10,740	)		(2,571	)		20,298
Accrued Taxes, Net		(2,453	)		(11,208	)		(2,675	)
Fuel Over/Under-Recovery, Net		(26,003	)		74,218			(53,410	)
Other Current Assets		871			2,134			2,014
Other Current Liabilities		(7,773	)		4,575			26,449
Net Cash Flows from Operating Activities		164,626			210,136			208,153

INVESTING ACTIVITIES
Construction Expenditures		(504,645	)		(323,332	)		(157,595	)
Change in Other Cash Deposits, Net		(122	)		(120	)		3,308
Change in Advances to Affiliates, Net		-			-			39,106
Proceeds from Sales of Assets		948			259			108
Net Cash Flows Used for Investing Activities		(503,819	)		(323,193	)		(115,073	)

FINANCING ACTIVITIES
Capital Contribution from Parent		85,000			-			-
Issuance of Long-term Debt – Nonaffiliated		569,078			80,593			154,574
Change in Short-term Debt, Net – Nonaffiliated		(16,858	)		15,749			-
Change in Advances from Affiliates, Net		(187,400	)		160,755			28,210
Retirement of Long-term Debt – Nonaffiliated		(102,312	)		(97,455	)		(215,101	)
Retirement of Cumulative Preferred Stock		-			(3	)		-
Principal Payments for Capital Lease Obligations		(8,962	)		(6,784	)		(6,200	)
Dividends Paid on Common Stock		-			(40,000	)		(55,000	)
Dividends Paid on Cumulative Preferred Stock		(229	)		(229	)		(229	)
Net Cash Flows from (Used for) Financing Activities		338,317			112,626			(93,746	)

Net Decrease in Cash and Cash Equivalents		(876	)		(431	)		(666	)
Cash and Cash Equivalents at Beginning of Period		2,618			3,049			3,715
Cash and Cash Equivalents at End of Period	$	1,742		$	2,618		$	3,049

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	53,000		$	47,610		$	43,673
Net Cash Paid for Income Taxes		47,069			82,267			52,756
Noncash Acquisitions Under Capital Leases		24,481			48,777			9,629
Construction Expenditures Included in Accounts Payable at December 31,		59,898			27,716			10,221

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

	Footnote Reference

Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Change	Note 2
Goodwill and Other Intangible Assets	Note 3
Rate Matters	Note 4
Effects of Regulation	Note 5
Commitments, Guarantees and Contingencies	Note 6
Company-wide Staffing and Budget Review	Note 7
Benefit Plans	Note 9
Business Segments	Note 11
Derivatives, Hedging and Financial Instruments	Note 12
Income Taxes	Note 13
Leases	Note 14
Financing Activities	Note 15
Related Party Transactions	Note 16
Property, Plant and Equipment	Note 17
Unaudited Quarterly Financial Information	Note 18

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders 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, 2007 and 2006, and the related consolidated statements of income, changes in common shareholder’s equity, and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2007. 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, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2008

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.

SWEPCo’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control- Integrated Framework. Based on our assessment, the Company’s internal control over financial reporting was effective as of December 31, 2007.

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, CSPCo, I&M, OPCo, PSO, SWEPCo
2.	New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Change	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
3.	Goodwill and Other Intangible Assets	SWEPCo
4.	Rate Matters	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
5.	Effects of Regulation	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
6.	Commitments, Guarantees and Contingencies	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
7.	Company-wide Staffing and Budget Review	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
8.	Acquisitions and Asset Impairment	APCo, CSPCo
9.	Benefit Plans	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
10.	Nuclear	I&M
11.	Business Segments	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
12.	Derivatives, Hedging and Financial Instruments	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
13.	Income Taxes	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
14.	Leases	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
15.	Financing Activities	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
16.	Related Party Transactions	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
17.	Property, Plant and Equipment	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
18.	Unaudited Quarterly Financial Information	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

1.	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

The principal business conducted by AEP’s 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 engage in wholesale electricity marketing and risk management activities in the United States. In addition, I&M provides barging services to both affiliated and nonaffiliated companies.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

AEP’s, AEPSC’s and its other subsidiaries affiliated transactions are regulated by the FERC under the 2005 Public Utility Holding Company Act (2005 PUHCA). AEP’s public utility subsidiaries rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories. The state regulatory commissions with jurisdiction approve the retail rates charged and regulate the retail services and operations of the utility subsidiaries for the generation and supply of power, a majority of transmission energy delivery services and distribution services.

The FERC regulates wholesale power markets and wholesale power transactions. The Registrant Subsidiaries’ wholesale power transactions are generally market-based and are not cost-based regulated unless 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 in which the transaction is taking place. The Registrant Subsidiaries enter into wholesale all-requirements power supply contracts with various municipalities and cooperatives that are FERC regulated, cost-based contracts. SWEPCo and PSO wholesale power transactions in the SPP region are all cost-based due to SWEPCo and PSO having market power in the SPP region.

The FERC also regulates, on a cost basis, the Registrant Subsidiaries’ wholesale transmission service and rates. The FERC claimed jurisdiction over retail transmission rates when the retail rates are unbundled in connection with restructuring. CSPCo’s and OPCo’s rates in Ohio and APCo’s retail rates in Virginia are unbundled. Therefore CSPCo, OPCo and APCo’s retail transmission rates are based on FERC’s Open Access Transmission Tariff (OATT) rates that are cost-based. Otherwise, retail transmission rates are still regulated, on a cost basis, by the state regulatory commissions.

In addition, the FERC regulates the AEP Power Pool, the CSW Operating Agreement, the East Transmission Equalization Agreement, Transmission Coordination Agreement, System Interim Allowance Agreement, and SIA, all of which allocate shared system costs and revenues to the AEP utility subsidiaries that are parties to the agreements.

The state regulatory commissions regulate all of the retail public utility services/operations (generation/power supply, transmission and distribution operations) and retail rates except in Ohio. The retail generation/power supply operations and rates for CSPCo and OPCo in Ohio are no longer cost based regulated and are on a transition to market based rates. These rates are currently subject to rate stabilization plans which expire on December 31, 2008. Under the present legislation in Ohio, rates are scheduled to be market based starting in January 2009. However, legislation is under consideration that may extend that transition date. In Virginia the legislature re-regulated AEP’s generation/supply business in 2007 ending a transition to market based rates and returning APCo to cost-based regulation. See Note 4 for further information of restructuring legislation and its effects on AEP in Ohio, Virginia and Michigan.

In 2005, the Registrant Subsidiaries were subject to regulation by the SEC under the Public Utility Holding Company Act of 1935 (1935 PUHCA). The Energy Policy Act of 2005 repealed the 1935 PUHCA effective February 8, 2006 and replaced it with the 2005 PUHCA. With the repeal of the 1935 PUHCA, the SEC no longer has jurisdiction over the affiliated activities of registered holding companies, their respective service corporations and their intercompany transactions, which it regulated since 1935 predominantly at cost. Jurisdiction over holding company-related affiliated activities was transferred to the FERC and the required reporting was reduced by the 2005 PUHCA. 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, mergers with another electric utility or holding company, inter-company transactions, accounting and AEPSC intercompany service billings which are generally at cost. The intercompany sale of non-power goods and non-AEPSC services to affiliates cannot exceed market under the 2005 PUHCA. The state regulatory commissions in Virginia and West Virginia also regulate certain intercompany transactions under their affiliates statutes.

Both the FERC and state regulatory commissions with jurisdiction are permitted to review and audit the books and records of any company within a public utility holding company system.

Principles of Consolidation

The consolidated financial statements for APCo, CSPCo and I&M include the registrant and its wholly-owned subsidiaries. The consolidated financial statements for SWEPCo include the registrant, its wholly-owned subsidiaries and Sabine Mining Company (a substantially controlled variable interest entity (VIE)). The consolidated financial statements for OPCo include the registrant and JMG Funding LP (a substantially controlled VIE). Intercompany items are eliminated in consolidation. Equity investments not substantially controlled that are 50% or less owned are accounted for using the equity method of accounting and are reported as Deferred Charges and Other on the consolidated balance sheets; equity earnings are included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. CSPCo, OPCo, PSO and SWEPCo also have generating units that are jointly-owned with nonaffiliated companies. The proportionate share of the operating costs associated with such facilities is included in the financial statements and the assets and liabilities are reflected in the balance sheets.

Accounting for the Effects of Cost-Based Regulation

As cost-based 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 SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues and income with its passage to customers through the reduction of regulated revenues. Due to the commencement of legislatively required restructuring and a transition to customer choice and market-based rates, certain affected Registrant Subsidiaries discontinued the application of SFAS 71, regulatory accounting, for the generation portion of their business as follows: in Ohio for OPCo and CSPCo in September 2000, in Virginia for APCo in June 2000, and in Texas for SWEPCo’s Texas generation business in September 1999. In 2007, the Virginia legislature amended its restructuring legislation to provide for the re-regulation of generation and supply business and rates on a cost basis. SFAS 101, “Regulated Enterprises – Accounting for the Discontinuance of Application of FASB Statement No. 71” requires the recognition of an impairment of stranded regulatory assets and stranded plants costs if they are not recoverable in regulated rates. In addition, an enterprise is required to eliminate from its balance sheet the effects of any actions of regulators that had been recognized as regulatory assets and regulatory liabilities pursuant to SFAS 71. Such impairments and adjustments arising from the discontinuance or reapplication of SFAS 71 are classified by SFAS 101 as an extraordinary item. Consistent with SFAS 71 as amended by SFAS 101, APCo recorded an extraordinary reduction in earnings and shareholder’s equity from the reapplication of SFAS 71 regulatory accounting in 2007 resulting from the passage of re-regulation legislation by the Virginia legislature, which reinstated cost-based rate regulation for APCo’s generation and supply business.

Use of Estimates

The preparation of these financial statements in conformity with accounting principles generally accepted in the United States of America 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, 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.

Property, Plant and Equipment and Equity Investments

Electric utility property, plant and equipment are stated at original purchase cost. Property, plant and equipment of nonregulated operations and other investments are stated at fair market value at acquisition (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for both cost-based rate-regulated and nonregulated operations under the group composite method of 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. 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. For the nonregulated generation assets, a gain or loss would be recorded if the retirement is not considered an interim routine replacement. The depreciation rates that are established for the generating plants 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 for cost-based rate-regulated operations and charged to expense for nonregulated operations. The costs of labor, materials and overhead incurred to operate and maintain the plants are included in operating expenses.

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held for sale criteria under SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” 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.

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 domestic regulated electric utility plant. For nonregulated operations including domestic generating assets in Ohio and Texas, effective with the discontinuance of SFAS 71 regulatory accounting, interest is capitalized during construction in accordance with SFAS 34, “Capitalization of Interest Costs.”

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Other Cash Deposits, Accounts Receivable, Short-term Debt and Accounts Payable 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.

Cash and Cash Equivalents

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

Other Cash Deposits

Other Cash Deposits include funds held by trustees primarily for environmental construction expenditures.

Inventory

Fossil fuel inventories are carried at average cost for APCo, I&M and SWEPCo. OPCo and CSPCo value fossil fuel inventories at the lower of average cost or market. PSO carries fossil fuel inventories utilizing a LIFO method. Excess of replacement or current costs over stated LIFO value for PSO was $11 million and $4 million as of December 31, 2007 and 2006, respectively. 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 or delivery when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, AEP and certain subsidiaries accrue and recognize, as Accrued Unbilled Revenues, an estimate of the revenues for energy delivered since the last billing.

AEP Credit factors accounts receivable through purchase agreements with CSPCo, I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” allowing the receivables to be removed from the company’s balance sheet (see “Sale of Receivables - AEP Credit” section of Note 15).

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, 2007.

The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. Management believes adequate provision for credit loss has been made in the accompanying registrant financial statements.

Deferred Fuel Costs

The cost of fuel and related chemical and emission allowance consumables is charged to Fuel and Other Consumables Used for Electric Generation Expense when the fuel is burned or the consumable is utilized. Where applicable under governing state regulatory commission retail rate orders, fuel cost over-recoveries (the excess of fuel revenues billed to customers over fuel costs incurred) are deferred as current regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as current regulatory assets. These deferrals are amortized when refunded or billed to customers in later months with the regulator’s review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of regulators. On a routine basis, state regulatory commissions audit fuel cost calculations. When a fuel cost disallowance becomes probable, the Registrant Subsidiaries adjust their deferrals and record provisions for estimated refunds to recognize these probable outcomes (see Note 4). Fuel cost over-recovery and under-recovery balances are classified as noncurrent when the fuel clauses have been suspended or terminated as in West Virginia prior to July 2006.

In general, changes in fuel costs in Indiana (beginning July 1, 2007) and Michigan for I&M, the SPP area of Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia and West Virginia for APCo are reflected in rates in a timely manner through the fuel cost adjustment clauses in place in those states. All or a portion of profits from off-system sales are shared with customers through fuel clauses in Texas (SPP area only), Oklahoma, Louisiana, Arkansas, West Virginia (beginning July 1, 2006), Virginia (beginning September 1, 2007) and in some areas of Michigan. Where fuel clauses have been eliminated due to the transition to market pricing (Ohio effective January 1, 2001), changes in fuel costs impact earnings unless recovered in the sales price for electricity. In other state jurisdictions, (Indiana and prior to July 1, 2006 in West Virginia) where fuel clauses have been capped, frozen or suspended for a period of years, fuel costs impact earnings. The Indiana fuel clause suspension ends June 30, 2007. In West Virginia, deferred fuel accounting for over- or under-recovery began July 1, 2006.

Revenue Recognition

Regulatory Accounting

The financial statements of the Registrant Subsidiaries with cost-based rate-regulated operations (APCo, I&M, PSO and a portion of CSPCo, OPCo and SWEPCo) 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 to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period and by matching income with its passage to customers in cost-based regulated rates. Regulatory liabilities or regulatory assets are also recorded for unrealized MTM gains or losses that occur due to changes in the fair value of physical and/or financial contracts that are derivatives and that are subject to the regulated ratemaking process when realized.

When regulatory assets are probable of recovery through regulated rates, the Registrant Subsidiaries record them as assets on the balance sheet. The Registrant Subsidiaries test for probability of recovery whenever new events occur, for example, 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 earnings.

Traditional Electricity Supply and Delivery Activities

The Registrant Subsidiaries recognize revenues from retail and wholesale electricity supply sales and electricity transmission and distribution delivery services. The Registrant Subsidiaries recognize the revenues in the financial statements 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, and the AEP East companies purchase power back from the same RTO to supply power to their respective loads. These power sales and purchases are reported on a net basis as revenues in the financial statements. Other RTOs in which the Registrant Subsidiaries operate do not function in the same manner as PJM. They function as balancing organizations and not as an exchange.

Physical energy purchases including those from all RTOs that are identified as non-trading, but excluding PJM purchases described in the preceding paragraph, are accounted for on a gross basis in Purchased Electricity for Resale in the financial statements.

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

AEP’s west zone is short capacity and must purchase physical power to supply retail and at times wholesale customers. For power purchased under derivative contracts in AEP’s west zone where the AEP West companies are short capacity, they recognize as revenues the unrealized gains and losses (other than those subject to regulatory deferral) that result from measuring these contracts at fair value during the period before settlement. If the contract results in the physical delivery of power from a RTO or any other counterparty, the Registrant Subsidiaries reverse the previously recorded unrealized gains and losses from MTM valuations and record the settled amounts gross as Purchased Energy for Resale. If the contract does not result in physical delivery, the Registrant Subsidiaries reverse the previously recorded unrealized gains and losses from MTM valuations and record the settled amounts as revenues in the financial statements on a net basis.

Energy Marketing and Risk Management Activities

The Registrant Subsidiaries engage in wholesale electricity, coal, natural gas and emission allowances marketing and risk management activities focused on wholesale markets where the AEP System owns assets. The Registrant Subsidiaries’ activities include the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options, and over-the-counter options and swaps. The Registrant Subsidiaries engage in certain energy marketing and risk management transactions 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 as a normal purchase or sale. For CSPCo and OPCo, the 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 on the respective income statements. For APCo, I&M, PSO and a portion of SWEPCo, who are subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

For all of the Registrant Subsidiaries, realized gains and losses on wholesale marketing and risk management transactions are included in revenues on a net basis on the respective income statements. Unrealized MTM gains and losses are included on the respective balance sheets as Risk Management Assets or Liabilities as appropriate.

Certain qualifying wholesale marketing and risk management derivatives transactions are designated as hedges of 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 earnings, the Registrant Subsidiaries subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses on the respective income statements, within the same financial statement line item as the forecasted transaction. For CSPCo and OPCo, the ineffective portion of the gain or loss is recognized in revenues in the financial statements immediately. APCo, I&M, PSO, and a portion of SWEPCo, who are subject to cost-based regulation, defer the ineffective portion as regulatory assets (for losses) and regulatory liabilities (for gains). See “Cash Flow Hedging Strategies” section of Note 12.

Levelization of Nuclear Refueling Outage Costs

In order to match costs with nuclear refueling cycles, 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. PSO also defers tree trimming costs and amortizes the costs commensurate with recovery through a rate rider in Oklahoma.

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.

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 FIN 48. Effective with the adoption of FIN 48, 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.

Excise Taxes

The Registrant Subsidiaries, as agents for some state and local governments, 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.

Debt and Preferred Stock

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.

Where reflected in rates, redemption premiums paid to reacquire preferred stock of certain Registrant Subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and reclassified to retained earnings upon the redemption of the entire preferred stock series. The excess of par value over the costs of reacquired preferred stock for nonregulated subsidiaries is credited to retained earnings upon reacquisition.

Goodwill and Intangible Assets

SWEPCo is the only Registrant Subsidiary with an intangible asset with a finite life. SWEPCo amortizes the asset over its estimated life to its residual value (see Note 3). The Registrant Subsidiaries have no recorded goodwill or intangible assets with indefinite lives as of December 31, 2007 and 2006.

Emission Allowances

The Registrant Subsidiaries record emission allowances at cost, including the annual SO2 and NOx emission allowance entitlements received at no cost from the Federal EPA. They follow the inventory model for all allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies for all of the Registrant Subsidiaries except CSPCo who reflects allowances in Emission Allowances. Allowances with expected consumption beyond one year are included in Other Noncurrent Assets-Deferred Charges and Other. 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 Current Assets-Prepayments and Other for all the Registrant Subsidiaries except CSPCo, who reflects allowances in Emission Allowances. 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 costs and the amortization of regulatory assets for certain jurisdictions.

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

I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its Consolidated Balance Sheet. I&M records these securities at market value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Upon the issuance of FASB Staff Position 115-1 and 124-1 “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments,” I&M considers all nuclear decommissioning trust fund and spent nuclear fuel trust fund investments in unrealized loss positions to be other-than-temporary impairments because I&M does not make specific investment decisions regarding the assets held in trusts. Thus, effective in 2006, the other-than-temporary impairments are considered realized losses and will reduce the cost basis of the securities which will affect any future unrealized gain or realized gains or losses. 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 spent nuclear fuel disposal trust funds in accordance with their treatment in rates. See Note 10 for additional discussion of nuclear matters.

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).

Components of Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss) is included on the balance sheets in the common shareholder’s equity section. Accumulated Other Comprehensive Income (Loss) for the Registrant Subsidiaries as of December 31, 2007 and 2006 is shown in the following table.

	December 31,
	2007			2006
	(in thousands)
Components
Cash Flow Hedges:
APCo	$	(5,944	)	$	(2,547	)
CSPCo		(650	)		3,398
I&M		(12,151	)		(8,962	)
OPCo		1,157			7,262
PSO		(887	)		(1,070	)
SWEPCo		(6,021	)		(6,410	)

Pension and OPEB Funded Status:
APCo	$	(29,243	)	$	(52,244	)
CSPCo		(18,144	)		(25,386	)
I&M		(3,524	)		(6,089	)
OPCo		(37,698	)		(64,025	)
SWEPCo		(10,418	)		(12,389	)

Earnings Per Share (EPS)

APCo, CSPCo, I&M and OPCo are wholly-owned subsidiaries of AEP and PSO and SWEPCo are owned by a wholly-owned subsidiary of AEP, therefore, none are required to report EPS.

Reclassifications

Certain prior period financial statement items have been reclassified to conform to current period presentation. These reclassifications had no impact on the Registrant Subsidiaries’ previously reported results of operations or changes in shareholders’ equity.

2.	NEW ACCOUNTING PRONOUNCEMENTS, EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE

NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, management thoroughly review the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following represents a summary of new final pronouncements that management has determined relate to the Registrant Subsidiaries’ operations.

SFAS 141 (revised 2007) “Business Combinations” (SFAS 141R)

In December 2007, the FASB issued SFAS 141R, improving financial reporting about business combinations and their effects. It establishes how the acquiring entity recognizes and measures the identifiable assets acquired, liabilities assumed, goodwill acquired, any gain on bargain purchases and any noncontrolling interest in the acquired entity. SFAS 141R no longer allows acquisition-related costs to be included in the cost of the business combination, but rather expensed in the periods they are incurred, with the exception of the costs to issue debt or equity securities which shall be recognized in accordance with other applicable GAAP. SFAS 141R requires disclosure of information for a business combination that occurs during the accounting period or prior to the issuance of the financial statements for the accounting period.

SFAS 141R is effective prospectively for business combinations with an acquisition date on or after the beginning of the first annual reporting period after December 15, 2008. Early adoption is prohibited. The Registrant Subsidiaries will adopt SFAS 141R effective January 1, 2009 and apply it to any business combinations on or after that date.

SFAS 157 “Fair Value Measurements” (SFAS 157)

In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-1 “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” which amends SFAS 157 to exclude SFAS 13 “Accounting for Leases” and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13.

In February 2008, the FASB issued FSP FAS 157-2 “Effective Date of FASB Statement No. 157” which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).

The Registrant Subsidiaries partially adopted SFAS 157 effective January 1, 2008. The Registrant Subsidiaries will adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP FAS 157-2. The provisions of SFAS 157 are applied prospectively, except for a) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, b) existing hybrid financial instruments measured initially at fair value using the transaction price and c) blockage discount factors. Although the statement is applied prospectively upon adoption, in accordance with the provisions of SFAS 157 related to EITF 02-3, certain Registrant Subsidiaries recorded an immaterial transition adjustment to beginning retained earnings. The impact of considering AEP’s own credit risk when measuring the fair value of liabilities, including derivatives, had an immaterial impact on fair value measurements upon adoption.

SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159)

In February 2007, the FASB issued SFAS 159, permitting entities to choose to measure many financial instruments and certain other items at fair value. The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities. If the fair value option is elected, the effect of the first remeasurement to fair value is reported as a cumulative effect adjustment to the opening balance of retained earnings. The statement is applied prospectively upon adoption.

The Registrant Subsidiaries adopted SFAS 159 effective January 1, 2008. At adoption, the Registrant Subsidiaries did not elect the fair value option for any assets or liabilities.

SFAS 160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS 160)

SFAS 160 is effective for interim and annual periods in fiscal years beginning after December 15, 2008. The statement is applied prospectively upon adoption. Early adoption is prohibited. Upon adoption, prior period financial statements will be restated for the presentation of the noncontrolling interest for comparability. Although management has not completed its analysis, management expects that the adoption of this standard will have an immaterial impact on the financial statements. The Registrant Subsidiaries will adopt SFAS 160 effective January 1, 2009.

EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements”

(EITF 06-10)

In March 2007, the FASB ratified EITF 06-10, a consensus on collateral assignment split-dollar life insurance arrangements in which an employee owns and controls the insurance policy. Under EITF 06-10, an employer should recognize a liability for the postretirement benefit related to a collateral assignment split-dollar life insurance arrangement in accordance with SFAS 106 “Employers' Accounting for Postretirement Benefits Other Than Pension” or Accounting Principles Board Opinion No. 12 “Omnibus Opinion – 1967” if the employer has agreed to maintain a life insurance policy during the employee's retirement or to provide the employee with a death benefit based on a substantive arrangement with the employee. In addition, an employer should recognize and measure an asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement. EITF 06-10 requires recognition of the effects of its application as either (a) a change in accounting principle through a cumulative effect adjustment to retained earnings or other components of equity or net assets in the statement of financial position at the beginning of the year of adoption or (b) a change in accounting principle through retrospective application to all prior periods. The Registrant Subsidiaries adopted EITF 06-10 effective January 1, 2008 with an immaterial effect on their financial statements.

EITF Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards”

(EITF 06-11)

In June 2007, the FASB ratified the EITF consensus on the treatment of income tax benefits of dividends on employee share-based compensation. The issue is how a company should recognize the income tax benefit received on dividends that are paid to employees holding equity-classified nonvested shares, equity-classified nonvested share units or equity-classified outstanding share options and charged to retained earnings under SFAS 123R, “Share-Based Payments.” Under EITF 06-11, a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and are paid to employees for equity-classified nonvested equity shares, nonvested equity share units and outstanding equity share options should be recognized as an increase to additional paid-in capital.

The Registrant Subsidiaries adopted EITF 06-11 effective January 1, 2008. EITF 06-11 is applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years after September 15, 2007. The adoption of this standard will have an immaterial impact on the financial statements.

FIN 48 “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 “Definition of

Settlement in FASB Interpretation No. 48” (FIN 48)

In July 2006, the FASB issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” and in May 2007, the FASB issued FASB Staff Position FIN 48-1 “Definition of Settlement in FASB Interpretation No. 48.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold (whether a tax position is more likely than not to be sustained) without which, the benefit of that position is not recognized in the financial statements. It requires a measurement determination for recognized tax positions based on the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

FIN 48 requires that the cumulative effect of applying this interpretation be reported and disclosed as an adjustment to the opening balance of retained earnings for that fiscal year and presented separately. The Registrant Subsidiaries adopted FIN 48 effective January 1, 2007. The impact of this interpretation was an unfavorable (favorable) adjustment to retained earnings as follows:

Company	(in thousands)
APCo	$	2,685
CSPCo		3,022
I&M		(327	)
OPCo		5,380
PSO		386
SWEPCo		1,642

FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)

In April 2007, the FASB issued FIN 39-1. It amends FASB Interpretation No. 39 “Offsetting of Amounts Related to Certain Contracts” by replacing the interpretation’s definition of contracts with the definition of derivative instruments per SFAS 133. It also requires entities that offset fair values of derivatives with the same party under a netting agreement to also net the fair values (or approximate fair values) of related cash collateral. The entities must disclose whether or not they offset fair values of derivatives and related cash collateral and amounts recognized for cash collateral payables and receivables at the end of each reporting period.

The Registrant Subsidiaries adopted FIN 39-1 effective January 1, 2008. This standard changed the method of netting certain balance sheet amounts and reduced assets and liabilities by an immaterial amount. It requires retrospective application as a change in accounting principle for all periods presented.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by FASB, 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, liabilities and equity, derivatives disclosures, emission allowances, leases, insurance, subsequent events and related tax impacts. Management also expects to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP. The ultimate pronouncements resulting from these and future projects could have an impact on future results of operations and financial position.

EXTRAORDINARY ITEM

Virginia Restructuring

In April 2007, Virginia passed legislation to reestablish regulation for retail generation and supply of electricity. As a result, APCo recorded an extraordinary loss of $118 million ($79 million, net of tax) in 2007 for the reestablishment of regulatory assets and liabilities related to Virginia retail generation and supply operations. In 2000, APCo discontinued SFAS 71 regulatory accounting in the Virginia jurisdiction for retail generation and supply operations due to the passage of legislation for customer choice and deregulation. See “Virginia Restructuring” section of Note 4.

CUMULATIVE EFFECT OF ACCOUNTING CHANGE

Asset Retirement Obligations

In 2005, certain Registrant Subsidiaries recorded a net of tax loss as a cumulative effect of accounting change for ARO in accordance with FIN 47. The following is a summary by Registrant Subsidiary of the cumulative effect of changes in accounting principles recorded in 2005 for the adoption of FIN 47 (no effect on I&M or PSO):

	FIN 47 Cumulative Effect
	Pretax Loss				Net of Tax Loss
Company	(in thousands)
APCo		$	(3,470	)		$	(2,256	)
CSPCo			(1,292	)			(839	)
OPCo			(7,039	)			(4,575	)
SWEPCo			(1,926	)			(1,252	)

3.	GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

There is no goodwill carried by any of the Registrant Subsidiaries.

Other Intangible Assets

SWEPCo’s acquired intangible asset subject to amortization is $9.9 million at December 31, 2007 and $12.8 million at December 31, 2006, net of accumulated amortization and is included in Deferred Charges and Other on SWEPCo’s Consolidated Balance Sheets. The amortization life, gross carrying amount and accumulated amortization are:

		December 31,
		2007				2006
	Amortization Life	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
	(in years)	(in millions)				(in millions)
Advanced Royalties	10	$	29.4	$	19.5	$	29.4	$	16.6

Amortization of the intangible asset was $3 million per year for 2007, 2006 and 2005. SWEPCo’s estimated total amortization is $1.1 million per year for 2008 through 2016, when the asset will be fully amortized with no residual value.

The Advanced Royalties asset class relates to the lignite mine of Dolet Hills Lignite Company, a wholly-owned subsidiary of SWEPCo. In 2008, SWEPCo expects to receive an order from the LPSC that will extend the useful life of the mine for an additional six years, which is factored in the estimates noted above.

The Registrant Subsidiaries have no intangible assets that are not subject to amortization.

4.	RATE MATTERS

The Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. This note is a discussion of rate matters and industry restructuring related proceedings that could have a material effect on the results of operations and cash flows.

Ohio Rate Matters

Ohio Restructuring and Rate Stabilization Plans – Affecting CSPCo and OPCo

CSPCo and OPCo have three automatic annual generation rate increases of 3% and 7%, respectively, the last of which became effective January 1, 2008. The RSP also allows additional annual generation rate increases of up to an average of 4% per year to recover new governmentally-mandated costs.

In March 2007, CSPCo also filed an application under the average 4% generation rate provision of its RSP to adjust the Power Acquisition Rider (PAR) related to CSPCo's acquisition of Monongahela Power Company's certified territory in Ohio. The PAR was increased to recover the cost of a new purchase power market contract to serve the load for that service territory. The PUCO approved this requested increase, which increased CSPCo's revenues by $22 million in 2007, and is expected to increase 2008 revenues by $38 million.

In May 2007, the PUCO approved a settlement agreement resolving the Ohio Supreme Court's remand of the PUCO’s RSP order. The settling parties agreed to have CSPCo and OPCo take bids for Renewable Energy Certificates (RECs). Under the approved settlement, CSPCo and OPCo will give customers the option to pay a generation rate premium that would encourage the development of renewable energy sources by reimbursing CSPCo and OPCo for the cost of the RECs.

In May 2007, CSPCo and OPCo implemented proposed increases from the average 4% proceeding of $24 million and $8 million, respectively, subject to refund. In October 2007, the PUCO issued an order that granted CSPCo and OPCo an annual increase of $19 million and $4 million, respectively. In September 2007, CSPCo and OPCo recorded a provision to refund the over-collected revenues.

On January 30, 2008, the PUCO approved a settlement agreement among CSPCo, OPCo and other parties related to an additional average 4% generation rate increase and TCRR adjustments for additional governmentally-mandated costs including increased environmental costs and PJM’s revision of its pricing methodology for transmission line losses. Under the settlement, the PUCO approved recovery through the TCRR increased PJM costs associated with transmission line losses of $39 million each for CSPCo and OPCo. As a result, CSPCo and OPCo established regulatory assets in the first quarter of 2008 of $12 million and $14 million, respectively, related to increased PJM costs from June 2007 to December 2007. See the “PJM Marginal-Loss Pricing” in the “FERC Rate Matters” section of this note. The PUCO also approved a credit applied to the TCRR of $10 million for OPCo and $8 million for CSPCo for PJM net congestion costs. To the extent that collections for the TCRR items are over/under actual net costs, CSPCo and OPCo will adjust billings to reflect actual costs including carrying costs. Under the terms of the settlement, although the increased PJM costs associated with transmission line losses will be recovered through the TCRR, these recoveries will still be applied to reduce the annual average 4% generation rate increase limitation. In addition, the PUCO approved recoveries of environmental costs and related carrying costs of $29 million for CSPCo and $5 million for OPCo. These rate adjustments have been implemented effective February 2008.

As permitted by the current Ohio restructuring legislation, CSPCo and OPCo can implement market-based rates effective January 2009, following the expiration of their RSPs on December 31, 2008. The RSP plans include generation rates which are between cost and higher market rates. In August 2007, legislation was introduced that would limit CSPCo’s and OPCo’s ability to charge market-based rates for generation at the expiration of their RSPs. The Ohio Senate passed legislation and it is being considered by the Ohio House of Representatives. Management continues to analyze the proposed legislation and is working with various stakeholders to achieve a principled, fair and well-considered approach to electric supply pricing. At this time, management is unable to predict whether CSPCo and OPCo will transition to market pricing, extend their RSP rates, with or without modification, or become subject to a legislative reinstatement of some form of cost-based regulation for their generation supply business on January 1, 2009. The return to cost-based regulation could cause the generation business of CSPCo and OPCo, in whole or in part, to meet the criteria for application of SFAS 71. If CSPCo and OPCo are required to reestablish certain net regulatory liabilities applicable to their generation business, it could result in an extraordinary item and a decrease in future results of operations and financial condition.

Customer Choice Deferrals – Affecting CSPCo and OPCo

CSPCo’s and OPCo’s restructuring settlement agreement, approved by the PUCO in 2000, allow CSPCo and OPCo to establish regulatory assets for customer choice implementation costs and related carrying costs in excess of $20 million each for recovery in the next general base rate filing for the distribution business. Through December 31, 2007, CSPCo and OPCo incurred $53 million and $54 million, respectively, of such costs and established regulatory assets for future recovery of $26 million each, net of equity carrying costs of $7 million for CSPCo and $8 million for OPCo. Management believes that these costs were prudently incurred to implement customer choice in Ohio and are probable of recovery in future distribution rates. However, failure of the PUCO to ultimately approve recovery of such costs would have an adverse effect on results of operations and cash flows.

Ohio IGCC Plant – Affecting CSPCo and OPCo

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a 629 MW IGCC power plant using clean-coal technology. The application proposed three phases of cost recovery associated with the IGCC plant: Phase 1, recovery of $24 million in pre-construction costs; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery or refund in distribution rates of any difference between the market-based standard service offer price for generation and the cost of operating and maintaining the plant, including a return on and return of the projected cost to construct the plant.

In June 2006, the PUCO issued an order approving a tariff to recover Phase 1 pre-construction costs over a period of no more than twelve months effective July 1, 2006. During that period CSPCo and OPCo each collected $12 million in preconstruction costs. The recoveries were applied against the average 4% limit on additional generation rate increases CSPCo and OPCo could request under their RSPs.

If CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant within five years of the June 2006 PUCO order, all Phase 1 costs associated with items that may be utilized in projects at other sites, must be refunded to Ohio ratepayers with interest. The PUCO deferred ruling on cost recovery for Phases 2 and 3 pending further hearings.

In August 2006, intervenors filed four separate appeals of the PUCO’s order in the IGCC proceeding. The Ohio Supreme Court heard oral arguments for these appeals in October 2007. Management believes that the PUCO’s authorization to collect Phase 1 preconstruction costs is lawful. Management, however, cannot predict the outcome of these appeals. If the PUCO’s order is found to be unlawful, CSPCo and OPCo could be required to refund the $12 million each has collected in Phase 1 preconstruction costs which would have an adverse effect on future results of operations and cash flows.

Pending the outcome of the Supreme Court litigation, CSPCo and OPCo announced they would delay the start of construction of the IGCC plant. Recent estimates of the cost to build the proposed IGCC plant are approximately $2.7 billion. If the commencement of construction is delayed beyond 2011, CSPCo and OPCo may need to request from the PUCO an extension of the deadline to commence construction of the IGCC plant.

Transmission Rate Filing – Affecting CSPCo and OPCo

In accordance with the RSPs, in December 2005, the PUCO approved the recovery of certain RTO transmission costs through separate transmission cost recovery riders (“TCRR”) for the Ohio companies. The TCRRs are subject to an annual true-up process. In October 2007, CSPCo and OPCo proposed increases in annual TCRR revenue of $55 million and $59 million, respectively, due to the under-recovery of costs in 2007, carrying costs on that under-recovery and escalating 2008 transmission costs. The PUCO approved this request and the new TCRR became effective at the start of the January 2008 billing cycle. See “Ohio Restructuring and Rate Stabilization Plans” above for a discussion of the settlement agreement which resulted in an additional adjustment to the TCRR.

Ormet – Affecting CSPCo and OPCo

Effective January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial customer with a 520 MW load, in accordance with a settlement agreement approved by the PUCO. The settlement agreement allows for the recovery in 2007 and 2008 of the difference between the $43 per MWH Ormet pays for power and a PUCO-approved market price, if higher. The PUCO approved a $47.69 per MWH market price for 2007. The recovery generally will be accomplished by the amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo) excess deferred tax regulatory liability resulting from an Ohio franchise tax phase-out recorded in 2005.

CSPCo and OPCo each amortized $7 million of this regulatory liability to income through December 31, 2007. In December 2007, CSPCo and OPCo submitted a market price of $53.03 per MWH for 2008. If the PUCO approves a market price for 2008 below the 2007 price, it could have an adverse effect on future results of operations and cash flows. If CSPCo and OPCo serve the Ormet load after 2008 without any special provisions, they could experience incremental costs to acquire additional capacity to meet their reserve requirements and/or forgo off-system sales margins.

Texas Rate Matters

Texas Restructuring – SPP – Affecting SWEPCo

In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in the SPP area of Texas until no sooner than January 1, 2011. This extension impacts SWEPCo’s Texas service territory.

SWEPCo Fuel Reconciliation – Texas – Affecting SWEPCo

In June 2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its Texas retail operations for the three-year reconciliation period ended December 31, 2005 seeking to recover under-recoveries of $50 million. In June 2007, an ALJ issued a proposal for decision recommending a $17 million disallowance. Results of operations for the second quarter of 2007 were adversely affected by $25 million to reflect the ALJ’s decision, which applied to items in the reconciliation period and subsequent periods through 2007. The PUCT issued an order in August 2007 adopting the ALJ’s recommendation; however, in response to a SWEPCo motion for rehearing, the PUCT clarified the rationale for crediting to fuel certain gains from sales of emissions allowances and limited the application to gains realized through June 15, 2006. As a result, in the fourth quarter of 2007 SWEPCo reversed $7 million of its provision which related to gains from sales of emissions allowances subsequent to June 15, 2006.

Stall Unit – Affecting SWEPCo

See “Stall Unit” section within Louisiana Rate Matters for disclosure.

Turk Plant – Affecting SWEPCo

See “Turk Plant” section within Arkansas Rate Matters for disclosure.

Virginia Rate Matters

Virginia Restructuring – Affecting APCo

With the new re-regulation legislation, APCo’s generation business again met the criteria for application of regulatory accounting principles under SFAS 71. APCo reapplied SFAS 71 in the second quarter of 2007 and recorded an extraordinary pretax reduction in its earnings and shareholder’s equity of $118 million ($79 million, net of tax). This extraordinary net loss relates to the reestablishment of $139 million in net generation-related customer-provided removal costs as a regulatory liability, offset by the restoration of $21 million of deferred state income taxes as a regulatory asset. In addition, APCo established a regulatory asset of $17 million for qualifying SFAS 158 pension costs of the generation operations that, for ratemaking purposes, are deferred for future recovery under the new re-regulation legislation. As a result, AOCI and Deferred Income Taxes increased by $11 million and $6 million, respectively.

Virginia Base Rate Case – Affecting APCo

In May 2006, APCo filed a request with the Virginia SCC seeking a net base rate increase of $198 million based on a return on equity of 11.5%. Pursuant to APCo’s request, the Virginia SCC issued an order placing the net requested base rate increase of $198 million into effect on October 2, 2006, subject to refund.

In May 2007, the Virginia SCC issued a final order approving an overall annual base rate increase of $24 million effective as of October 2006 based on a return on equity of 10.0%. The final order resulted in a $9 million net deferral of ARO costs to be recovered over 10 years, an $11 million annual decrease in depreciation expense retroactive to January 1, 2006 and implemented a base rate off-system sales margin credit equal to 100% of estimated off-system sales margins. APCo completed a $127 million refund in August 2007 for the difference between the requested and approved rates. As a result of a Virginia SCC decision to limit the inclusion of incremental E&R costs through June 30, 2006 in new base rates, APCo will continue to defer for future recovery unrecovered incremental E&R costs incurred through 2008 utilizing the E&R surcharge mechanism. APCo estimates the new base rates will increase annual pretax income by $34 million.

Virginia E&R Costs Recovery Filing – Affecting APCo

In July 2007, APCo filed a request with the Virginia SCC seeking recovery over the twelve months beginning December 1, 2007 of approximately $60 million of unrecovered incremental E&R costs based on a return of equity of 12% and inclusive of carrying costs for the period from October 1, 2005 through September 30, 2006. In December 2007, the Virginia SCC issued a final order approving the recovery of $49 million of deferred incremental E&R costs over a twelve month period beginning January 1, 2008 based on a 9.9% return on equity and denied APCo’s request for carrying costs on the unrecovered incremental E&R costs.

APCo recovered $26 million of incremental E&R costs in the rider that ended on November 30, 2007. As of December 31, 2007, APCo has deferred $82 million of incremental E&R costs to be recovered through current and future E&R surcharges. APCo has not recognized $19 million of E&R equity carrying charges, which are recognizable when recovered. APCo intends to file in 2008 for future recovery of incremental E&R costs incurred subsequent to September 30, 2006.

Virginia Fuel Clause Filing – Affecting APCo

In July 2007, APCo filed an application with the Virginia SCC to seek an annualized increase, effective September 1, 2007, of $33 million for fuel costs and sharing of off-system sales, consistent with the minimum 25% retention of off-system sales margins provision of the new re-regulation legislation. The sharing requirement in the new law also includes a true-up of off-system sales credits provided to customers to actual off-system sales margins.

Pursuant to APCo’s request, the Virginia SCC issued an order in August 2007 that implemented APCo’s proposed termination of its base rate off-system sales margin rider on an interim basis, subject to refund, on September 1, 2007. The order also implemented APCo’s proposed new fuel factor on an interim basis, effective September 1, 2007, which includes a credit for the sharing of 75% of off-system sales margins with customers in compliance with the new law.

In December 2007, APCo filed supplemental testimony requesting to defer for future recovery the increased transmission costs related to PJM’s revision of its pricing methodology for transmission line losses to marginal-loss pricing which became effective June 1, 2007. The request did not change the requested actual fuel rate. Through December 31, 2007, APCo deferred $14 million of such increased costs for future recovery related to the Virginia jurisdiction. See the “PJM Marginal-Loss Pricing” in the “FERC Rate Matters” section of this note.

In February 2008, the Virginia SCC issued an order that approved a reduced fuel factor effective with the February 2008 billing cycle. The adjusted factor will increase annual revenues by $4 million. The order permanently terminated the off-system sales margin rider and approved the 75%-25% sharing of off-system sales margins between customers and APCo effective September 1, 2007. The order also allows APCo to include in its monthly under/over recovery deferrals its Virginia jurisdictional share of PJM transmission line loss allocated to it effective back to June 1, 2007. The order authorized the Virginia SCC staff and other parties to make specific recommendations to the Virginia SCC in APCo’s next fuel factor proceeding in the fourth quarter of 2008 to ensure accurate assignment of the prudently incurred PJM transmission line loss costs to APCo’s Virginia jurisdictional operations. APCo believes the incurred PJM transmission line loss costs are prudently incurred and are being properly assigned to APCo’s Virginia jurisdictional operations. However, if the amount of such costs included in APCo’s Virginia fuel under/over recovery deferrals is revised by the Virginia SCC in APCo’s next fuel factor proceeding, it could, if applied retroactively, result in a change to the recoverable deferred fuel balance which would affect future results of operations and cash flows.

APCo’s Virginia SCC Filing for the West Virginia IGCC Plant – Affecting APCo

In July 2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to recover initial costs associated with a proposed 629 MW IGCC plant to be constructed in Mason County, West Virginia adjacent to APCo’s existing Mountaineer Generating Station for an estimated cost of $2.2 billion. The filing requests recovery of an estimated $45 million over twelve months beginning January 1, 2009 including a return on projected construction work in progress and development, design and planning preconstruction costs incurred from July 1, 2007 through December 31, 2009. APCo is requesting authorization to defer a return on deferred preconstruction costs incurred beginning July 1, 2007 until such costs are recovered. Through December 31, 2007, APCo deferred for future recovery in Virginia preconstruction IGCC costs totaling $6 million. The rate adjustment clause provisions of the new re-regulation legislation provide for full recovery of all costs of the proposed plant including recovery of an enhanced return on equity. The Virginia SCC held a hearing in February 2008 and an order is due in April 2008. If the plant is not built and these costs are not recoverable, it would have an adverse effect on future results of operations and cash flows.

West Virginia Rate Matters

APCo Expanded Net Energy Cost (ENEC) Filing – Affecting APCo

In April 2007, the WVPSC issued an order establishing an investigation and hearing concerning APCo’s and WPCo’s 2007 ENEC compliance filing. The ENEC is an expanded form of fuel clause mechanism, which includes all energy-related costs including fuel, purchased power expenses, off-system sales credits and other energy/transmission items. APCo filed for an increase of approximately $91 million including a $65 million increase in the ENEC itself and a $26 million increase in a related construction cost surcharges to become effective July 1, 2007. In June 2007, the WVPSC approved a settlement agreement, which provided for an increase in annual non-base revenues of approximately $77 million effective July 1, 2007. This annual revenue increase includes a $50 million ENEC increase and a $26 million construction cost surcharge increase.

The ENEC portion of the increase is subject to a true-up to actual and should have no earnings effect due to the deferral of any over/under-recovery of actual ENEC costs.

APCo’s West Virginia IGCC Plant Filing – Affecting APCo

In January 2006, APCo filed a petition with the WVPSC requesting its approval of a Certificate of Public Convenience and Necessity (CCN) to construct a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason County, WV.

In June 2007, APCo filed testimony with the WVPSC supporting the requests for a CCN and for pre-approval of a surcharge rate mechanism to provide for the timely recovery of both pre-construction costs and the ongoing finance costs of the project during the construction period as well as the capital costs, operating costs and a return on equity once the facility is placed into commercial operation. The WVPSC held hearings on the requests in December 2007. If APCo receives all necessary approvals, the plant could be completed as early as mid-2012. At the time of the filing, the cost of the plant was estimated at $2.2 billion. The statutory deadline for the WVPSC to act on APCo’s request is March 2008. Through December 31, 2007, APCo deferred for future recovery in West Virginia preconstruction IGCC costs totaling $6 million. If the plant is not built and these costs are not recoverable, it would have an adverse effect on future results of operations and cash flows.

Indiana Rate Matters

Indiana Depreciation Study Filing – Affecting I&M

In February 2007, I&M filed a request with the IURC for approval of revised book depreciation rates effective January 1, 2007. I&M recommended a decrease in pretax annual depreciation expense on an Indiana jurisdictional basis of approximately $69 million reflecting an NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and 2 and an extension of the service life of the Tanners Creek coal-fired generating units. This petition was not a request for a change in customers’ electric service rates. The filing included a settlement agreement that provided for direct benefits to I&M's customers if new lower book depreciation rates were approved by the IURC. The direct benefits included a $5 million credit to fuel costs and an approximate $8 million smart metering pilot program. In addition, if the agreement were approved, I&M would initiate a general rate proceeding on or before July 1, 2007.

In June 2007, the IURC approved the settlement agreement, but modified the effective date of the new book depreciation rates to the date I&M filed a general rate petition. I&M filed its rate petition in June 2007 and reduced its book depreciation rates as agreed in the settlement agreement resulting in an increase of $37 million in pretax earnings through December 31, 2007. The $37 million increase was partially offset by a $5 million regulatory liability, recorded in June 2007, to provide for the agreed-upon fuel credit. I&M’s approved book depreciation rates are subject to further review in the general rate case.

Indiana Rate Filing – Affecting I&M

In January 2008, I&M filed for an increase in its Indiana base rates of $82 million including a return on equity of 11.5%. The base rate increase includes a previously approved $69 million reduction in depreciation. The filing requests trackers for certain variable components of the cost of service including PJM RTO costs, reliability enhancement costs, demand side management/energy efficiency costs, off-system sales margins and net environmental compliance costs. The trackers would increase annual revenues by $46 million. I&M proposes to share 50% of an estimated $96 million of off-system sales margins with ratepayers with a guaranteed minimum of $20 million. A decision is expected from the IURC in early 2009.

Michigan Rate Matters

Michigan Restructuring – Affecting I&M

Customer choice commenced for I&M’s Michigan customers on January 1, 2002. Effective on that date, the rates on I&M’s Michigan customers’ bills for retail electric service were unbundled to allow customers the opportunity to evaluate the cost of generation service for comparison with other offers. I&M’s total base rates in Michigan remain unchanged and reflect cost of service. As of December 31, 2007, none of I&M’s customers elected to change suppliers and no alternative electric suppliers are registered to compete in I&M’s Michigan service territory. As a result, management concluded that as of December 31, 2007, the requirements to apply SFAS 71 continue to be met since I&M’s rates for generation in Michigan continue to be cost-based regulated.

Michigan Depreciation Study Filing – Affecting I&M

In December 2006, I&M filed a depreciation study in Michigan seeking to reduce its book depreciation rates. In September 2007, the Michigan Public Service Commission (MPSC) approved a settlement agreement authorizing I&M to implement new book depreciation rates. I&M agreed to decrease pretax annual book depreciation expense, on a Michigan jurisdictional basis, by approximately $10 million a year starting on October 1, 2007. This petition was not a request for a change in Michigan retail customers’ electric service rates. In addition, pursuant to FERC-approved wholesale power sale agreements, I&M will decrease pretax annual book depreciation expense, on a FERC jurisdictional basis, by approximately $11 million. Pursuant to agreements, the formula rates of approximately one-half of I&M’s wholesale customer load changed commensurate with a decrease in FERC revenues in October 2007 and the wholesale rates for the remainder of I&M’s formula rate wholesale load will decrease in June 2008. As a result, results of operations will increase by approximately $12 million in 2008 and by $10 million annually thereafter until base rates are revised in Michigan. Presently, I&M has no plan to revise base rates in Michigan.

Oklahoma Rate Matters

PSO Fuel and Purchased Power and its Possible Impact on AEP East companies and AEP West companies

In 2002, PSO under-recovered $42 million of purchased power costs through its fuel clause resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In 2003, the OCC staff filed testimony recommending PSO recover $42 million of the reallocated purchased power costs over three years. Intervenors objected to allowing recovery claiming that during that same period AEP had inappropriately under allocated off-system sales credits to PSO by $37 million under a FERC-approved allocation agreement.

In 2004, an ALJ found that the OCC lacked authority to examine whether AEP deviated from the FERC-approved allocation methodology for off-system sales margins and held that any such complaints should be addressed at the FERC. In August 2007, the OCC issued an order adopting the ALJ’s recommendation that the allocation of system sales/trading margins is a FERC jurisdictional issue. In October 2007, the OCC orally directed the OCC staff to explore filing a complaint at FERC alleging the allocation of off-system sales margins to PSO is improper, which could result in an adverse effect on future results of operations and cash flows for AEP and the AEP East companies. To date, no claim has been asserted at the FERC.

In February 2006, the OCC enacted a rule, requiring the OCC to conduct prudence reviews on PSO’s generation and fuel procurement processes, practices and costs on a periodic basis. PSO filed its testimony in June 2007 covering the year 2005. The OCC Staff and intervenors filed testimony in September 2007, and hearings occurred in November 2007. The major issue raised was the alleged under allocation of off-system sales credits under the FERC-approved allocation agreements which was not jurisdictional to the OCC as previously ordered. In addition, PSO filed testimony in November 2007 covering the year 2006. Decisions for both the 2005 and 2006 prudence proceedings are expected in 2008.

In May 2007, PSO submitted a filing to the OCC to adjust its fuel/purchase power rates. In the filing, PSO netted the $42 million of under-recovered pre-2002 reallocated purchased power costs against a $48 million over-recovered fuel balance as of April 30, 2007. PSO began refunding the $6 million net over-recovered fuel/purchased power cost deferral balance beginning June 2007 effectively recovering the $42 million by May 2008. In October 2007, the OCC denied an Oklahoma Industrial Energy Consumers request for PSO to refund the $42 million being recovered.

Management cannot predict the outcome of the pending fuel and purchased power cost recovery filings and prudence reviews. However, PSO believes its fuel and purchased power procurement practices and costs are prudent and properly incurred and that it allocated off-system sales credits consistent with governing FERC-approved agreements.

Oklahoma Rate Filing – Affecting PSO

In November 2006, PSO filed a request to increase base rates with a return on equity of 11.75%. In a subsequent revised filing, PSO requested a $48 million increase in base rates. In October 2007, the OCC issued a final order providing for a $10 million annual increase in base rates with a return on equity of 10%. PSO implemented $9 million of the increase in rates in July 2007 and implemented the additional $1 million increase in rates in October 2007. The final order also provided for an estimated $10 million reduction in PSO’s annual depreciation expense. PSO estimates this base rate final order should increase PSO’s ongoing annual revenues by approximately $10 million, and have a favorable effect on pretax earnings of $20 million.

Lawton and Peaking Generation Settlement Agreement – Affecting PSO

In November 2003, Lawton Cogeneration, L.L.C. (Lawton) sought approval for a Power Supply Agreement (the Agreement) with PSO and associated avoided cost payments. The OCC approved the Agreement which was contested by PSO.

In April 2007, the OCC approved a settlement agreement among all parties resolving all issues. The settlement agreement approved a purchase fee of $35 million to be paid by PSO to Lawton and required Lawton to provide all rights to the Lawton Cogeneration Facility including permits, options and engineering studies to PSO. PSO paid the $35 million purchase fee in June 2007, abandoned the relatively high cost Lawton Cogeneration Facility and recorded the purchase fee as a regulatory asset. PSO began recovering the $35 million regulatory asset through a rider over a three-year period with a carrying charge of 8.25% which began in September 2007. In addition, PSO will recover through a rider, subject to a $135 million cost cap, all of the traditional costs associated with plant in service of its new peaking units to be located at the Southwestern Station and Riverside Station at the time these units are placed in service, currently expected to be 2008. PSO expects these units will have a substantially lower plant-in-service cost than the proposed Lawton Cogeneration Facility purchase power cost. These costs will be recovered through the rider until cost recovery occurs through base rates in a subsequent proceeding. Under the settlement, PSO agreed to file a rate case within 18 months of the beginning of recovery of the costs of the peaking units. PSO may request approval from the OCC for recovery of unexpected costs exceeding the cost cap if special circumstances occur.

Red Rock Generating Facility – Affecting PSO

In July 2006, PSO announced an agreement with Oklahoma Gas and Electric Company (OG&E) to build a 950 MW pulverized coal ultra-supercritical generating unit. PSO would own 50% of the new unit. Under the agreement OG&E would manage construction of the plant. OG&E and PSO requested preapproval to construct the Red Rock Generating Facility and to implement a recovery rider.

In October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of additional capacity by the year 2012, but denied PSO and OG&E’s applications for construction preapproval. The OCC stated that PSO failed to fully study other alternatives. Since PSO and OG&E could not obtain preapproval to build the Red Rock Generating Facility, PSO and OG&E cancelled the third party construction contract and their joint venture development contract. PSO believes the Red Rock preconstruction costs, associated contract cancellation fees and applicable carrying costs are probable of recovery and established a regulatory asset for future recovery. In December 2007, PSO made a filing requesting recovery of the $21 million regulatory asset that included associated carrying costs to date, and requested to recover future carrying costs at the weighted average cost of capital ordered in PSO’s last rate case. In the filing, PSO proposed to amortize the asset commensurate with gains from the sale of excess SO2 allowances until recovered. If a settlement agreement signed in February 2008 is approved, see the “Oklahoma 2007 Ice Storms” below, PSO will have to amend its Red Rock filing since the gains from the sale of excess SO2 allowances originally expected to offset Red Rock costs are instead expected to be fully used to offset ice storm costs in accordance with the settlement. PSO continues to believe that the prudently incurred Red Rock pre-construction and cancellation costs will be recovered. If recovery becomes no longer probable or is denied, future results of operations and cash flows would be adversely affected by the reversal of the regulatory asset. As a result of the OCC’s decision, PSO will restudy various alternative options to meet its capacity and energy needs.

Oklahoma 2007 Ice Storms – Affecting PSO

In October 2007, PSO filed with the OCC requesting recovery of $13 million of operation and maintenance expenses related to service restoration efforts after a January 2007 ice storm. PSO proposed in its application to establish a regulatory asset of $13 million and to amortize this asset coincident with gains from the sale of excess SO2 allowances until such gains provide for the full recovery of the ice storm regulatory asset. In December 2007, PSO expensed approximately $70 million of additional storm restoration costs related to a December 2007 ice storm.

In February 2008, PSO entered into a settlement with certain parties covering both ice storms and filed the settlement agreement with the OCC for approval. The settlement agreement provides for PSO to record a regulatory asset for actual ice storm operation and maintenance expenses, estimated to be $83 million, less existing deferred gains from past sales of SO2 emission allowances of $11 million. The net regulatory asset will earn a return of 10.92% on the unrecovered balance. Under the settlement agreement, PSO will apply proceeds from future sales of excess SO2 emission allowances of an estimated $26 million to recover part of the ice storm regulatory asset. PSO will recover the remaining amount of the regulatory asset plus a return of 10.92% from customers over a period of five years beginning in the fourth quarter of 2008.

Louisiana Rate Matters

Louisiana Compliance Filing and Settlement – Affecting SWEPCo

In connection with compliance filings of SWEPCo that were previously ordered to be filed with the LPSC, SWEPCo and LPSC staff signed a settlement agreement in February 2008 that prospectively resolves all issues. SWEPCo agreed to a formula rate plan (FRP) with a three-year term. Beginning August 2008, rates shall be established to allow SWEPCo to earn an adjusted return on common equity of 10.565%. The adjustments are traditional Louisiana rate filing adjustments. At this time, SWEPCo cannot estimate the rate change expected in August 2008.

If, in years two or three of the FRP, the adjusted earned return is within the range of 10.015% to 11.115%, no adjustment to rates is necessary. However, if the adjusted earned return is outside of the above-specified range, an FRP rider will be established to increase or decrease rates prospectively. If the adjusted earned return is less than 10.015%, SWEPCo will prospectively increase rates to collect 60% of the difference between 10.565% and the adjusted earned return. Alternatively, if the adjusted earned return is more than 11.115%, SWEPCo will prospectively decrease rates by 60% of the difference between the adjusted earned return and 10.565%. SWEPCo will not record over/under recoveries for refund or future recovery under this FRP.

The settlement provides for a separate credit rider prospectively decreasing Louisiana retail base rates by $5 million over the entire three year term of the FRP, which shall not affect the adjusted earned return. This separate credit rider will cease effective August 2011.

In addition, the settlement provides for an expected reduction in depreciation rates effective October 2007. In lieu of an actual reduction in rates, SWEPCo will defer as a regulatory liability the effects of the expected depreciation reduction through July 2008. SWEPCo will amortize the regulatory liability over the three year term of the FRP as a reduction to the cost of service used to determine the adjusted earned return.

SWEPCo and the LPSC staff have submitted the settlement to an ALJ and expect the LPSC to rule on the settlement in second quarter of 2008.

Stall Unit – Affecting SWEPCo

In May 2006, SWEPCo announced plans to build a new intermediate load 480 MW natural gas-fired combustion turbine combined cycle generating unit (the Stall Unit) at its existing Arsenal Hill Plant location in Shreveport, Louisiana. SWEPCo submitted the appropriate filings with the PUCT, the APSC, the LPSC and the Louisiana Department of Environmental Quality to seek approvals to construct the unit. The Stall Unit is estimated to cost $378 million, excluding AFUDC, and is expected to be in service in mid-2010. As of December 2007, SWEPCo capitalized preconstruction costs of approximately $45 million and has contractual commitments of an additional $245 million.

In March 2007, the PUCT approved SWEPCo’s need for the facility. In February 2008, the LPSC staff submitted testimony in support of the Stall Unit and one intervenor submitted testimony opposing the Stall Unit due to the increase in cost. The LPSC has hearings scheduled for April 2008 and the APSC has not established a procedural schedule at this time. If SWEPCo is not authorized to build the Stall Unit, SWEPCo would seek recovery of the capitalized preconstruction costs including any cancellation fees. If SWEPCo cannot recover its capitalized costs, including any cancellation fees, it could have an adverse effect on future results of operations and cash flows.

Turk Plant – Affecting SWEPCo

See “Turk Plant” section within Arkansas Rate Matters for disclosure.

Arkansas Rate Matters

Turk Plant – Affecting SWEPCo

In August 2006, SWEPCo announced plans to build a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas named the John W. Turk, Jr. (Turk) Plant. SWEPCo submitted filings with the APSC, the PUCT and the LPSC seeking approval of the plant. SWEPCo will own 73% of the Turk Plant and will operate the facility. During 2007, SWEPCo signed joint ownership agreements with Oklahoma Municipal Power Authority (OMPA), Arkansas Electric Cooperative Corporation (AECC) and East Texas Electric Cooperative (ETEC) for the remaining 27% of the Turk facility. The Turk Plant is estimated to cost $1.3 billion with SWEPCo’s portion estimated to cost $950 million, excluding AFUDC. If approved on a timely basis, the plant is expected to be in-service in 2012. As of December 2007, SWEPCo capitalized approximately $272 million of expenditures and has significant contractual commitments for an additional $943 million.

In November 2007, the APSC granted approval to build the plant. Certain landowners filed a notice of appeal to the Arkansas State Court of Appeals. SWEPCo is still awaiting approvals from the Arkansas Department of Environmental Quality and the U.S. Army Corps of Engineers. Both approvals are anticipated to be received in the second or third quarter of 2008. The PUCT held hearings in October 2007. In January 2008, a Texas ALJ issued a report, which concluded that SWEPCo failed to prove there was a need for the plant. The Texas ALJ recommended that SWEPCo’s application be denied. The LPSC held hearings in September 2007 in which the LPSC staff expressed support for the project. In February 2008, a Louisiana ALJ issued a report which concluded that SWEPCo has demonstrated a need for additional capacity, and that a diversified fuel mix is an important attribute that should be taken into account in an overall strategic plan. The Louisiana ALJ recommended that SWEPCo’s application be approved. SWEPCo expects decisions from the PUCT and the LPSC in the first half of 2008. If SWEPCo is not authorized to build the Turk plant, SWEPCo could incur significant cancellation fees to terminate its commitments and would be responsible to reimburse OMPA, AECC and ETEC for their share of costs. If that occurred, SWEPCo would seek recovery of its capitalized costs including any cancellation fees and joint owner reimbursements. If SWEPCo cannot recover its capitalized costs, it could have an adverse effect on future results of operations, cash flows and possibly financial condition.

Stall Unit – Affecting SWEPCo

See “Stall Unit” section within Louisiana Rate Matters for disclosure.

FERC Rate Matters

Transmission Rate Proceedings at the FERC – Affecting APCo, CSPCo, I&M and OPCo

SECA Revenue Subject to Refund

Effective December 1, 2004, AEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected load-based charges, referred to as RTO SECA, to partially mitigate the loss of T&O revenues on a temporary basis through March 31, 2006. Intervenors objected to the temporary SECA rates, raising various issues. As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund. The AEP East companies paid SECA rates to other utilities at considerably lesser amounts than they collected. If a refund is ordered, the AEP East companies would also receive refunds related to the SECA rates they paid to third parties. The AEP East companies recognized gross SECA revenues of $220 million from December 2004 through March 2006 when the SECA rates terminated leaving AEP and ultimately its internal load customers to make up the short fall in revenues. Approximately $10 million of SECA revenues billed by PJM and recognized by the AEP East companies were not collected. The AEP East companies filed a motion with the FERC to force payment of these uncollected SECA billings. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of recognized gross SECA revenues are as follows:

Company	(in millions)
APCo	$	70.2
CSPCo		38.8
I&M		41.3
OPCo		53.3

In August 2006, a FERC ALJ issued an initial decision, finding that the rate design for the recovery of SECA charges was flawed and that a large portion of the “lost revenues” reflected in the SECA rates was not recoverable. The ALJ found that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made. The ALJ also found that the unpaid SECA rates must be paid in the recommended reduced amount. As a result, SECA ratepayers are engaged with AEP in settlement discussions. Management has been advised by external FERC counsel that it is probable that the FERC will reverse the ALJ’s decision as it is contrary to two prior FERC decisions and lacks merit.

In 2006, the AEP East companies provided reserves of $37 million for net refunds for current and future SECA settlements. After reviewing existing settlements, the AEP East companies increased their reserves by an additional $5 million in December 2007. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the provision are as follows:

	2007		2006
Company	(in millions)
APCo	$	1.7	$	12.0
CSPCo		0.9		6.7
I&M		1.0		7.0
OPCo		1.3		9.1

The AEP East companies have reached settlements related to approximately $69 million of the $220 million of SECA revenues for a net refund of $3 million. The AEP East companies are also in the process of completing two settlements-in-principle on an additional $36 million of SECA revenues and expect to make net refunds of $4 million when those settlements are approved. Thus, completed and in-process settlements cover $105 million of SECA revenues and cover about $7 million of the reserve for refund, leaving approximately $115 million of contested SECA revenues and $35 million of refund reserves. However, if the ALJ’s initial decision was upheld in its entirety, it could result in a disallowance of approximately $90 million of the AEP East companies’ remaining $115 million of unsettled gross SECA revenues. Based on advice of external FERC counsel, recent settlement experience and the expectation that most of the unsettled SECA revenues will be settled, management believes that the remaining reserve of $35 million is adequate to cover all remaining settlements and any uncollectible amounts.

In September 2006, AEP filed briefs jointly with other affected companies noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part. Management believes that the FERC should reject the ALJ’s initial decision because it contradicts prior related FERC decisions, which are presently subject to rehearing. Furthermore, management believes the ALJ’s findings on key issues are largely without merit. As directed by the FERC, management is working to settle the remaining $115 million of unsettled revenues within the remaining reserve balance. Although management believes it has meritorious arguments and can settle with the remaining customers within the amount provided, management cannot predict the ultimate outcome of ongoing settlement talks and, if necessary, any future FERC proceedings or court appeals. If the FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of the remaining unsettled claims within the amount provided, it will have an adverse effect on future results of operations and cash flows.

The FERC PJM Regional Transmission Rate Proceeding

With the elimination of T&O rates and the expiration of SECA rates and after considerable administrative litigation at the FERC in which AEP sought to mitigate the effect of T&O rate elimination, the FERC failed to implement a regional rate in PJM. As a result, the AEP East companies’ retail customers incur the bulk of the cost of the existing AEP east transmission zone facilities. However, the FERC ruled that the cost of any new 500 kV and higher voltage transmission facilities built in PJM will be shared by all customers in the region. It is expected that most of the new 500 kV and higher voltage transmission facilities will be built in other zones of PJM, not AEP’s zone. The AEP East companies will need to obtain regulatory approvals for recovery of any costs of new facilities that are assigned to them. AEP had requested rehearing of this order which the FERC denied. Management expects to file an appeal. Management cannot estimate at this time what effect, if any, this order will have on the AEP East companies’ future construction of new transmission facilities, results of operations and cash flows.

The AEP East companies increased their retail rates in Ohio, Virginia and West Virginia to recover lost T&O and SECA revenues. The AEP East companies are presently recovering from retail customers, approximately 85% of the lost T&O/SECA transmission revenues of $128 million a year. I&M requested recovery of these lost revenues in its Indiana rate filing in late January 2008 but does not expect to commence recovering the new rates until early 2009. Future results of operations and cash flows will continue to be adversely affected in Indiana, Michigan and Tennessee until the remaining 15% of the lost T&O/SECA transmission revenues are recovered in retail rates.

The FERC PJM and MISO Regional Transmission Rate Proceeding

In the SECA proceedings, the FERC ordered the RTOs and transmission owners in the PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to establish a permanent transmission rate design for the Super Region effective February 1, 2008. All of the transmission owners in PJM and MISO, with the exception of AEP and one MISO transmission owner, voted to continue zonal rates in both RTOs. In September 2007, AEP filed a formal complaint proposing a highway/byway rate design be implemented for the Super Region where users pay based on their use of the transmission system. AEP argues the use of other PJM and MISO facilities by AEP is not as large as the use of AEP transmission by others in PJM and MISO. Therefore, a regional rate design change is required to recognize that the provision and use of transmission service in the Super Region is not sufficiently uniform between transmission owners and users to justify zonal rates. In January 2008, the FERC denied AEP’s complaint. Management expects to file for rehearing. Should this effort be successful, AEP would reduce future retail rates in fuel or base rate proceedings. Management is unable to predict the outcome of this case.

SPP Transmission Formula Rate Filing – Affecting PSO and SWEPCo

In June 2007, AEPSC filed revised tariffs to establish an up-to-date revenue requirement for SPP transmission services over the facilities owned by PSO and SWEPCo and to implement a transmission cost of service formula rate.

PSO and SWEPCo requested an effective date of September 1, 2007 for the revised tariff. The revised tariff will increase annual network transmission service revenues from nonaffiliated municipal and rural cooperative utilities in the AEP pricing zone of SPP. If the proposed formula rate and requested return on equity are approved, the 2008 network transmission service revenues from nonaffiliates will increase by approximately $10 million. In August 2007, the FERC issued an order conditionally accepting PSO’s and SWEPCo’s proposed formula rate, subject to a compliance filing, suspended the effective date until February 1, 2008 and established hearing and settlement judge proceedings. Multiple intervenors have protested or requested re-hearing of the order. Discovery and settlement discussions have begun. Management is unable to predict the outcome of this proceeding.

PJM Marginal-Loss Pricing – Affecting APCo, I&M, OPCo and CSPCo

In June 2007, in response to a 2006 FERC order, PJM revised its methodology for considering transmission line losses in generation dispatch and the calculation of locational marginal prices. Marginal-loss dispatch recognizes the varying delivery costs of transmitting electricity from individual generator locations to the places where customers consume the energy. Prior to the implementation of marginal-loss dispatch, PJM used average losses in dispatch and in the calculation of locational marginal prices. Locational marginal prices in PJM now include the real-time impact of transmission losses from individual sources to loads.

Due to the implementation of marginal-loss pricing, for the period June 1, 2007 through December 31, 2007, AEP experienced an increase in the cost of delivering energy from its generating plants to customer load zones, which was partially offset by cost recoveries. Management believes these additional costs should be recoverable through retail and/or cost-based wholesale rates and is deferring these incremental costs as a regulatory asset where recovery is currently probable. These incremental PJM billings for the period June through December 2007 are as follows:

PJM Billings For Marginal-Loss Pricing

(in millions)

	PJM Billings
APCo	$	34
I&M		19
OPCo		23
CSPCo		19

APCo is presently deferring these costs for future recovery in West Virginia because, based on the advice of rate counsel, it is recoverable under the West Virginia ENEC mechanism. APCo expects to make a West Virginia ENEC filing in March 2008. For Virginia, see “Virginia Fuel Clause Filing” section of this note.

I&M filed a request to increase rates in Indiana in January 2008, which includes a request to recover these incremental PJM billings prospectively commensurate with the collection of the new rate. The IURC will probably not act on I&M’s request for collection until early 2009. I&M also plans to seek recovery in Michigan.

In the first quarter of 2008, CSPCo and OPCo established regulatory assets for $12 million and $14 million, respectively, related to these incremental PJM billings expensed in 2007 to reflect the approved recovery via the TCRR. See “Ohio Restructuring and Rate Stabilization Plans” above for a discussion of the settlement agreement which resulted in the recovery of these incremental PJM costs.

Management is unable to predict whether recovery will ultimately be approved in Indiana, Michigan, Virginia and West Virginia.

AEP has initiated discussions with PJM regarding the impact it is experiencing from the change in methodology and will pursue a modification of such methodology through the appropriate PJM stakeholder processes.

5.	EFFECTS OF REGULATION

Regulatory Assets and Liabilities

Regulatory assets and liabilities are comprised of the following items:

	APCo					I&M
	December 31,					December 31,
	2007		2006		Notes	2007		2006		Notes
	(in thousands)					(in thousands)
Regulatory Assets:

Total Current Regulatory Assets – Under-recovered Fuel Costs	$	-	$	29,526	(b) (h)	$	844	$	644	(a) (h) (o)

SFAS 109 Regulatory Asset, Net (Note 13)	$	400,580	$	365,462	(a) (g)	$	106,981	$	111,035	(a) (g)
Transition Regulatory Assets – Virginia		12,734		16,978	(a) (j)		-		-
SFAS 158 Regulatory Asset (Note 9)		91,619		124,080	(a) (g)		57,517		101,673	(a) (g)
Environmental and Reliability Costs (Note 4)		81,488		58,375	(c) (n)		-		-
Unamortized Loss on Reacquired Debt		13,541		15,435	(b) (m)		18,359		20,310	(b) (m)
Cook Nuclear Plant Refueling Outage Levelization		-		-			33,891		46,864	(a) (f)
Other		52,777		41,823	(a) (g)		29,687		34,923	(c) (g)
Total Noncurrent Regulatory Assets	$	652,739	$	622,153		$	246,435	$	314,805

Regulatory Liabilities:

Total Current Regulatory Liabilities – Over-recovered Fuel Costs	$	23,637	$	11,196	(c) (h) (p)	$	5,979	$	298	(a) (h) (p)

Asset Removal Costs	$	417,087	$	200,582	(d)	$	313,014	$	293,961	(d)
Deferred Investment Tax Credits		19,284		21,164	(c) (k)		62,244		67,324	(a) (l)
Over-recovered ENEC Costs		25,110		41,395	(b) (i)		-		-
Excess ARO for Nuclear Decommissioning (Note 10)		-		-			361,599		322,746	(e)
Other		44,075		46,583	(a) (g)		52,489		69,371	(c) (g)
Total Noncurrent Regulatory Liabilities	$	505,556	$	309,724		$	789,346	$	753,402

(a)	Amount does not earn a return.
(b)	Amount effectively earns a return.
(c)	A portion of this amount effectively earns a return.
(d)	The liability for removal cost, which reduces rate base and the resultant return, will be discharged as removal costs are incurred.
(e)	This is the difference in the cumulative amount of removal costs recovered through rates and the cumulative amount of ARO as measured by applying SFAS 143. This amount earns a return, accrues monthly and will be paid when the nuclear plant is decommissioned.
(f)	Amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage.
(g)	Recovery/refund period – various periods.
(h)	Recovery/refund period – 1 year.
(i)	Recovery/refund period – up to 2 years.
(j)	Recovery/refund period – 3 years.
(k)	Recovery/refund period – up to 12 years.
(l)	Recovery/refund period – up to 79 years.
(m)	Recovery/refund period – up to 25 years.
(n)	Approximately $49 million will be recovered over a twelve month period beginning January 1, 2008 with the remaining recovery method and timing to be determined in future proceedings.
(o)	Current Regulatory Asset – Under-recovered Fuel Costs are recorded in Prepayments and Other on The Registrant Subsidiaries Consolidated Balance Sheets.
(p)	Current Regulatory Liability – Under-recovered Fuel Costs are recorded in Other on The Registrant Subsidiaries Consolidated Balance Sheets.

	CSPCo					OPCo
	December 31,					December 31,
	2007		2006		Notes	2007		2006		Notes
	(in thousands)					(in thousands)
Regulatory Assets:

SFAS 109 Regulatory Asset, Net (Note 13)	$	15,135	$	17,646	(a) (e)	$	166,011	$	158,545	(a) (e)
Transition Regulatory Assets – Ohio		49,356		97,610	(a) (f)		-		70,397	(a)
SFAS 158 Regulatory Asset (Note 9)		71,180		94,924	(a) (e)		68,062		92,729	(a) (e)
Customer Choice Deferrals (Note 4)		26,608		24,514	(b) (j)		26,867		24,330	(b) (j)
Unamortized Loss on Reacquired Debt		10,858		11,624	(b) (h)		10,116		11,782	(b) (i)
Other		62,746		51,986	(c) (e)		52,049		56,397	(c) (e)
Total Noncurrent Regulatory Assets	$	235,883	$	298,304		$	323,105	$	414,180

Regulatory Liabilities:

Asset Removal Costs	$	130,014	$	121,773	(d)	$	116,685	$	111,319	(d)
Deferred Investment Tax Credits		20,767		22,952	(a) (h)		3,859		6,447	(c) (g)
Excess Deferred State Income Taxes Due to the Phase Out of the Ohio Franchise Tax (Ormet – Note 4)		8,150		15,104	(a) (e)		34,910		41,864	(a) (e)
Other		6,704		19,219	(c) (e)		5,267		26,265	(c) (e)
Total Noncurrent Regulatory Liabilities	$	165,635	$	179,048		$	160,721	$	185,895

(a)	Amount does not earn a return.
(b)	Amount effectively earns a return.
(c)	A portion of this amount effectively earns a return.
(d)	The liability for removal cost, which reduces rate base and the resultant return, will be discharged as removal costs are incurred.
(e)	Recovery/refund period – various periods.
(f)	Recovery/refund period – 1 year.
(g)	Recovery/refund period – up to 12 years.
(h)	Recovery/refund period – up to 17 years.
(i)	Recovery/refund period – up to 31 years.
(j)	Recovery method and timing to be determined in future proceedings.

	PSO					SWEPCo
	December 31,					December 31,
	2007		2006		Notes	2007		2006		Notes
	(in thousands)					(in thousands)
Regulatory Assets:

Total Current Regulatory Assets – Under-recovered Fuel Costs	$	-	$	7,557	(b) (h)	$	5,859	$	-	(e) (h)

SFAS 109 Regulatory Asset, Net (Note 13)	$	N/A	$	N/A		$	37,614	$	35,495	(b) (f) (g)
SFAS 158 Regulatory Asset (Note 9)		63,077		73,203	(a) (g)		52,266		59,649	(a) (g)
Lawton Settlement (Note 4)		32,303		-	(b) (m)		-		-
Unrealized Loss on Forward Commitments		18,641		39,597	(a) (g)		14,465		31,093	(a) (g)
Unamortized Loss on Reacquired Debt		8,632		10,451	(b) (i)		15,569		18,175	(b) (l)
Red Rock Generating Facility (Note 4)		20,614		-	(b) (n)		-		-
Other		15,464		19,654	(a) (h)		13,703		12,008	(c) (g)
Total Noncurrent Regulatory Assets	$	158,731	$	142,905		$	133,617	$	156,420

Regulatory Liabilities:

Total Current Regulatory Liabilities – Over-recovered Fuel Costs	$	11,697	$	-	(e) (h)	$	22,879	$	26,012	(e) (h)

Asset Removal Costs	$	267,504	$	220,286	(d)	$	284,345	$	268,323	(d)
Deferred Investment Tax Credits		25,535		26,242	(a) (k)		22,859		27,022	(a) (j)
SFAS 109 Regulatory Liability, Net (Note 13)		8,795		10,706	(b) (f) (g)		N/A		N/A
Unrealized Gain on Forward Commitments		25,473		58,350	(a) (g)		19,565		44,769	(a) (g)
Other		11,481		-	(a) (n)		7,245		6,660	(c) (g)
Total Noncurrent Regulatory Liabilities	$	338,788	$	315,584		$	334,014	$	346,774

(a)	Amount does not earn a return.
(b)	Amount effectively earns a return.
(c)	Amounts are both earning and not earning a return.
(d)	The liability, which reduces rate base and the resultant return, will be discharged as removal costs are incurred.
(e)	Over/Under-recovered fuel for SWEPCo’s Arkansas and Louisiana jurisdictions does not earn a return. Texas jurisdictional amounts for SWEPCo do earn a return.
(f)	SFAS 109 Regulatory Asset/Liability, Net is presented on the Balance Sheet at net presentation.
(g)	Recovery/refund period – various periods.
(h)	Recovery/refund period – 1 year.
(i)	Recovery/refund period – up to 12 years.
(j)	Recovery/refund period – up to 10 years.
(k)	Recovery/refund period – up to 57 years.
(l)	Recovery/refund period – up to 36 years.
(m)	Recovery/refund period – 3 years
(n)	Recovery method and timing to be determined in future proceedings.

N/A	Not applicable, asset and liability are shown net.

Merger with CSW

On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned subsidiary of AEP. The key provisions of the merger rate agreements were rate reductions starting the third quarter 2000 through 2007 of $8.4 million per year in Indiana and $1.8 million per year in Michigan for I&M. Rates will remain in effect until I&M changes base rates. In January 2008, I&M filed a base rate filing in Indiana. See “Indiana Rate Filing” section of Note 4 – Rate Matters for additional information. I&M will file for new base rates in Michigan when appropriate.

6.	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 adverse effect on the financial statements.

Insurance and Potential Losses – Affecting APCo, CSPCo, 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 a South Carolina domiciled protected-cell captive insurance company together with and/or in addition to various industry mutual and commercial insurance carriers.

See Note 10 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 a nuclear incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could have a material adverse effect on results of operations, cash flows and financial condition.

COMMITMENTS

Construction and Commitments – Affecting APCo, CSPCo, 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 estimated construction expenditures by Registrant Subsidiary for 2008, 2009 and 2010:

	Estimated Construction Expenditures
	2008		2009		2010		Total
Company	(in millions)
APCo	$	726.1	$	753.2	$	628.6	$	2,107.9
CSPCo		404.2		351.0		329.8		1,085.0
I&M		385.7		440.2		380.3		1,206.2
OPCo		634.7		591.1		549.9		1,775.7
PSO		276.5		363.3		463.3		1,103.1
SWEPCo		741.0		620.0		637.6		1,998.6

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.

The Registrant Subsidiaries enter into long-term contracts to acquire fuel for electric generation and transport it to their facilities. The longest contract extends to 2017 for APCo, 2021 for CSPCo, 2014 for I&M, 2021 for OPCo, 2012 for PSO and 2029 for SWEPCo. The contracts provide for periodic price adjustments and contain various clauses that would release the Registrant Subsidiary from its obligations under certain conditions.

The Registrant Subsidiaries purchase 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. Management does not expect to incur penalty payments under these provisions that would materially affect results of operations, cash flows or financial condition.

GUARANTEES

There are certain immaterial liabilities recorded for guarantees in accordance with FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” 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

Certain Registrant Subsidiaries enter into standby letters of credit (LOCs) with third parties. These LOCs cover items such as insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. All of these LOCs were issued in the subsidiaries’ ordinary course of business. At December 31, 2007, the maximum future payments of the LOCs include $1 million and $4 million for I&M and SWEPCo, respectively, with maturities ranging from March 2008 to December 2008.

Guarantees of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of approximately $65 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 Mining Company (Sabine), an entity consolidated under FIN 46. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study, it is estimated the reserves will be depleted in 2029 with final reclamation completed by 2036, at an estimated cost of approximately $39 million. As of December 31, 2007, SWEPCo has collected approximately $33 million through a rider for final mine closure costs, which is recorded in Deferred Credits and Other on SWEPCo’s Consolidated Balance Sheets.

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

Indemnifications and Other Guarantees

Contracts

All of 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. Prior to December 31, 2007, the Registrant Subsidiaries entered into sale agreements which included indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary.

AEP East companies, PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to power purchase and sale activity conducted pursuant to the SIA.

Master Operating Lease

Certain Registrant Subsidiaries lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, the subsidiary has committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. Historically, at the end of the lease term the fair market value has been in excess of the unamortized balance. At December 31, 2007, the maximum potential loss by subsidiary for these lease agreements assuming the fair market value of the equipment is zero at the end of the lease term is as follows:

	Maximum Potential Loss
Company	(in millions)
APCo	$	9
CSPCo		4
I&M		6
OPCo		9
PSO		5
SWEPCo		6

CONTINGENCIES

Federal EPA Complaint and Notice of Violation – Affecting APCo, CSPCo, I&M, and OPCo

The Federal EPA, certain special interest groups and a number of states alleged that APCo, CSPCo, I&M and OPCo modified certain units at their coal-fired generating plants in violation of the NSR requirements of the CAA. The Federal EPA filed its complaints in U.S. District Court for the Southern District of Ohio. The alleged modifications occurred over a 20-year period.

In December 2007, the U.S. District Court approved the AEP System’s consent decree with the Federal EPA, the DOJ, the states and the special interest groups. The consent decree resolved all issues related to various parties’ claims in the NSR cases.

Under the consent decree, the AEP System agreed to annual SO2 and NOx emission caps for sixteen coal-fired power plants located in Indiana, Kentucky, Ohio, Virginia and West Virginia. In addition to completing the installation of previously announced environmental retrofit projects at many of the plants, including the installation of flue gas desulfurization (FGD or scrubbers) equipment at KPCo’s Big Sandy Plant and at OPCo’s Muskingum River Plant no later than the end of 2015, AEGCo and I&M agreed to install selective catalytic reduction (SCR) and FGD emissions control equipment on their jointly-owned Rockport Plant. Unit 1 at the Rockport Plant will be retrofit no later than the end of 2017, and Unit 2 will be retrofit no later than the end of 2019. APCo also agreed to install selective non-catalytic reduction, a NOx-reduction technology, no later than the end of 2009 at Clinch River Plant. Management agreed to operate SCRs year round during 2008 at APCo’s Mountaineer Plant, OPCo’s Muskingum River Plant and APCo’s and OPCo’s jointly-owned Amos Plant, and agreed to plant-specific SO2 emission limits for the Clinch River Plant and OPCo’s Kammer Plant.

Under the consent decree, the AEP System paid a $15 million civil penalty in 2008 and provided $36 million for environmental projects coordinated with the federal government and $24 million to the states for environmental mitigation. The Registrant Subsidiaries expensed their share of these amounts in 2007 as follows:

			Environmental		Total Expensed in
	Penalty		Mitigation Costs		September 2007
	(in thousands)
APCo	$	4,974	$	20,659	$	25,633
CSPCo		2,883		11,973		14,856
I&M		2,770		11,503		14,273
OPCo		3,355		13,935		17,290

Management believes that APCo, CSPCo, I&M and OPCo can recover any capital and operating costs of additional pollution control equipment that may be required as a result of the consent decree through future regulated rates or market prices of electricity. If they are unable to recover such costs, it would adversely affect their future results of operations, cash flows and possibly financial condition.

Cases are still pending that could affect CSPCo’s share of jointly-owned units at Beckjord (12.5% owned) and Stuart (26% owned) stations. The Stuart units, operated by Dayton Power and Light Company, are equipped with SCR and FGD controls. A trial on liability issues is scheduled for August 2008. The Court issued a 60-day stay to allow the parties to pursue settlement discussions. The Beckjord case is scheduled for a liability trial in May 2008. Beckjord is operated by Duke Energy Ohio, Inc.

Management is unable to estimate the loss or range of loss related to any contingent liability, if any, CSPCo might have for civil penalties under the CAA proceedings for these jointly-owned plants. Management is also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If CSPCo does not prevail, management believes CSPCo can recover any capital and operating costs of additional pollution control equipment that may be required through market prices for electricity. If CSPCo is unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations, cash flows and possibly financial condition.

Notice of Enforcement and Notice of Citizen Suit – Affecting SWEPCo

In March 2005, two special interest groups, Sierra Club and Public Citizen, filed a complaint in Federal District Court for the Eastern District of Texas alleging violations of the CAA at SWEPCo’s Welsh Plant. A trial in this matter was delayed until March 31, 2008 to allow the parties to pursue settlement discussions.

In 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant. In April 2005, TCEQ issued an Executive Director’s Report (Report) recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of approximately $228 thousand against SWEPCo. TCEQ filed an amended Report during the fourth quarter of 2007, eliminating certain claims and reducing the recommended penalty amount to $122 thousand. The original Report contains a recommendation limiting the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued. SWEPCo had previously requested a permit alteration to remove the reference to a specific heat input value for each Welsh unit and to clarify the sulfur content requirement for fuels consumed at the plant. A permit alteration was issued in March 2007. The Sierra Club and Public Citizen filed a motion to overturn the permit alteration. In June 2007, TCEQ denied that motion. The permit alteration has been appealed to the Travis County District Court.

On February 8, 2008, the Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in the previous state permit. The NOV also alleges that the permit alteration issued by TCEQ was improper. SWEPCo requested a meeting with the Federal EPA to discuss the alleged violations.

Management is unable to predict the timing of any future action by TCEQ, the Federal EPA or the special interest groups or the effect of such actions on results of operations, cash flows or financial condition.

Carbon Dioxide (CO2) Public Nuisance Claims – Affecting AEP East Companies and AEP West Companies

In 2004, eight states and the City of New York filed an action in federal district court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority. The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants. The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants. The dismissal of this lawsuit was appealed to the Second Circuit Court of Appeals. Briefing and oral argument have concluded. In April 2007, the U.S. Supreme Court issued a decision holding that the Federal EPA has authority to regulate emissions of CO2 and other greenhouse gases under the CAA, which may impact the Second Circuit’s analysis of these issues. The Second Circuit requested supplemental briefs addressing the impact of the Supreme Court’s decision on this case. Management believes the actions are without merit and intends to defend against the claims.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting APCo, CSPCo, 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 (PCBs) and other hazardous and nonhazardous materials. The Registrant Subsidiaries currently incur costs to safely dispose of these substances.

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. At December 31, 2007, APCo and OPCo are each named as a Potentially Responsible Party (PRP) for one site and CSPCo and I&M are each named a PRP for two sites by the Federal EPA. There are nine additional sites for which APCo, CSPCo, I&M, OPCo, and SWEPCo have received information requests which could lead to PRP designation. I&M and SWEPCo have also been named potentially liable at one site each under state law. In those instances where AEP 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 results of operations.

The Registrant Subsidiaries evaluate the potential liability for each Superfund site separately, but several general statements can be made regarding their potential future liability. Disposal of materials at a particular site is often unsubstantiated and the quantity of materials deposited at a site was 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 sites.

TEM Litigation – Affecting OPCo

OPCo agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) (now known as SUEZ Energy Marketing NA, Inc.) for a period of 20 years under a Power Purchase and Sale Agreement (PPA). Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming.

In 2003, TEM and OPCo separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. OPCo alleged that TEM breached the PPA, and sought a determination of its rights under the PPA. TEM alleged that the PPA never became enforceable, or alternatively, that the PPA was terminated as the result of OPCo’s breaches. The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided a limited guaranty.

In January 2008, OPCo reached a settlement with TEM to resolve all litigation regarding the PPA resulting in TEM paying $255 million. The proceeds did not impact OPCo’s results of operations under terms of an indemnification agreement with AEP Resources (AEPR), a nonutility subsidiary of AEP, whereby AEPR held OPCo harmless from market exposure related to the PPA. AEPR received the proceeds of this lawsuit under the terms of the indemnification agreement.

Coal Transportation Dispute – Affecting PSO

PSO, TCC, TNC, the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville, Texas, as joint owners of a generating station, disputed transportation costs for coal received between July 2000 and the present time. The joint plant remitted less than the amount billed. In September 2007, the Surface Transportation Board ruled that the disputed rates were not unreasonable under the standalone cost rate test. The joint owners filed a Petition for Reconsideration. Based upon this ruling, PSO, as operator of the plant, adjusted the provision recorded in prior periods. PSO deferred its immaterial share of the provision under its fuel mechanism after mitigation by certain contractual rights.

Coal Transportation Rate Dispute - Affecting PSO

In 1985, the Burlington Northern Railroad Co. (now BNSF) entered into a coal transportation agreement with PSO. The agreement contained a base rate subject to adjustment, a rate floor, a reopener provision and an arbitration provision. In 1992, PSO reopened the pricing provision. The parties failed to reach an agreement and the matter was arbitrated, with the arbitration panel establishing a lowered rate as of July 1, 1992 (the 1992 Rate), and modifying the rate adjustment formula. The decision did not mention the rate floor. From April 1996 through the contract termination in December 2001, the 1992 Rate exceeded the adjusted rate, determined according to the decision. PSO paid the adjusted rate and contended that the panel eliminated the rate floor. BNSF invoiced at the 1992 Rate and contended that the 1992 Rate was the new rate floor. At the end of 1991, PSO terminated the contract by paying a termination fee, as required by the agreement. BNSF contends that the termination fee should have been calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment of approximately $9.5 million, including interest.

This matter was submitted to an arbitration board. In April 2006, the arbitration board filed its decision, denying BNSF’s underpayments claim. PSO filed a request for an order confirming the arbitration award and a request for entry of judgment on the award with the U.S. District Court for the Northern District of Oklahoma. On July 14, 2006, the U.S. District Court issued an order confirming the arbitration award. On July 24, 2006, BNSF filed a Motion to Reconsider the July 14, 2006 Arbitration Confirmation Order and Final Judgment and its Motion to Vacate and Correct the Arbitration Award with the U.S. District Court. In February 2007, the U.S. District Court granted BNSF’s Motion to Reconsider. PSO filed a substantive response to BNSF’s motion and BNSF filed a reply. Management continues to defend its position that PSO paid BNSF all amounts owed.

FERC Long-term Contracts – Affecting AEP East Companies and AEP West Companies

In 2002, the FERC held a hearing related to a complaint filed by Nevada Power Company and Sierra Pacific Power Company (the Nevada utilities). The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.” The complaint alleged that AEP subsidiaries sold power at unjust and unreasonable prices because the market for power was allegedly dysfunctional at the time such contracts were executed. In 2003, the FERC rejected the complaint. In 2006, the U.S. Court of Appeals for the Ninth Circuit reversed the FERC order and remanded the case to the FERC for further proceedings. That decision was appealed and the U.S. Supreme Court decided that it will review the Ninth Circuit’s decision in 2008. Management is unable to predict the outcome of these proceedings or their impact on future results of operations and cash flows. The Registrant Subsidiaries asserted claims against certain companies that sold power to them, which was resold to the Nevada utilities, seeking to recover a portion of any amounts the Registrant Subsidiaries may owe to the Nevada utilities.

7.	COMPANY-WIDE STAFFING AND BUDGET REVIEW

The following table shows the severance benefits expense recorded in 2005 (primarily in Other Operation and Maintenance) resulting from a company-wide staffing and budget review, including the allocation of approximately $19.2 million of severance benefits expense associated with AEPSC employees. Payments and accrual adjustments recorded during 2006 were immaterial and were settled by June 30, 2006.

	Year Ended December 31, 2005
Company	(in millions)
APCo	$	4.5
CSPCo		2.6
I&M		4.7
OPCo		3.9
PSO		1.4
SWEPCo		1.8

8.	ACQUISITIONS AND ASSET IMPAIRMENT

ACQUISITIONS

2007

Darby Electric Generating Station – Affecting CSPCo

In November 2006, CSPCo agreed to purchase Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company, for $102 million and the assumption of liabilities of $2 million. CSPCo completed the purchase in April 2007. The Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple cycle power plant with a generating capacity of 480 MW.

2006

None

2005

Waterford Plant – Affecting CSPCo

In May 2005, CSPCo signed a purchase-and-sale agreement with Public Service Enterprise Group Waterford Energy LLC, a subsidiary of PSEG, for the purchase of the Waterford Plant in Waterford, Ohio. The Waterford Plant is a natural gas, combined cycle power plant with a generating capacity of 821 MW. This transaction was completed in September 2005 for $218 million and the assumption of liabilities of approximately $2 million.

Monongahela Power Company – Affecting CSPCo

In June 2005, the PUCO ordered CSPCo to explore the purchase of the Ohio service territory of Monongahela Power Company (Monongahela Power), which includes approximately 29,000 customers. In August 2005, AEP agreed to terms of a transaction, which included the transfer of Monongahela Power’s Ohio customer base and the assets, at net book value, that serve those customers to CSPCo. This transaction was completed in December 2005 for approximately $42 million and the assumption of liabilities of approximately $2 million. In addition, CSPCo paid $10 million to compensate Monongahela Power for its termination of certain litigation in Ohio. Therefore, beginning January 1, 2006, CSPCo began serving customers in this additional portion of its service territory. CSPCo’s $10 million payment was recorded as a regulatory asset and will be recovered with a carrying cost from all of CSPCo’s customers over approximately 5 years. Also included in the transaction was a power purchase agreement under which Allegheny Power, Monongahela Power’s parent company, will provide the power requirements of the acquired customers through May 31, 2007.

Ceredo Generating Station – Affecting APCo

In August 2005, APCo signed a purchase-and-sale agreement with Reliant Energy for the purchase of the Ceredo Generating Station located near Ceredo, West Virginia. The Ceredo Generating Station is a natural gas, simple cycle power plant with a generating capacity of 505 MW. This transaction was completed in December 2005 for $100 million.

ASSET IMPAIRMENT

2007 and 2006

None

2005

Conesville Units 1 and 2 – Affecting CSPCo

In the third quarter of 2005, following management’s extensive review of the commercial viability of CSPCo’s generation fleet, management committed to a plan to retire CSPCo’s Conesville Units 1 and 2 before the end of their previously estimated useful lives. As a result, Conesville Units 1 and 2 were retired as of the third quarter of 2005.

CSPCo recognized a pretax charge of approximately $39 million in 2005 related to its decision to retire the units. The impairment amount is classified in Asset Impairments and Other Related Charges on CSPCo’s 2005 Consolidated Statement of Income.

9.	BENEFIT PLANS

APCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in AEP sponsored qualified pension plans and nonqualified pension plans. A substantial majority of employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan. APCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in other postretirement benefit plans sponsored by AEP to provide medical and life insurance benefits for retired employees.

APCo, CSPCo, I&M, OPCo, PSO and SWEPCo adopted SFAS 158 as of December 31, 2006. It requires employers to fully recognize the obligations associated with defined benefit pension plans and OPEB plans, which include retiree healthcare, in their balance sheets. Previous standards required an employer to disclose the complete funded status of its plan only in the notes to the financial statements and provided that an employer delay recognition of certain changes in plan assets and obligations that affected the costs of providing benefits resulting in an asset or liability that often differed from the plan’s funded status. SFAS 158 requires a defined benefit pension or postretirement plan sponsor to (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for the plan’s underfunded status, (b) measure the plan’s assets and obligations that determine its funded status as of the end of the employer’s fiscal year and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year but are not recognized as a component of net periodic benefit cost pursuant to previous standards. It also requires an employer to disclose additional information on how delayed recognition of certain changes in the funded status of a defined benefit pension or OPEB plan affects net periodic benefit costs for the next fiscal year. APCo, CSPCo, I&M, OPCo, PSO and SWEPCo recorded a SFAS 71 regulatory asset for qualifying SFAS 158 costs of regulated operations that for ratemaking purposes will be deferred for future recovery. The effect of this standard on the 2006 financial statements was a pretax AOCI adjustment that was partially or fully offset by a SFAS 71 regulatory asset and as applicable a deferred income tax asset resulting in a net of tax AOCI equity reduction. The following table shows the amounts:

	Total Adjustment		Regulatory Asset		Deferred Income Tax		AOCI Equity Reduction
Company	(in thousands)
APCo	$	204,456	$	124,080	$	28,132	$	52,244
CSPCo		133,980		94,924		13,670		25,386
I&M		111,040		101,673		3,278		6,089
OPCo		191,229		92,729		34,475		64,025
PSO		73,203		73,203		-		-
SWEPCo		78,709		59,649		6,671		12,389

SFAS 158 requires adjustment of pretax AOCI at the end of each year, for both underfunded and overfunded defined benefit pension and OPEB plans, to an amount 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 and deferred gains result in an AOCI equity addition. The year-end AOCI measure can be volatile based on fluctuating investment returns and discount rates.

The following tables provide a reconciliation of the changes in projected benefit obligations and fair value of assets for AEP’s plans over the two-year period ending at the plan’s measurement date of December 31, 2007, and their funded status as of December 31 for each year:

Projected Pension Obligations, Plan Assets, Funded Status as of December 31, 2007 and 2006

	Pension Plans						Other Postretirement Benefit Plans
	2007			2006			2007			2006
	(in millions)
Change in Projected Benefit Obligation
Projected Obligation at January 1	$	4,108		$	4,347		$	1,818		$	1,831
Service Cost		96			97			42			39
Interest Cost		235			231			104			102
Actuarial Gain		(64	)		(293	)		(91	)		(55	)
Plan Amendments		18			2			-			-
Benefit Payments		(284	)		(276	)		(130	)		(112	)
Participant Contributions		-			-			22			21
Medicare Subsidy		-			-			8			(8	)
Projected Obligation at December 31	$	4,109		$	4,108		$	1,773		$	1,818

Change in Fair Value of Plan Assets
Fair Value of Plan Assets at January 1	$	4,346		$	4,143		$	1,302		$	1,172
Actual Return on Plan Assets		435			470			115			127
Company Contributions		7			9			91			94
Participant Contributions		-			-			22			21
Benefit Payments		(284	)		(276	)		(130	)		(112	)
Fair Value of Plan Assets at December 31	$	4,504		$	4,346		$	1,400		$	1,302

Funded (Underfunded) Status at December 31	$	395		$	238		$	(373	)	$	(516	)

Amounts Recognized on AEP’s Balance Sheets as of December 31, 2007 and 2006

	Pension Plans								Other Postretirement Benefit Plans
	2007				2006				2007				2006
	(in millions)
Employee Benefits and Pension Assets – Prepaid Benefit Costs		$	482			$	320			$	-			$	-
Other Current Liabilities – Accrued Short-term Benefit Liability			(8	)			(8	)			(4	)			(5	)
Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability			(79	)			(74	)			(369	)			(511	)
Funded (Underfunded) Status		$	395			$	238			$	(373	)		$	(516	)

SFAS 158 Amounts Recognized in AEP’s Accumulated Other Comprehensive Income (AOCI) as of December 31, 2007 and 2006

	Pension Plans					Other Postretirement Benefit Plans
	2007		2006			2007		2006
Components	(in millions)
Net Actuarial Loss	$	534	$	759		$	231	$	354
Prior Service Cost (Credit)		14		(5	)		4		4
Transition Obligation		-		-			97		124
Pretax AOCI	$	548	$	754		$	332	$	482

Recorded as
Regulatory Assets	$	453	$	582		$	204	$	293
Deferred Income Taxes		33		60			45		66
Net of Tax AOCI		62		112			83		123
Pretax AOCI	$	548	$	754		$	332	$	482

Components of the Change in AEP’s Plan Assets and Benefit Obligations Recognized in Pretax AOCI during the year ended December 31, 2007 are as follows:

					Other
					Postretirement
	Pension Plans				Benefit Plans
Components	(in millions)
2007 Actuarial Gain		$	(166	)		$	(111	)
Amortization of Actuarial Loss			(59	)			(12	)
2007 Prior Service Cost			19				-
Amortization of Transition Obligation			-				(27	)
Total 2007 Pretax AOCI Change		$	(206	)		$	(150	)

Pension and Other Postretirement Plans’ Assets

The asset allocations for AEP’s pension plans at the end of 2007 and 2006, and the target allocation for 2008, by asset category, are as follows:

	Target Allocation			Percentage of Plan Assets at Year End
	2008			2007		2006
Asset Category
Equity Securities		55	%	57	%	63	%
Real Estate		5	%	6	%	6	%
Debt Securities		39	%	36	%	26	%
Cash and Cash Equivalents		1	%	1	%	5	%
Total		100	%	100	%	100	%

The asset allocations for AEP’s other postretirement benefit plans at the end of 2007 and 2006, and target allocation for 2008, by asset category, are as follows:

	Target Allocation			Percentage of Plan Assets at Year End
	2008			2007		2006
Asset Category
Equity Securities		66	%	62	%	66	%
Debt Securities		33	%	35	%	32	%
Cash and Cash Equivalents		1	%	3	%	2	%
Total		100	%	100	%	100	%

AEP’s investment strategy for the employee benefit 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 plans’ assets relative to the plans’ liabilities. To minimize investment risk, AEP’s employee benefit trust funds are broadly diversified among classes of assets, investment strategies and investment managers. AEP regularly reviews the actual asset allocation and periodically rebalances the investments to AEP’s targeted allocation when considered appropriate. AEP’s 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 investment policies prohibit investment in AEP securities, with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies.

The value of the pension plans’ assets increased to $4.5 billion at December 31, 2007 from $4.3 billion at December 31, 2006. The qualified plans paid $277 million in benefits to plan participants during 2007 (nonqualified plans paid $7 million in benefits). The value of AEP’s Postretirement Plans’ assets increased to $1.4 billion in December 31, 2007 from $1.3 billion at December 31, 2006. The Postretirement Plans paid $130 million in benefits to plan participants during 2007.

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.

	December 31,
	2007			2006
Accumulated Benefit Obligation	(in millions)
Qualified Pension Plans		$	3,914		$	3,861
Nonqualified Pension Plans			77			78
Total		$	3,991		$	3,939

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 at December 31, 2007 and 2006 were as follows:

	Underfunded Pension Plans
	December 31,
	2007			2006
	(in millions)
Projected Benefit Obligation		$	81		$	82

Accumulated Benefit Obligation		$	77		$	78
Fair Value of Plan Assets			-			-
Accumulated Benefit Obligation Exceeds the Fair Value of Plan Assets		$	77		$	78

Actuarial Assumptions for Benefit Obligations

The weighted-average assumptions as of December 31, used in the measurement of AEP’s benefit obligations are shown in the following tables:

	Pension Plans						Other Postretirement Benefit Plans
	2007			2006			2007		2006
Assumptions
Discount Rate	6.00	%		5.75	%		6.20	%	5.85	%
Rate of Compensation Increase	5.90	%	(a)	5.90	%	(a)	N/A		N/A

(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.

N/A	= Not Applicable

To determine a discount rate, AEP uses a duration-based method by constructing a hypothetical portfolio of high quality corporate bonds similar to those included in the Moody’s Aa bond index with a duration matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.

For 2007, the rate of compensation increase assumed varies with the age of the employee, ranging from 5% per year to 11.5% per year, with an average increase of 5.9%.

Estimated Future Benefit Payments and Contributions

Information about the 2008 expected cash flows for the pension (qualified and nonqualified) and other postretirement benefit plans is as follows:

Employer Contributions	Pension Plans		Other Postretirement Benefit Plans
	(in millions)
Required Contributions (a)	$	8	$	4
Additional Discretionary Contributions		-		73

(a)	Contribution required to meet minimum funding requirement per the U.S. Department of Labor plus direct payments for unfunded benefits.

The contribution to the pension plans is based on the minimum amount required by the U.S. Department of Labor and the amount to pay unfunded nonqualified benefits. The contribution to the other postretirement benefit plans is generally based on the amount of the other postretirement benefit plans’ periodic benefit cost for accounting purposes as provided for in agreements with state regulatory authorities, plus the additional discretionary contribution of AEP’s Medicare subsidy receipts.

The table below reflects the total benefits expected to be paid from the plan or from the employer’s assets, including both the employer’s share of the benefit cost and the participants’ share of the cost, which is funded by participant contributions to the plan. Medicare subsidy receipts are shown in the year of the corresponding benefit payments, even though actual cash receipts are expected early in the following year. 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 AEP’s pension benefits and other postretirement benefits are as follows:

	Pension Plans		Other Postretirement Benefit Plans
	Pension Payments		Benefit Payments		Medicare Subsidy Receipts
	(in millions)
2008	$	356	$	111	$	(10	)
2009		362		121		(11	)
2010		363		131		(11	)
2011		363		141		(12	)
2012		368		149		(13	)
Years 2013 to 2017, in Total		1,861		864		(82	)

Components of Net Periodic Benefit Cost

The following table provides the components of AEP’s net periodic benefit cost for the plans for fiscal years 2007, 2006 and 2005:

	Pension Plans									Other Postretirement Benefit Plans
	Years Ended December 31,
	2007			2006			2005			2007			2006			2005
	(in millions)
Service Cost	$	96		$	97		$	93		$	42		$	39		$	42
Interest Cost		235			231			228			104			102			107
Expected Return on Plan Assets		(340	)		(335	)		(314	)		(104	)		(94	)		(92	)
Amortization of Transition Obligation		-			-			-			27			27			27
Amortization of Prior Service Cost		-			(1	)		(1	)		-			-			-
Amortization of Net Actuarial Loss		59			79			55			12			22			25
Net Periodic Benefit Cost		50			71			61			81			96			109
Capitalized Portion		(14	)		(21	)		(17	)		(25	)		(27	)		(33	)
Net Periodic Benefit Cost Recognized as Expense	$	36		$	50		$	44		$	56		$	69		$	76

Estimated amounts expected to be amortized to net periodic benefit costs from AEP’s pretax accumulated other comprehensive income during 2008 are shown in the following table:

	Pension Plans		Other Postretirement Benefit Plans
	(in millions)
Net Actuarial Loss	$	26	$	5
Prior Service Cost		1		1
Transition Obligation		-		27
Total Estimated 2008 Pretax AOCI Amortization	$	27	$	33

Net Benefit Cost by Registrant

The following table provides the net periodic benefit cost (credit) for the plans by Registrant Subsidiary for fiscal years 2007, 2006 and 2005:

	Pension Plans										Other Postretirement Benefit Plans
	December 31,
	2007				2006			2005			2007			2006			2005
Company	(in thousands)
APCo		$	3,367			$	5,876		$	7,391		$	14,241		$	17,953		$	20,005
CSPCo			(1,030	)			820			2,143			5,964			7,222			8,202
I&M			7,599				9,319			9,463			10,121			11,805			13,524
OPCo			1,451				3,307			4,825			11,207			13,582			15,442
PSO			1,697				3,912			295			5,722			6,352			6,989
SWEPCo			2,987				4,890			1,462			5,677			6,311			6,849

Actuarial Assumptions for Net Periodic Benefit Costs

The weighted-average assumptions as of January 1, used in the measurement of AEP’s benefit costs are shown in the following tables:

	Pension Plans						Other Postretirement Benefit Plans
	2007		2006		2005		2007		2006		2005
Discount Rate	5.75	%	5.50	%	5.50	%	5.85	%	5.65	%	5.80	%
Expected Return on Plan Assets	8.50	%	8.50	%	8.75	%	8.00	%	8.00	%	8.37	%
Rate of Compensation Increase	5.90	%	5.90	%	3.70	%	N/A		N/A		N/A

N/A = Not Applicable

The expected return on plan assets for 2007 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 health care trend rate assumptions as of January 1, used for other postretirement benefit plans measurement purposes are shown below:

Health Care Trend Rates	2007		2006
Initial	7.5	%	8.0	%
Ultimate	5.0	%	5.0	%
Year Ultimate Reached	2012		2009

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

	1% Increase			1% Decrease
	(in millions)
Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$	19		$	(16	)

Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation			185			(154	)

AEP Savings Plan

APCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in an AEP sponsored defined contribution retirement savings plans for substantially all employees who are not members of the United Mine Workers of America (UMWA). These plans offer participants an opportunity to contribute a portion of their pay, include features under Section 401(k) of the Internal Revenue Code and provide for company matching contributions. The matching contributions to the plan are 75% of the first 6% of eligible compensation contributed by the employee.

The following table provides the cost for contributions to the retirement savings plans by the Registrant Subsidiaries for fiscal years 2007, 2006 and 2005:

	Years Ended December 31,
	2007		2006		2005
Company	(in thousands)
APCo	$	7,787	$	7,471	$	6,780
CSPCo		3,442		3,224		2,929
I&M		9,075		8,764		7,892
OPCo		6,842		6,440		5,962
PSO		3,673		3,312		2,915
SWEPCo		4,623		4,284		3,935

UMWA Benefits

APCo, CSPCo 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.

The health and welfare benefits are administered by APCo, CSPCo and OPCo. Benefits are paid from their general assets. Contributions were not material in 2007, 2006 and 2005.

10.

NUCLEAR

I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by the NRC. A significant future financial commitment to safely dispose of SNF and to decommission and decontaminate the plant results from its ownership. 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. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. 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.

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 estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant ranges from $733 million to $1.3 billion in 2006 nondiscounted dollars. The most recent decommissioning study was performed in 2006. The wide range is caused by variables in assumptions. I&M recovers estimated Cook Plant decommissioning costs in its rates. The amount recovered in rates was $32 million in 2007, $30 million in 2006 and $27 million in 2005. Decommissioning costs recovered from customers are deposited in external trusts.

I&M deposited an additional $4 million in 2007, 2006 and 2005 in its decommissioning trust under funding provisions approved by regulatory commissions. At December 31, 2007, the total decommissioning trust fund balance was $1.1 billion. 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 results of operations, cash flows and possibly financial condition would be adversely affected 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. At December 31, 2007, fees and related interest of $259 million for fuel consumed prior to April 7, 1983 at the Cook Plant have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $285 million to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trust. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.

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 market value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. As discussed in the “Nuclear Trust Funds” section of Note 1, 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. The gains, losses or other-than-temporary impairments shown below did not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdictions’ liabilities. Regulatory approval is required to withdraw decommissioning funds.

The following is a summary of nuclear trust fund investments at December 31:

	December 31,
	2007										2006
	Estimated Fair Value			Gross Unrealized Gains			Other-Than- Temporary Impairments				Estimated Fair Value			Gross Unrealized Gains			Other-Than- Temporary Impairments
	(in millions)
Cash		$	22		$	-		$	-			$	24		$	-		$	-
Debt Securities			823			27			(6	)			750			18			(8	)
Equity Securities			502			205			(11	)			474			192			(4	)
Spent Nuclear Fuel and Decommissioning Trusts		$	1,347		$	232		$	(17	)		$	1,248		$	210		$	(12	)

Proceeds from sales of I&M’s nuclear trust fund investments were $696 million, $631 million and $557 million in 2007, 2006 and 2005, respectively. Purchases of I&M’s nuclear trust fund investments were $777 million, $692 million and $607 million in 2007, 2006 and 2005, respectively.

Gross realized gains from the sales of I&M’s nuclear trust fund investments were $15 million, $7 million and $4 million in 2007, 2006 and 2005, respectively. Gross realized losses from the sales of I&M’s nuclear trust fund investments were $5 million, $7 million and $16 million in 2007, 2006 and 2005, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at December 31, 2007 for I&M is as follows:

	Fair Value of Debt Securities
	(in millions)
Within 1 year	$	38
1 year – 5 years		205
5 years – 10 years		231
After 10 years		349
Total	$	823

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 extra costs resulting from a prolonged accidental outage. I&M utilizes an industry mutual insurer for the placement of this insurance coverage. I&M’s participation in this mutual insurer requires a contingent financial obligation of up to $39 million 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 $10.8 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 $300 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 $101 million on each licensed reactor in the U.S. payable in annual installments of $15 million. As a result, I&M could be assessed $202 million per nuclear incident payable in annual installments of $30 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 $300 million through commercially available insurance. The next level of liability coverage of up to $10.5 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, results of operations, cash flows and financial condition could be adversely affected.

11.	BUSINESS SEGMENTS

All of AEP’s Registrant Subsidiaries have one reportable segment, an integrated electricity generation, transmission and distribution business. All of 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.

12.	DERIVATIVES, HEDGING AND FINANCIAL INSTRUMENTS

DERIVATIVES AND HEDGING

SFAS 133 requires recognition of all qualifying derivative instruments as either assets or liabilities in the statement of financial position 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 and supply and demand market data and assumptions. The fair values determined are reduced by the appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the influence that imperfections in marketplace transparency may cause pricing to be less than or more than what the price should be based purely on supply and demand. Because energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value open long-term risk management contracts. Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract’s term and at the time a contract settles. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices are not consistent with AEP’s approach at estimating current market consensus for forward prices in the current period. This is particularly true for long-term contracts.

Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided in SFAS 133. Derivative contracts that have been designated as normal purchases or normal sales under SFAS 133 are not subject to MTM accounting treatment and are recognized on an accrual or settlement basis.

The Registrant Subsidiaries’ 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, the Registrant Subsidiaries designate a hedging instrument as a fair value hedge or cash flow hedge. For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof that is attributable to a particular risk), the Registrant Subsidiaries recognize the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item associated with the hedged risk in earnings. For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) until the period the hedged item affects earnings. The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any, is recognized immediately in earnings 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).

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 in the Registrant Financial Statements. 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.

Fair Value Hedging Strategies

At certain times the Registrant Subsidiaries enter into interest rate derivative transactions in order to manage interest rate risk exposure. These interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. The Registrant Subsidiaries record gains or losses on swaps that qualify for fair value hedge accounting treatment, as well as offsetting changes in the fair value of the debt being hedged, in Interest Expense on the statements of income. At various times during 2007, 2006 and 2005, APCo and I&M designated interest rate derivatives as fair value hedges and did not recognize any hedge ineffectiveness related to these derivative transactions.

Cash Flow Hedging Strategies

The Registrant Subsidiaries enter into, and designate as cash flow hedges, certain derivative transactions for the purchase and sale of electricity, coal and natural gas in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management closely monitors the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect margins for a portion of future electricity sales and fuel purchases. Realized gains and losses on these derivatives designated as cash flow hedges are included in Revenues or fuel expense, depending on the specific nature of the risk being hedged. The Registrant Subsidiaries do not hedge all variable price risk exposure related to energy commodities. At various times during 2007, 2006 and 2005, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo designated cash flow hedge relationships using these commodities and recognized immaterial amounts in earnings related to hedge ineffectiveness.

The Registrant Subsidiaries enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrant Subsidiaries enter into various derivative instruments to manage interest rate exposure related to anticipated borrowings of fixed-rate debt, or to manage floating-rate debt exposure by converting it to a fixed rate. The anticipated debt offerings have a high probability of occurrence because the proceeds will be used to fund existing debt maturities as well as fund projected capital expenditures. The Registrant Subsidiaries reclassify gains and losses on the hedges from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which the interest payments being hedged occur. At various times during 2007, 2006 and 2005, APCo, I&M, OPCo, PSO and SWEPCo designated interest rate derivatives as cash flow hedges and recognized immaterial amounts in earnings due to hedge ineffectiveness.

At times certain, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks because they may purchase certain fixed assets from foreign suppliers. In accordance with AEP’s risk management policy, 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 accumulated gains or losses related to these foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) into Operating Expenses over the same period as the depreciable lives of the fixed assets that were designated as the hedged items in qualifying foreign currency hedging relationships. At various times during 2007, 2006 and 2005, APCo, OPCo and SWEPCo designated foreign currency derivatives as cash flow hedges and did not recognize any hedge ineffectiveness related to these derivative transactions. The Registrant Subsidiaries do not hedge all foreign currency exposure.

The following table represents the activity in Accumulated Other Comprehensive Income (Loss) for derivative contracts that qualify as cash flow hedges for the years 2005, 2006 and 2007:

	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Balance at December 31, 2004	$	(9,324	)	$	1,393		$	(4,076	)	$	1,241		$	400		$	(820	)
Effective portion of changes in fair value		(4,515	)		(71	)		2,489			2,281			(1,168	)		(4,817	)
Reclasses from AOCI to Net Income		(2,582	)		(2,181	)		(1,880	)		(2,767	)		(344	)		(215	)
Balance at December 31, 2005		(16,421	)		(859	)		(3,467	)		755			(1,112	)		(5,852	)
Effective portion of changes in fair value		10,365			3,438			(6,576	)		6,899			(728	)		(1,833	)
Impact Due to Changes in SIA		(442	)		(261	)		(267	)		(337	)		506			592
Reclasses from AOCI to Net Income		3,951			1,080			1,348			(55	)		264			683
Balance at December 31, 2006		(2,547	)		3,398			(8,962	)		7,262			(1,070	)		(6,410	)
Effective portion of changes in fair value		781			(831	)		(834	)		(1,485	)		-			(416	)
Reclasses from AOCI to Net Income		(4,178	)		(3,217	)		(2,355	)		(4,620	)		183			805
Balance at December 31, 2007	$	(5,944	)	$	(650	)	$	(12,151	)	$	1,157		$	(887	)	$	(6,021	)

The following table approximates net (loss) gain from cash flow hedges in Accumulated Other Comprehensive Income (Loss) at December 31, 2007 that are expected to be reclassified to net income in the next twelve months as the items being hedged settle. In addition, the following table summarizes the maximum length of time that the variability of future cash flows is being hedged. The actual amounts reclassified from AOCI to Net Income can differ as a result of market price changes.

	Gain (Loss)
	Expected to be			Maximum
	Reclassified to			Term for
	Earnings			Exposure to
	During the			Variability of
	Next Twelve			Future Cash
	Months			Flow
Company	(in thousands)			(in months)
APCo	$	(846	)	17
CSPCo		(684	)	17
I&M		(1,664	)	17
OPCo		(657	)	17
PSO		(183	)	-
SWEPCo		(829	)	30

FINANCIAL INSTRUMENTS

The fair values of Long-term Debt are based on quoted market prices for the same or similar issues and the current interest rates offered for instruments with similar maturities. 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 significant Long-term Debt for the Registrant Subsidiaries at December 31, 2007 and 2006 are summarized in the following table.

	December 31, 2007				December 31, 2006
	Book Value		Fair Value		Book Value		Fair Value
	(in thousands)
Company

APCo	$	2,847,299	$	2,811,067	$	2,598,664	$	2,577,506
CSPCo		1,298,224		1,290,718		1,197,322		1,211,176
I&M		1,567,427		1,527,320		1,555,135		1,549,985
OPCo		2,849,598		2,865,214		2,401,741		2,417,050
PSO		918,316		913,432		669,998		670,531
SWEPCo		1,197,217		1,190,708		729,006		718,902

13.	INCOME TAXES

The details of the Registrant Subsidiaries’ income taxes before extraordinary loss and cumulative effect of accounting changes as reported are as follows:

	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Year Ended December 31, 2007
Income Tax Expense (Credit):
Current	$	17,254		$	152,443		$	68,402		$	134,935		$	(52,670	)	$	43,659
Deferred		48,962			(20,874	)		4,177			16,238			31,362			(21,935	)
Deferred Investment Tax Credits		(4,102	)		(2,184	)		(5,080	)		(2,588	)		(707	)		(4,163	)
Total Income Tax	$	62,114		$	129,385		$	67,499		$	148,585		$	(22,015	)	$	17,561

	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Year Ended December 31, 2006
Income Tax Expense (Credit):
Current	$	88,750		$	114,007		$	70,231		$	165,290		$	40,690		$	71,589
Deferred		17,225			(10,900	)		13,626			(43,997	)		(23,672	)		(23,667	)
Deferred Investment Tax Credits		(4,559	)		(2,264	)		(7,752	)		(2,969	)		(1,031	)		(4,225	)
Total Income Tax	$	101,416		$	100,843		$	76,105		$	118,324		$	15,987		$	43,697

	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Year Ended December 31, 2005
Income Tax Expense (Credit):
Current	$	(1,915	)	$	44,968		$	62,082		$	68,508		$	(14,510	)	$	44,156
Deferred		72,763			19,209			26,873			59,593			46,342			(4,942	)
Deferred Investment Tax Credits		(4,659	)		(2,717	)		(7,725	)		(3,123	)		(1,347	)		(4,292	)
Total Income Tax	$	66,189		$	61,460		$	81,230		$	124,978		$	30,485		$	34,922

Shown below is a reconciliation for each Registrant Subsidiary of the difference between the amount 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			CSPCo			I&M
	(in thousands)
Year Ended December 31, 2007
Net Income	$	54,736		$	258,088		$	136,895
Extraordinary Loss		78,763			-			-
Income Taxes		62,114			129,385			67,499
Pretax Income	$	195,613		$	387,473		$	204,394

Income Tax on Pretax Income at Statutory Rate (35%)	$	68,465		$	135,616		$	71,538
Increase (Decrease) in Income Tax resulting from the following items:
Depreciation		8,015			4,298			14,251
Nuclear Fuel Disposal Costs		-			-			(5,610	)
Allowance for Funds Used During Construction		(4,334	)		(1,223	)		(4,376	)
Rockport Plant Unit 2 Investment Tax Credit		-			-			397
Removal Costs		(5,394	)		(917	)		(8,191	)
Investment Tax Credits, Net		(4,102	)		(2,184	)		(5,080	)
State and Local Income Taxes		1,706			(4,096	)		3,663
Other		(2,242	)		(2,109	)		907
Total Income Taxes	$	62,114		$	129,385		$	67,499

Effective Income Tax Rate		31.8	%		33.4	%		33.0	%

	OPCo			PSO			SWEPCo
	(in thousands)
Year Ended December 31, 2007
Net Income (Loss)	$	268,564		$	(24,124	)	$	66,264
Income Taxes		148,585			(22,015	)		17,561
Pretax Income (Loss)	$	417,149		$	(46,139	)	$	83,825

Income Tax on Pretax Income at Statutory Rate (35%)	$	146,002		$	(16,149	)	$	29,339
Increase (Decrease) in Income Tax resulting from the following items:
Depreciation		2,362			(592	)		17
Depletion		-			-			(3,360	)
Allowance for Funds Used During Construction		(1,269	)		(433	)		(3,490	)
Investment Tax Credits, Net		(2,588	)		(707	)		(4,163	)
State and Local Income Taxes		3,438			(3,699	)		(165	)
Other		640			(435	)		(617	)
Total Income Taxes	$	148,585		$	(22,015	)	$	17,561

Effective Income Tax Rate		35.6	%		47.7	%		20.9	%

	APCo			CSPCo			I&M
	(in thousands)
Year Ended December 31, 2006
Net Income	$	181,449		$	185,579		$	121,168
Income Taxes		101,416			100,843			76,105
Pretax Income	$	282,865		$	286,422		$	197,273

Income Tax on Pretax Income at Statutory Rate (35%)	$	99,003		$	100,248		$	69,046
Increase (Decrease) in Income Tax resulting from the following items:
Depreciation		10,325			1,395			20,834
Nuclear Fuel Disposal Costs		-			-			(5,538	)
Allowance for Funds Used During Construction		(7,379	)		(789	)		(5,149	)
Rockport Plant Unit 2 Investment Tax Credit		-			-			397
Removal Costs		(3,339	)		(544	)		(5,968	)
Investment Tax Credits, Net		(4,559	)		(2,264	)		(7,752	)
State and Local Income Taxes		12,678			(53	)		4,559
Other		(5,313	)		2,850			5,676
Total Income Taxes	$	101,416		$	100,843		$	76,105

Effective Income Tax Rate		35.9	%		35.2	%		38.6	%

	OPCo			PSO			SWEPCo
	(in thousands)
Year Ended December 31, 2006
Net Income	$	228,643		$	36,860		$	91,723
Income Taxes		118,324			15,987			43,697
Pretax Income	$	346,967		$	52,847		$	135,420

Income Tax on Pretax Income at Statutory Rate (35%)	$	121,438		$	18,496		$	47,397
Increase (Decrease) in Income Tax resulting from the following items:
Depreciation		4,397			(593	)		(85	)
Depletion		-			-			(3,150	)
Allowance for Funds Used During Construction		(1,323	)		(209	)		(370	)
Investment Tax Credits, Net		(2,969	)		(1,031	)		(4,225	)
State and Local Income Taxes		270			260			3,764
Other		(3,489	)		(936	)		366
Total Income Taxes	$	118,324		$	15,987		$	43,697

Effective Income Tax Rate		34.1	%		30.3	%		32.3	%

	APCo			CSPCo			I&M
	(in thousands)
Year Ended December 31, 2005
Net Income	$	133,576		$	136,960		$	146,852
Cumulative Effect of Accounting Changes		2,256			839			-
Income Taxes		66,189			61,460			81,230
Pretax Income	$	202,021		$	199,259		$	228,082

Income Tax on Pretax Income at Statutory Rate (35%)	$	70,707		$	69,741		$	79,829
Increase (Decrease) in Income Tax resulting from the following items:
Depreciation		11,257			1,614			19,492
Nuclear Fuel Disposal Costs		-			-			(3,413	)
Allowance for Funds Used During Construction		(4,786	)		(679	)		(3,819	)
Rockport Plant Unit 2 Investment Tax Credit		-			-			397
Removal Costs		(4,275	)		(357	)		(5,476	)
Investment Tax Credits, Net		(4,659	)		(2,717	)		(7,725	)
State and Local Income Taxes		2,223			448			6,598
Other		(4,278	)		(6,590	)		(4,653	)
Total Income Taxes	$	66,189		$	61,460		$	81,230

Effective Income Tax Rate		32.8	%		30.8	%		35.6	%

	OPCo			PSO			SWEPCo
	(in thousands)
Year Ended December 31, 2005
Net Income	$	245,844		$	57,893		$	73,938
Cumulative Effect of Accounting Changes		4,575			-			1,252
Income Taxes		124,978			30,485			34,922
Pretax Income	$	375,397		$	88,378		$	110,112

Income Tax on Pretax Income at Statutory Rate (35%)	$	131,389		$	30,932		$	38,539
Increase (Decrease) in Income Tax resulting from the following items:
Depreciation		5,195			(775	)		(211	)
Depletion		-			-			(3,150	)
Allowance for Funds Used During Construction		(936	)		(271	)		(760	)
Investment Tax Credits, Net		(3,123	)		(1,347	)		(4,292	)
State and Local Income Taxes		5,437			(1,387	)		1,831
Other		(12,984	)		3,333			2,965
Total Income Taxes	$	124,978		$	30,485		$	34,922

Effective Income Tax Rate		33.3	%		34.5	%		31.7	%

The following tables show the elements of the net deferred tax liability and the significant temporary differences for each Registrant Subsidiary:

	APCo			CSPCo			I&M
December 31, 2007	(in thousands)
Deferred Tax Assets	$	320,186		$	104,680		$	694,293
Deferred Tax Liabilities		(1,292,189	)		(553,665	)		(1,023,778	)
Net Deferred Tax Liabilities	$	(972,003	)	$	(448,985	)	$	(329,485	)

Property Related Temporary Differences	$	(729,960	)	$	(375,433	)	$	17,170
Amounts Due from Customers for Future Federal Income Taxes		(103,488	)		(4,803	)		(23,509	)
Deferred State Income Taxes		(109,997	)		(7,198	)		(38,345	)
Transition Regulatory Assets		(4,457	)		(17,290	)		-
Deferred Income Taxes on Other Comprehensive Loss		18,947			10,120			8,440
Net Deferred Gain on Sale and Leaseback-Rockport Plant Unit 2		-			-			18,708
Accrued Nuclear Decommissioning Expense		-			-			(285,265	)
Deferred Fuel and Purchased Power		15,559			(39	)		263
Accrued Pensions		(21,638	)		(21,930	)		(13,880	)
Nuclear Fuel		-			-			(11,862	)
Regulatory Assets		(69,574	)		(38,231	)		(25,436	)
All Other, Net		32,605			5,819			24,231
Net Deferred Tax Liabilities	$	(972,003	)	$	(448,985	)	$	(329,485	)

	OPCo			PSO			SWEPCo
December 31, 2007	(in thousands)
Deferred Tax Assets	$	209,969		$	90,452		$	83,555
Deferred Tax Liabilities		(1,140,159	)		(531,645	)		(435,247	)
Net Deferred Tax Liabilities	$	(930,190	)	$	(441,193	)	$	(351,692	)

Property Related Temporary Differences	$	(823,397	)	$	(374,276	)	$	(303,865	)
Amounts Due from Customers for Future Federal Income Taxes		(54,203	)		3,078			(3,631	)
Deferred State Income Taxes		(42,724	)		(55,990	)		(31,850	)
Transition Regulatory Assets		(635	)		-			-
Deferred Income Taxes on Other Comprehensive Loss		19,676			478			8,852
Deferred Fuel and Purchased Power		-			3,114			(12,315	)
Accrued Pensions		(35,833	)		(16,238	)		(12,482	)
Regulatory Assets		(29,393	)		(46,010	)		(18,365	)
All Other, Net		36,319			44,651			21,964
Net Deferred Tax Liabilities	$	(930,190	)	$	(441,193	)	$	(351,692	)

	APCo			CSPCo			I&M
December 31, 2006	(in thousands)
Deferred Tax Assets	$	359,085		$	117,884		$	696,709
Deferred Tax Liabilities		(1,316,314	)		(593,772	)		(1,031,709	)
Net Deferred Tax Liabilities	$	(957,229	)	$	(475,888	)	$	(335,000	)

Property Related Temporary Differences	$	(742,711	)	$	(381,832	)	$	(1,550	)
Amounts Due from Customers for Future Federal Income Taxes		(101,554	)		(5,745	)		(23,938	)
Deferred State Income Taxes		(97,887	)		(8,559	)		(42,329	)
Transition Regulatory Assets		(5,942	)		(34,179	)		-
Deferred Income Taxes on Other Comprehensive Loss		29,503			11,840			8,104
Net Deferred Gain on Sale and Leaseback-Rockport Plant Unit 2		-			-			20,670
Accrued Nuclear Decommissioning Expense		-			-			(246,533	)
Deferred Fuel and Purchased Power		7,117			(39	)		(146	)
Accrued Pensions		(17,769	)		(16,161	)		(7,618	)
Nuclear Fuel		-			-			(16,403	)
Regulatory Assets		(25,919	)		(5,052	)		(5,284	)
All Other, Net		(2,067	)		(36,161	)		(19,973	)
Net Deferred Tax Liabilities	$	(957,229	)	$	(475,888	)	$	(335,000	)

	OPCo			PSO			SWEPCo
December 31, 2006	(in thousands)
Deferred Tax Assets	$	215,890		$	107,723		$	109,860
Deferred Tax Liabilities		(1,127,111	)		(521,920	)		(484,408	)
Net Deferred Tax Liabilities	$	(911,221	)	$	(414,197	)	$	(374,548	)

Property Related Temporary Differences	$	(789,303	)	$	(351,461	)	$	(319,240	)
Amounts Due from Customers for Future Federal Income Taxes		(51,673	)		3,747			(1,382	)
Deferred State Income Taxes		(33,053	)		(55,256	)		(38,073	)
Transition Regulatory Assets		(25,273	)		-			-
Deferred Income Taxes on Other Comprehensive Loss		30,565			576			10,337
Deferred Fuel and Purchased Power		-			(2,644	)		(6,501	)
Accrued Pensions		(30,668	)		(14,182	)		(11,676	)
Regulatory Assets		(34,821	)		(30,392	)		(21,293	)
All Other, Net		23,005			35,415			13,280
Net Deferred Tax Liabilities	$	(911,221	)	$	(414,197	)	$	(374,548	)

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 System companies allocates the benefit of current tax losses to the 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.

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2000. However, AEP has filed refund claims with the IRS for years 1997 through 2000 for the CSW pre-merger tax period, which are currently being reviewed. The Registrant Subsidiaries have completed the exam for the years 2001 through 2003 and have issues that will be pursued at the appeals level. The returns for the years 2004 through 2006 are presently under audit by the IRS. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for 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 have a material adverse effect on results of operations.

The Registrant Subsidiaries file income tax returns in various state, local, and foreign 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 we have filed tax returns with positions that may be challenged by these tax authorities. However, management does not believe that the ultimate resolution of these audits will materially impact results of operations. With few exceptions, the Registrant Subsidiaries are no longer subject to state, local, or non-U.S. income tax examinations by tax authorities for years before 2000.

Prior to the adoption of FIN 48, the Registrant Subsidiaries recorded interest and penalty expense related to uncertain tax positions in tax expense accounts. With the adoption of FIN 48, the Registrant Subsidiaries began recognizing interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation. The following table shows the amounts we reported in 2007 for interest expense, interest income and reversal of prior period interest expense.

				Prior Period
Company	Expense		Refund	Reversal
	(in millions)
APCo	$	3	-	-
CSPCo		1	-	-
I&M		1	-	-
OPCo		-	-	4
PSO		-	2	-
SWEPCo		-	-	2

The following table shows the amount of interest and penalties as of December 31, 2007 and 2006:

	Years Ended December 31,
	2007			2006
Company	(in millions)
APCo	$	7		$	11
CSPCo		-			4
I&M		2			7
OPCo		6			8
PSO		(1	)		1
SWEPCo		1			4

The Registrant Subsidiaries adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, the approximate increase (decrease) in the liabilities for unrecognized tax benefits, as well as related interest expense and penalties, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings was recognized by each Registrant Subsidiary as follows:

Company	(in thousands)
APCo	$	2,685
CSPCo		3,022
I&M		(327	)
OPCo		5,380
PSO		386
SWEPCo		1,642

As of December 31, 2007, the reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Balance at January 1, 2007	$	22		$	25		$	18		$	50		$	9		$	7
Increase - Tax Positions Taken During a Prior Period		2			-			-			3			7			-
Decrease - Tax Positions Taken During a Prior Period		(7	)		(2	)		(9	)		(5	)		(6	)		(3	)
Increase - Tax Positions Taken During the Current Year		3			2			2			6			2			4
Increase - Settlements with Taxing Authorities		-			-			-			-			2			-
Decrease - Lapse of the Applicable Statute of Limitations		-			(5	)		-			(2	)		-			(1	)

Balance at December 31, 2007	$	20		$	20		$	11		$	52		$	14		$	7

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	(in millions)
APCo	$	9
CSPCo		12
I&M		6
OPCo		29
PSO		7
SWEPCo		4

Federal Tax Legislation

In 2005, the Energy Tax Incentives Act of 2005 was signed into law. This act created a limited amount of tax credits for the building of IGCC plants. The credit is 20% of the eligible property in the construction of new plant or 20% of the total cost of repowering of an existing plant using IGCC technology. In the case of a newly constructed IGCC, eligible property is defined as the components necessary for the gasification of coal, including any coal handling and gas separation equipment. AEP announced plans to construct two new IGCC plants that may be eligible for the allocation of these credits. AEP filed applications for the Mountaineer and Great Bend projects with the DOE and the IRS. Both projects were certified by the DOE and qualified by the IRS. However, neither project was awarded credits during this round of credit awards. AEP will continue to pursue credits for the next round of available credits.

The Tax Increase Prevention and Reconciliation Act of 2005 (TIPRA 2005) was passed May 17, 2006. The majority of the provisions in TIPRA 2005 were directed toward individual income tax relief including the extension of reduced tax rates for dividends and capital gains through 2010. Management believes the application of this act will not materially affect the Registrant Subsidiaries’ results of operations, cash flows or financial condition.

The President signed the Pension Protection Act of 2006 (PPA 2006) into law on August 17, 2006. This law is directed toward strengthening qualified retirement plans and adding new restrictions on charitable contributions. Specifically, PPA 2006 concentrates on the funding of defined benefit plans and the health of the Pension Benefit Guaranty Corporation. PPA 2006 imposes new minimum funding rules for multiemployer plans as well as increasing the deduction limitation for contributions to multiemployer defined benefit plans. Due to the significant funding of the AEP pension plans in 2005, the Act will not materially affect the Registrant Subsidiaries’ results of operations, cash flows or financial condition.

On December 20, 2006, the Tax Relief and Health Care Act of 2006 (TRHCA 2006) was signed into law. The primary purpose of the bill was to extend expiring tax provisions for individuals and business taxpayers and provide increased tax flexibility around medical benefits. In addition to extending the lower capital gains and dividend tax rates for individuals, TRHCA 2006 extended the research credit and for 2007 provided a new alternative formula for determining the research credit. The application of TRHCA 2006 is not expected to materially affect the Registrant Subsidiaries’ results of operations, cash flows or financial condition.

Several tax bills and other legislation with tax-related sections were enacted in 2007, including the Tax Technical Corrections Act of 2007, the Tax Increase Prevention Act of 2007 and the Energy Independence and Security Act of 2007. The tax law changes enacted in 2007 are not expected to materially affect the Registrant Subsidiaries’ results of operations, cash flows or financial condition.

State Tax Legislation

On June 30, 2005, the Governor of Ohio signed Ohio House Bill 66 into law enacting sweeping tax changes impacting all companies doing business in Ohio. Most of the significant tax changes will be phased in over a five-year period, while some of the less significant changes became fully effective July 1, 2005. Changes to the Ohio franchise tax, nonutility property taxes, and the new commercial activity tax are subject to phase-in. The Ohio franchise tax will fully phase-out over a five-year period beginning with a 20% reduction in state franchise tax for taxable income accrued during 2005. In 2005, AEP reversed deferred state income tax liabilities that are not expected to reverse during the phase-out as follows:

	Other Regulatory Liabilities (a)		SFAS 109 Regulatory Asset, Net (b)		State Income Tax Expense (c)		Deferred State Income Tax Liabilities (d)
Company	(in thousands)
APCo	$	-	$	10,945	$	2,769	$	13,714
CSPCo		15,104		-		-		15,104
I&M		-		5,195		-		5,195
OPCo		41,864		-		-		41,864
PSO		-		-		706		706
SWEPCo		-		582		119		701

(a)	The reversal of deferred state income taxes for the Ohio companies was recorded as a regulatory liability pending rate-making treatment in Ohio. See “Ormet” section of Note 4.
(b)	Deferred state income tax adjustments related to those companies in which state income taxes flow through for rate-making purposes reduced the regulatory asset associated with the deferred state income tax liabilities.
(c)	These amounts were recorded as a reduction to Income Tax Expense.
(d)	Total deferred state income tax liabilities that reversed during 2005 related to Ohio law change.

In November 2006, the PUCO ordered OPCo and CSPCo to amortize $41,864 and $15,104, respectively, to income as an offset to power supply contract losses incurred by Ohio Power and Columbus Southern Power for sales to Ormet.

The new legislation also imposes a new commercial activity tax at a fully phased-in rate of 0.26% on all Ohio gross receipts. The new tax is being phased-in over a five-year period that began July 1, 2005 at 23% of the full 0.26% rate. As a result of this new tax, expenses of approximately $3 million, $2 million and $1 million for CSPCo and $3 million, $2 million and $1 million for OPCo were recorded in 2007, 2006 and 2005, respectively, in Taxes Other than Income Taxes.

In the second quarter of 2006, the Texas state legislature replaced the existing franchise/income tax with a gross margin tax at a 1% rate for electric utilities. Overall, the new law reduces Texas income tax rates and is effective January 1, 2007. The new gross margin tax is income-based for purposes of the application of SFAS 109 “Accounting for Income Taxes.” Based on the new law, management reviewed deferred tax liabilities with consideration given to the rate changes and changes to the allowed deductible items with temporary differences. As a result, in the second quarter of 2006 the following adjustments were recorded:

		Decrease in SFAS 109 Regulatory Asset, Net		Decrease in State Income Tax Expense		Decrease in Deferred State Income Tax Liabilities
Company	(in thousands)
PSO		$	-	$	3,273	$	3,273
SWEPCo			4,438		501		4,939

On July 12, 2007, the Governor of Michigan signed Michigan Senate Bill 0094 (MBT Act) and related companion bills into law providing a comprehensive restructuring of Michigan’s principal business tax. The new law is effective January 1, 2008 and replaces the Michigan Single Business Tax that expired at the end of 2007. The MBT Act is composed of a new tax which will be calculated based upon two components: (a) a business income tax (BIT) imposed at a rate of 4.95% and (b) a modified gross receipts tax (GRT) imposed at a rate of 0.80%, which will collectively be referred to as the BIT/GRT tax calculation. The new law also includes significant credits for engaging in Michigan-based activity.

On September 30, 2007, the Governor of Michigan signed House Bill 5198, which amends the MBT Act to provide for a new deduction on the BIT and GRT tax returns equal to the book-tax basis difference triggered as a result of the enactment of the MBT Act. This new state-only temporary difference will be deducted over a 15 year period on the MBT Act tax returns starting in 2015. The purpose of the new MBT Act state deduction was to provide companies relief from the recordation of the SFAS 109 Income Tax Liability. The Registrant Subsidiaries have evaluated the impact of the MBT Act and the application of the MBT Act will not materially affect their results of operations, cash flows or financial condition.

14.

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. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows:

	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Year Ended December 31, 2007	(in thousands)
Net Lease Expense on Operating Leases	$	14,955	$	5,675	$	95,991	$	23,145	$	8,176	$	7,618
Amortization of Capital Leases		4,498		2,925		6,699		7,526		1,510		8,194
Interest on Capital Leases		691		609		2,679		2,132		290		6,613
Total Lease Rental Costs	$	20,144	$	9,209	$	105,369	$	32,803	$	9,976	$	22,425

	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Year Ended December 31, 2006	(in thousands)
Net Lease Expense on Operating Leases	$	12,657	$	5,093	$	97,750	$	20,985	$	6,901	$	6,808
Amortization of Capital Leases		5,825		3,221		6,533		7,946		1,155		6,504
Interest on Capital Leases		873		429		2,807		2,155		232		3,689
Total Lease Rental Costs	$	19,355	$	8,743	$	107,090	$	31,086	$	8,288	$	17,001

	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Year Ended December 31, 2005	(in thousands)
Net Lease Expense on Operating Leases	$	8,539	$	6,194	$	93,993	$	10,528	$	5,658	$	5,867
Amortization of Capital Leases		6,273		3,313		6,681		7,940		668		6,200
Interest on Capital Leases		449		540		2,442		2,275		93		2,738
Total Lease Rental Costs	$	15,261	$	10,047	$	103,116	$	20,743	$	6,419	$	14,805

The following table shows the property, plant and equipment under capital leases and related obligations recorded on the Registrant Subsidiaries’ balance sheets. For I&M, current capital lease obligations are included in Obligations Under Capital Leases on I&M’s Consolidated Balance Sheets. For all other Registrant Subsidiaries, current capital lease obligations are included in Current Liabilities – Other. For all Registrant Subsidiaries, long-term capital lease obligations are included in Noncurrent Liabilities – Deferred Credits and Other on the Registrant Subsidiaries’ balance sheets.

	APCO		CSPCO		I&M		OPCo		PSO		SWEPCo
December 31, 2007	(in thousands)
Property, Plant and Equipment Under Capital Leases:
Production	$	-	$	7,104	$	15,643	$	39,484	$	-	$	14,270
Distribution		-		-		14,589		-		-		-
Other		28,234		12,686		117,249		27,670		6,576		95,442
Construction Work in Progress		-		-		-		-		-		39,151
Total Property, Plant and Equipment		28,234		19,790		147,481		67,154		6,576		148,863
Accumulated Amortization		17,133		11,681		26,922		39,809		2,548		49,243
Net Property, Plant and Equipment Under Capital Leases	$	11,101	$	8,109	$	120,559	$	27,345	$	4,028	$	99,620

Obligations Under Capital Leases:
Noncurrent Liability	$	6,280	$	4,885	$	77,177	$	21,062	$	2,527	$	89,765
Liability Due Within One Year		4,821		3,243		43,382		8,015		1,501		10,555
Total Obligations Under Capital Leases	$	11,101	$	8,128	$	120,559	$	29,077	$	4,028	$	100,320

	APCO		CSPCO		I&M		OPCo		PSO		SWEPCo
December 31, 2006	(in thousands)
Property, Plant and Equipment Under Capital Leases:
Production	$	1,264	$	7,104	$	18,480	$	39,807	$	-	$	14,270
Distribution		-		-		14,589		-		-		-
Other		30,578		13,009		40,227		31,590		6,387		82,209
Construction Work in Progress		-		-		-		-		-		29,777
Total Property, Plant and Equipment		31,842		20,113		73,296		71,397		6,387		126,256
Accumulated Amortization		20,011		11,660		30,240		38,102		1,571		41,894
Net Property, Plant and Equipment Under Capital Leases	$	11,831	$	8,453	$	43,056	$	33,295	$	4,816	$	84,362

Obligations Under Capital Leases:
Noncurrent Liability	$	7,699	$	5,731	$	27,073	$	25,996	$	3,332	$	72,061
Liability Due Within One Year		4,160		2,741		15,983		8,970		1,484		12,654
Total Obligations Under Capital Leases	$	11,859	$	8,472	$	43,056	$	34,966	$	4,816	$	84,715

Future minimum lease payments consisted of the following at December 31, 2007:

	APCO		CSPCO		I&M		OPCo		PSO		SWEPCo
Capital Leases	(in thousands)
2008	$	5,162	$	3,644	$	44,910	$	7,547	$	1,684	$	16,788
2009		3,110		2,522		34,988		5,570		1,330		16,654
2010		2,264		1,852		23,477		4,302		820		12,363
2011		524		486		8,531		1,969		365		11,019
2012		268		191		8,716		1,766		141		10,140
Later Years		477		185		20,873		19,330		47		73,011
Total Future Minimum Lease Payments		11,805		8,880		141,495		40,484		4,387		139,975
Less Estimated Interest Element		704		752		20,936		11,407		359		39,655
Estimated Present Value of Future Minimum Lease Payments	$	11,101	$	8,128	$	120,559	$	29,077	$	4,028	$	100,320

	APCO		CSPCO		I&M		OPCo		PSO		SWEPCo
Noncancelable Operating Leases	(in thousands)
2008	$	15,010	$	5,572	$	99,272	$	25,267	$	6,715	$	7,952
2009		13,784		5,005		97,549		23,932		5,883		7,098
2010		12,517		4,222		93,745		22,365		4,848		5,149
2011		10,654		3,097		92,640		19,903		3,208		3,925
2012		8,631		2,030		89,667		18,644		2,505		2,817
Later Years		37,100		5,222		781,992		92,398		5,591		7,170
Total Future Minimum Lease Payments	$	97,696	$	25,148	$	1,254,865	$	202,509	$	28,750	$	34,111

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 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. Neither AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction for each respective company as of December 31, 2007 are as follows:

	AEGCo		I&M
Future Minimum Lease Payments	(in millions)
2008	$	74	$	74
2009		74		74
2010		74		74
2011		74		74
2012		74		74
Later Years		738		738
Total Future Minimum Lease Payments	$	1,108	$	1,108

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 has an initial term of five years. At the end of each lease term, AEP may (a) renew for another five-year term, not to exceed a total of twenty years; (b) purchase the railcars for the purchase price amount specified in the lease, projected at the lease inception to be the then fair market value; or (c) return the railcars and arrange a third party sale (return-and-sale option). The lease is accounted for as an operating lease. AEP intends to renew the lease for the full twenty years. This operating lease agreement allows AEP to avoid a large initial capital expenditure and to spread AEP’s railcar costs evenly over the expected twenty-year usage.

Under the return-and-sale option, the lessor is guaranteed that the sale proceeds will equal at least a specified lessee obligation amount which declines with each five-year renewal. At December 31, 2007, the maximum potential loss was approximately $30 million ($20 million, net of tax) assuming the fair market value of the equipment is zero at the end of the current lease term. However, management believes that the fair market value would produce a sufficient sales price to avoid any loss.

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 new operating leases for I&M and SWEPCo. The future minimum lease payments related to these leases are not included in I&M’s and SWEPCo’s schedules of future minimum lease payments under operating leases earlier in this note. I&M and SWEPCo intend to renew these leases for the full twenty years and have assumed the guarantee under the return-and-sale option.

The Registrant Subsidiaries have other railcar leases arrangements that do not utilize this type of financing structure.

Sabine Dragline Lease

In December 2006, Sabine Mining Company (Sabine), an entity consolidated under FIN 46, entered into a capital lease agreement with a nonaffiliated company to finance the purchase of a $51 million electric dragline for Sabine’s mining operations. In 2006, the initial capital outlay for the dragline was $26 million. Sabine incurred an additional $13 million of transportation, assembly and upgrade costs in 2007. Sabine expects to incur an additional $12 million of setup costs prior to the completion date of mid-2008. These additional costs will be added to SWEPCo’s consolidated capital lease assets and capital lease obligations as they are incurred. For the year ended December 31, 2007, Sabine paid $2 million of interim rent. Sabine will continue to pay interim rent on a quarterly basis through the estimated completion date of mid-2008. Once the dragline is fully assembled, Sabine will pay capital and interest payments on the outstanding lease obligation. The capital lease asset is included in Construction Work in Progress and the capital lease obligation is included in Noncurrent Liabilities – Deferred Credits and Other on SWEPCo’s December 31, 2007 and 2006 Consolidated Balance Sheets. Total future payments of $60 million were calculated using both interim rent prior to completion and capital and interest from completion until the maturity of the lease using the current capital outlay of $39 million. 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. I&M sold a portion of its unamortized nuclear fuel inventory to CLI at cost for $85 million. The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 60 months. The future payment obligations of $94 million are included in I&M’s future minimum lease payments schedule earlier in this note. At December 31, 2007, the net capital lease asset is included in Property, Plant and Equipment – Other and the long-term and short-term capital lease obligations are included in Noncurrent Liabilities – Deferred Credits and Other and Current Liabilities – Other, respectively, on I&M’s December 31, 2007 Consolidated Balance Sheet. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2007 are as follows, based on estimated fuel burn:

Future Minimum Lease Payments	(in millions)
2008	$	37
2009		28
2010		19
2011		6
2012		4
Total Future Minimum Lease Payments	$	94

15. FINANCING ACTIVITIES

Preferred Stock

	Par Value			Authorized Shares	Shares Outstanding at December 31, 2007	Call Price at December 31, 2007 (a)		Series	Redemption
										December 31,
										2007		2006
Company										(in thousands)
APCo	$	0	(b)	8,000,000	177,520	$	110.00	4.50%	Any time	$	17,752	$	17,763
CSPCo		25		7,000,000	-		-	-	-		-		-
CSPCo		100		2,500,000	-		-	-	-		-		-
I&M		25		11,200,000	-		-	-	-		-		-
I&M		100		(c)	55,335		106.13	4.125%	Any time		5,533		5,535
I&M		100		(c)	14,412		102.00	4.56%	Any time		1,441		1,441
I&M		100		(c)	11,055		102.73	4.12%	Any time		1,106		1,106
OPCo		25		4,000,000	-		-	-	-		-		-
OPCo		100		(d)	14,595		103.00	4.08%	Any time		1,460		1,460
OPCo		100		(d)	22,824		103.20	4.20%	Any time		2,282		2,282
OPCo		100		(d)	31,482		104.00	4.40%	Any time		3,148		3,151
OPCo		100		(d)	97,373		110.00	4.50%	Any time		9,737		9,737
PSO		100		(e)	44,548		105.75	4.00%	Any time		4,455		4,455
PSO		100		(e)	8,069		103.19	4.24%	Any time		807		807
SWEPCo		100		(f)	7,386		103.90	4.28%	Any time		740		740
SWEPCo		100		(f)	1,907		102.75	4.65%	Any time		190		190
SWEPCo		100		(f)	37,673		109.00	5.00%	Any time		3,767		3,767

(a)	The cumulative preferred stock is callable at the price indicated plus accrued dividends.
(b)	Stated value is $100 per share.
(c)	I&M has 2,250,000 authorized $100 par value per share shares in total.
(d)	OPCo has 3,762,403 authorized $100 par value per share shares in total.
(e)	PSO has 700,000 authorized shares in total.
(f)	SWEPCo has 1,860,000 authorized shares in total.

		Number of Shares Redeemed for the Years Ended December 31,
Company	Series	2007	2006	2005
APCo	4.50%	114	202	-
I&M	4.12%	22	12	-
I&M	5.90%	-	-	132,000
I&M	6.25%	-	-	192,500
I&M	6.30%	-	-	132,450
I&M	6.875%	-	-	157,500
OPCo	4.50%	-	89	20
OPCo	5.90%	-	-	50,000
OPCo	4.40%	30	-	-
SWEPCo	5.00%	-	30	-

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, 2007 and 2006:

		Interest Rates at
		December 31,						December 31,
Type of Debt	Maturity	2007			2006			2007			2006
APCo								(in thousands)
Pollution Control Bonds, Putnam Co., Series E (a)	2019		4.40	%		3.50	%	$	30,000		$	30,000
Pollution Control Bonds, Putnam Co., Series F (a)	2019 (d)		4.50	%		3.60	%		40,000			40,000
Pollution Control Bonds, Russell Co., Series J (a)	2021		4.40	%		3.70	%		17,500			17,500
Pollution Control Bonds, Russell Co., Series H (a)	2021		5.00	%		5.00	%		19,500			19,500
Pollution Control Bonds, Mason Co., Series L (a)	2022		5.50	%		5.50	%		100,000			100,000
Pollution Control Bonds, Mason Co., Series K (a)	2024		6.05	%		6.05	%		30,000			30,000
Pollution Control Bonds, West Virginia Econ. Dev. Auth., Series 2006 A (a)	2036		6.00	%		3.70	%		50,275			50,275
Pollution Control Bonds, West Virginia Econ. Dev. Auth., Series 2007 A (a)	2037		5.10	%		-			75,000			-
Unamortized Premium (Discount)									(203	)		(215	)
Total Pollution Control Bonds - APCo									362,072			287,060

Senior Unsecured Notes, Series F	2007		-			4.3148	%		-			200,000
Senior Unsecured Floating Rate Notes, Series C	2007		-			5.6938	%		-			125,000
Senior Unsecured Notes, Series G	2008		3.60	%		3.60	%		200,000			200,000
Senior Unsecured Notes, Series C	2009		6.60	%		6.60	%		150,000			150,000
Senior Unsecured Notes, Series J	2010		4.40	%		4.40	%		150,000			150,000
Senior Unsecured Notes, Series M	2011		5.55	%		5.55	%		250,000			250,000
Senior Unsecured Notes, Series O	2012		5.65	%		-			250,000			-
Senior Unsecured Notes, Series I	2015		4.95	%		4.95	%		200,000			200,000
Senior Unsecured Notes, Series K	2017		5.00	%		5.00	%		250,000			250,000
Senior Unsecured Notes, Series H	2033		5.95	%		5.95	%		200,000			200,000
Senior Unsecured Notes, Series L	2035		5.80	%		5.80	%		250,000			250,000
Senior Unsecured Notes, Series N	2036		6.375	%		6.375	%		250,000			250,000
Senior Unsecured Notes, Series P	2037		6.70	%		-			250,000			-
MTM of Fair Value Hedge									(282	)		(1,171	)
Unamortized Premium (Discount)									(16,971	)		(14,718	)
Total Senior Unsecured Notes - APCo									2,382,747			2,209,111

Notes Payable – Affiliated	2010		4.708	%		4.708	%		100,000			100,000
Total Notes Payable – Affiliated - APCo									100,000			100,000

Other Long-term Debt	2026		13.718	%		13.718	%		2,480			2,493
Total Other Long-term Debt - APCo									2,480			2,493

Total APCo Long-term Debt									2,847,299			2,598,664
Less: Long-term Debt Due Within One Year									239,732			324,191
Long-term Debt								$	2,607,567		$	2,274,473

		Interest Rates at
		December 31,						December 31,
Type of Debt	Maturity	2007			2006			2007			2006
CSPCo								(in thousands)
Pollution Control Bonds, State of Ohio Air Quality Series 2005 D (a)	2038		4.50	%		3.53	%	$	48,550		$	48,550
Pollution Control Bonds, State of Ohio Air Quality Series 2005 C (a)	2038		3.80	%		3.75	%		43,695			43,695
Pollution Control Bonds, State of Ohio Air Quality Series 2007 A (a)	2040		4.60	%		-			44,500			-
Pollution Control Bonds, State of Ohio Air Quality Series 2007 B (a)	2042		4.75	%		-			56,000			-
Unamortized Premium (Discount)									(153	)		(158	)
Total Pollution Control Bonds – CSPCo									192,592			92,087

Senior Unsecured Medium Term Notes, Series A	2008		6.51	%		6.51	%		52,000			52,000
Senior Unsecured Medium Term Notes, Series B	2008		6.55	%		6.55	%		60,000			60,000
Senior Unsecured Notes, Series E	2010		4.40	%		4.40	%		150,000			150,000
Senior Unsecured Notes, Series C	2013		5.50	%		5.50	%		250,000			250,000
Senior Unsecured Notes, Series B	2033		6.60	%		6.60	%		250,000			250,000
Senior Unsecured Notes, Series F	2035		5.85	%		5.85	%		250,000			250,000
Unamortized Premium (Discount)									(6,368	)		(6,765	)
Total Senior Unsecured Notes – CSPCo									1,005,632			1,005,235

Notes Payable – Affiliated	2010		4.64	%		4.64	%		100,000			100,000
Total Notes Payable – Affiliated – CSPCo									100,000			100,000

Total CSPCo Long-term Debt									1,298,224			1,197,322
Less: Long-term Debt Due Within One Year									112,000			-
Long-Term Debt								$	1,186,224		$	1,197,322

I&M
Pollution Control Bonds, City of Sullivan, Series D (a)	2009 (e)		4.50	%		3.70	%	$	45,000		$	45,000
Pollution Control Bonds, City of Lawrenceburg, Series F (a)	2019		4.75	%		3.55	%		25,000			25,000
Pollution Control Bonds, City of Lawrenceburg, Series G (a)	2021		4.65	%		3.50	%		52,000			52,000
Pollution Control Bonds, City of Rockport, Series C (a)	2025		4.25	%		3.74	%		40,000			40,000
Pollution Control Bonds, City of Rockport, Series B (a)	2025 (f)		4.10	%		3.60	%		50,000			50,000
Pollution Control Bonds, City of Rockport, Series 2002A (a)	2025		4.625	%		4.90	%		50,000			50,000
Pollution Control Bonds, City of Rockport, Series 2006A (a)	2025		5.00	%		3.90	%		50,000			50,000
Unamortized Premium (Discount)									(657	)		(695	)
Total Pollution Control Bonds – I&M									311,343			311,305

Senior Unsecured Notes, Series A	2008		6.45	%		6.45	%		50,000			50,000
Senior Unsecured Notes, Series E	2012		6.375	%		6.375	%		100,000			100,000
Senior Unsecured Notes, Series F	2014		5.05	%		5.05	%		175,000			175,000
Senior Unsecured Notes, Series G	2015		5.65	%		5.65	%		125,000			125,000
Senior Unsecured Notes, Series D	2032		6.00	%		6.00	%		150,000			150,000
Senior Unsecured Notes, Series H	2037		6.05	%		6.05	%		400,000			400,000
Unamortized Premium (Discount)									(2,939	)		(3,254	)
Total Senior Unsecured Notes – I&M									997,061			996,746

Spent Nuclear Fuel Liability (c)									259,023			247,084
Total Spent Nuclear Fuel Liability – I&M									259,023			247,084

Total I&M Long-term Debt									1,567,427			1,555,135
Less: Long-term Debt Due Within One Year									145,000			50,000
Long-term Debt								$	1,422,427		$	1,505,135

		Interest Rates at
		December 31,						December 31,
Type of Debt	Maturity	2007			2006			2007			2006
OPCo								(in thousands)
Pollution Control Bonds, Marshall Co., WV, Series C (a)	2014		4.25	%		3.60	%	$	50,000		$	50,000
Pollution Control Bonds, Mason Co., WV, Series C (a)	2016		3.90	%		3.60	%		50,000			50,000
Pollution Control Bonds, Marshall Co., WV, Series F (a)	2022		4.25	%		3.60	%		35,000			35,000
Pollution Control Bonds, Marshall Co., WV, Series E (a)	2022		3.70	%		3.75	%		50,000			50,000
Pollution Control Bonds, JMG Air Quality Revenue Bonds, 1997 Series A (a)	2022		5.5625	%		5.5625	%		19,565			19,565
Pollution Control Bonds, JMG Air Quality Revenue Bonds, 1997 Series B (a)	2023		5.5625	%		5.5625	%		19,565			19,565
Pollution Control Bonds, Ohio Air Quality Revenue Bonds, 1999 Series C (a)	2026		5.15	%		5.15	%		50,000			50,000
Pollution Control Bonds, JMG Air Quality Revenue Bonds, 2005 Series B (a)	2028		4.60	%		3.70	%		54,500			54,500
Pollution Control Bonds, JMG Air Quality Revenue Bonds, 2005 Series C (a)	2028		5.50	%		3.80	%		54,500			54,500
Pollution Control Bonds, JMG Air Quality Revenue Bonds, 2005 Series D (a)	2028		5.80	%		3.70	%		54,500			54,500
Pollution Control Bonds, JMG Air Quality Revenue Bonds, Series 2005 A (a)	2029		4.10	%		3.70	%		54,500			54,500
Pollution Control Bonds, West Virginia Econ. Dev. Auth., Series 2006A (a)	2036		4.50	%		3.85	%		65,000			65,000
Pollution Control Bonds, West Virginia Econ. Dev. Auth., Series 2007A (a)	2037		4.90	%		-			65,000			-
Total Pollution Control Bonds – OPCo									622,130			557,130

Senior Unsecured Medium Notes, Series A	2008		6.24	%		6.24	%		37,225			37,225
Senior Unsecured Notes, Floating Series B	2010		5.42375	%		-			400,000			-
Senior Unsecured Notes, Series J	2010		5.30	%		5.30	%		200,000			200,000
Senior Unsecured Notes, Series D	2013		5.50	%		5.50	%		250,000			250,000
Senior Unsecured Notes, Series H	2014		4.85	%		4.85	%		225,000			225,000
Senior Unsecured Notes, Series K	2016		6.00	%		6.00	%		350,000			350,000
Senior Unsecured Notes, Series I	2033		6.375	%		6.375	%		225,000			225,000
Senior Unsecured Notes, Series E	2033		6.60	%		6.60	%		250,000			250,000
Unamortized Premium (Discount)									(5,220	)		(5,932	)
Total Senior Unsecured Notes – OPCo									1,932,005			1,531,293

Notes Payable – Affiliated	2015		5.25	%		5.25	%		200,000			200,000
Total Notes Payable – Affiliated – OPCo									200,000			200,000

Notes Payable – Nonaffiliated, JMG Funding Corp., Series B	2008		6.81	%		6.81	%		1,463			7,318
Notes Payable – Nonaffiliated, JMG Funding Corp., Series D	2009		6.27	%		6.27	%		13,000			25,000
Notes Payable – Nonaffiliated, JMG Funding Corp., Series F	2009		7.21	%		7.21	%		11,000			11,000
Notes Payable – Nonaffiliated, JMG Funding Corp., Series E	2009		7.49	%		7.49	%		70,000			70,000
Total Notes Payable – Nonaffiliated - OPCo									95,463			113,318

Total OPCo Long-term Debt									2,849,598			2,401,741
Less: Long-term Debt Due Within One Year									55,188			17,854
Long-term Debt								$	2,794,410		$	2,383,887

		Interest Rates at
		December 31,						December 31,
Type of Debt	Maturity	2007			2006			2007			2006
PSO								(in thousands)
Pollution Control Bonds, Oklahoma Development Finance Auth., Series 2004 (a)	2014		3.75	%		3.60	%	$	33,700		$	33,700
Pollution Control Bonds, Red River Auth. of Texas, Series 1996 (a)	2020		-			6.00	%		-			12,660
Pollution Control Bonds, Red River Auth. of Texas, Series 2007 (a)	2020		4.45	%		-			12,660			-
Total Pollution Control Bonds – PSO									46,360			46,360

Senior Unsecured Notes, Series D	2009		4.70	%		4.70	%		50,000			50,000
Senior Unsecured Notes, Series C	2010		4.85	%		4.85	%		150,000			150,000
Senior Unsecured Notes, Series E	2011		4.70	%		4.70	%		75,000			75,000
Senior Unsecured Notes, Series F	2016		6.15	%		6.15	%		150,000			150,000
Senior Unsecured Notes, Series B	2032		6.00	%		6.00	%		200,000			200,000
Senior Unsecured Notes, Series G	2037		6.625	%		-			250,000			-
Unamortized Premium (Discount)									(3,044	)		(1,362	)
Total Senior Unsecured Notes – PSO									871,956			623,638

Total PSO Long-term Debt									918,316			669,998
Less: Long-term Debt Due Within One Year									-			-
Long-term Debt								$	918,316		$	669,998

SWEPCo
Pollution Control Bonds, Titus Co., Series 2004 (a)	2011		4.25	%		3.60	%	$	41,135		$	41,135
Pollution Control Bonds, Sabine River Auth. of Texas, Series 2006 (a)	2018		5.50	%		3.88	%		81,700			81,700
Pollution Control Bonds, Parish of DeSoto, Series 2004 (a)	2019		4.25	%		3.65	%		53,500			53,500
Unamortized Premium (Discount)									-			1,360
Total Pollution Control Bonds – SWEPCo									176,335			177,695

Senior Unsecured Notes, Series D	2015		4.90	%		4.90	%		150,000			150,000
Senior Unsecured Notes, Series C	2015		5.38	%		5.38	%		100,000			100,000
Senior Unsecured Notes, Series E	2017		5.55	%		-			250,000			-
Senior Unsecured Notes, Series F	2018		5.875	%		-			300,000			-
Unamortized Premium (Discount)									(3,353	)		(178	)
Total Senior Unsecured Notes – SWEPCo									796,647			249,822

First Mortgage Bonds, Series X (b)	2007		-			7.00	%		-			90,000
Unamortized Premium (Discount)									-			(48	)
Total First Mortgage Bonds - SWEPCo									-			89,952

Notes Payable – Affiliated	2010		4.45	%		4.45	%		50,000			50,000
Total Notes Payable – Affiliated – SWEPCo									50,000			50,000

Notes Payable – Nonaffiliated, Sabine Mines	2007		-			6.36	%		-			4,000
Notes Payable – Nonaffiliated, Sabine Mines	2008		5.43	%		5.93675	%		1,500			4,500
Notes Payable – Nonaffiliated, Dolet Hills Lignite Co., LLC	2011		4.47	%		4.47	%		14,686			19,998
Notes Payable – Nonaffiliated, Sabine Mines	2012		7.03	%		7.03	%		20,000			20,000
Notes Payable – Nonaffiliated, Sabine Mines	2024		6.37	%		-			25,000			-
Total Notes Payable – Nonaffiliated – SWEPCo									61,186			48,498

Notes Payable to Trust, 5.25% TPS Flexible	2043		5.25	%		5.25	%		113,403			113,403
Unamortized Premium (Discount)									(354	)		(364	)
Total Notes Payable to Trust - SWEPCo									113,049			113,039

Total SWEPCo Long-term Debt									1,197,217			729,006
Less: Long-term Debt Due Within One Year									5,906			102,312
Long-term Debt								$	1,191,311		$	626,694

(a)	Under the terms of the pollution control bonds, each Registrant Subsidiary is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Interest payments range from monthly to semi-annually. Letters of credit from banks, standby bond purchase agreements and insurance policies support certain series.
(b)	First mortgage bonds were secured by the first mortgage liens on Electric Property, Plant and Equipment. Interest payments were made semi-annually. SWEPCo’s first mortgage bonds were retired in September 2007.
(c)	Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has an obligation with the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets of $285 million and $274 million related to this obligation are included in Spent Nuclear Fuel and Decommissioning Trusts on its Consolidated Balance Sheets at December 31, 2007 and 2006, respectively.
(d)	In early March 2008, notification will be made to the trustee that APCo plans to redeem these pollution control bonds for possible future remarketing. As a result, APCo classified $40 million as Long-term Debt Due Within One Year – Nonaffiliated on its December 31, 2007 Consolidated Balance Sheets.
(e)	In February 2008, notification was made to the trustee that I&M plans to retire these pollution control bonds. As a result, I&M classified $45 million as Long-term Debt Due Within One Year – Nonaffiliated on its December 31, 2007 Consolidated Balance Sheets.
(f)	In February 2008, notification was made to the trustee that I&M plans to redeem these pollution control bonds for possible future remarketing. As a result, I&M classified $50 million as Long-term Debt Due Within One Year – Nonaffiliated on its December 31, 2007 Consolidated Balance Sheets.

At December 31, 2007 future annual long-term debt payments are as follows:

	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
2008	$	239,732		$	112,000		$	145,000		$	55,188		$	-		$	5,906
2009		150,017			-			-			77,500			50,000			4,406
2010		250,019			250,000			-			600,000			150,000			54,406
2011		250,022			-			-			-			75,000			42,603
2012		250,025			-			100,000			-			-			20,000
Later Years		1,724,658			942,745			1,326,023			2,122,130			646,360			1,073,603
Total Principal Amount		2,864,473			1,304,745			1,571,023			2,854,818			921,360			1,200,924
Unamortized Discount		(17,174	)		(6,521	)		(3,596	)		(5,220	)		(3,044	)		(3,707	)
Total	$	2,847,299		$	1,298,224		$	1,567,427		$	2,849,598		$	918,316		$	1,197,217

In January 2008, SWEPCo retired $367 thousand of 4.47% notes.

In February 2008, CSPCo retired $52 million of 6.51% Senior Unsecured Notes.

As of December 31, 2007, the Registrant Subsidiaries had tax-exempt long-term debt (Pollution Control Bonds) sold at auction rates that are reset every 7, 28 or 35 days and are insured by bond insurers previously AAA-rated, namely Ambac Assurance Corporation, Financial Guaranty Insurance Co., MBIA Insurance Corporation and XL Capital Assurance Inc. As of December 31, 2007, the amount outstanding by Registrant Subsidiary are as follows:

	Amount
	Outstanding
	(in millions)
APCo	$	213
CSPCo		193
I&M		262
OPCo		468
PSO		34
SWEPCo		176

Due to the exposure that these bond insurers have in connection with recent developments in the subprime credit market, the credit ratings of these insurers have been downgraded or placed on negative outlook. This has contributed to higher interest rates in successful auctions and increasing occurrences of failed auctions, including a number of auctions of the Registrant Subsidiaries’ tax-exempt long-term debt. The instruments under which the bonds are issued allow for conversion to other short-term variable-rate structures, term-put structures and fixed-rate structures. Management is planning to reduce outstanding auction rate market securities by redeeming, refunding or converting such debt securities to other permitted modes, including term-put and fixed-rate structures. Management expects this to result in additional transaction costs and higher interest charges for this tax-exempt long-term debt.

Dividend Restrictions

Under the Federal Power Act, the Registrant Subsidiaries are restricted from paying dividends out of stated capital.

Trust Preferred Securities

SWEPCo has a wholly-owned business trust that issued trust preferred securities. Effective July 1, 2003, the trust was deconsolidated due to the implementation of FIN 46. The SWEPCo trust, which holds mandatorily redeemable trust preferred securities, is reported as two components on the Consolidated Balance Sheets. The investment in the trust, which was $3 million as of December 31, 2007 and 2006, is reported as Deferred Charges and Other within Other Noncurrent Assets. The Junior Subordinated Debentures, in the amount of $113 million as of December 31, 2007 and 2006, are reported as Notes Payable to Trust within Long-term Debt – Nonaffiliated.

The business trust is treated as a nonconsolidated subsidiary of its parent company. The only asset of the business trust is the subordinated debentures issued by its parent company as specified above. In addition to the obligations under the subordinated debentures, the parent company has also agreed to a security obligation, which represents a full and unconditional guarantee of its capital trust obligation.

Lines of Credit – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries. The AEP System corporate borrowing program 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, 2007 and 2006 are included in Advances to/from Affiliates on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and corresponding authorized limits for the years ended December 31, 2007 and 2006 are described in the following tables:

Year Ended December 31, 2007:

	Maximum Borrowings from Utility Money Pool		Maximum Loans to Utility Money Pool		Average Borrowings from Utility Money Pool		Average Loans to Utility Money Pool		Loans (Borrowings) to/from Utility Money Pool as of December 31, 2007			Authorized Short-Term Borrowing Limit
Company	(in thousands)
APCo	$	406,262	$	96,543	$	162,526	$	36,795	$	(275,257	)	$	600,000
CSPCo		137,696		35,270		57,516		13,511		(95,199	)		350,000
I&M		118,570		52,748		48,033		30,277		(45,064	)		500,000
OPCo		447,335		1,564		144,776		1,564		(101,548	)		600,000
PSO		242,097		176,077		131,975		125,469		51,202			300,000
SWEPCo		245,278		97,328		108,820		31,341		(1,565	)		350,000

Year Ended December 31, 2006:

	Maximum Borrowings from Utility Money Pool			Maximum Loans to Utility Money Pool			Average Borrowings from Utility Money Pool			Average Loans to Utility Money Pool			Loans (Borrowings) to/from Utility Money Pool as of December 31, 2006				Authorized Short-Term Borrowing Limit
Company	(in thousands)
APCo		$	283,872		$	314,064		$	169,937		$	149,103		$	(34,975	)		$	600,000
CSPCo			48,337			95,977			14,703			45,886			(696	)			350,000
I&M			128,071			322,067			62,659			292,504			(91,173	)			500,000
OPCo			351,302			40,382			102,302			15,845			(181,281	)			600,000
PSO			167,456			146,657			94,328			58,541			(76,323	)			300,000
SWEPCo			189,021			24,209			66,848			9,411			(188,965	)			350,000

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool for the years ended December 31, 2007, 2006 and 2005 were as follows:

	Years Ended December 31,
	2007			2006			2005
Maximum Interest Rate		5.94	%		5.41	%		4.49	%
Minimum Interest Rate		5.16	%		3.32	%		1.63	%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the years ended December 31, 2007, 2006 and 2005 are summarized for all Registrant Subsidiaries in the following table:

	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31,									Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31,
	2007			2006			2005			2007			2006			2005
Company
APCo		5.38	%		4.63	%		3.40	%		5.75	%		4.93	%		3.15	%
CSPCo		5.46	%		4.76	%		3.95	%		5.39	%		4.37	%		3.03	%
I&M		5.37	%		4.80	%		3.43	%		5.80	%		3.84	%		2.12	%
OPCo		5.39	%		4.74	%		3.86	%		5.43	%		5.12	%		2.57	%
PSO		5.48	%		5.02	%		3.37	%		5.31	%		4.35	%		3.56	%
SWEPCo		5.47	%		4.79	%		4.10	%		5.34	%		4.45	%		2.62	%

Interest expense related to the Utility Money Pool is included in Interest Expense in each of the Registrant Subsidiaries’ Financial Statements. The Registrant Subsidiaries incurred interest expense for amounts borrowed from the Utility Money Pool as follows:

	Years Ended December 31,
	2007		2006		2005
Company	(in thousands)
APCo	$	6,897	$	2,656	$	2,830
CSPCo		2,561		284		280
I&M		2,399		2,772		2,854
OPCo		7,958		4,473		1,056
PSO		6,398		3,037		637
SWEPCo		4,414		3,234		293

Interest income related to the Utility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ Financial Statements. The Registrant Subsidiaries earned interest income for amounts advanced to the Utility Money Pool as follows:

	Years Ended December 31,
	2007		2006		2005
Company	(in thousands)
APCo	$	470	$	5,007	$	543
CSPCo		142		1,231		2,757
I&M		171		967		6
OPCo		-		63		1,129
PSO		881		941		431
SWEPCo		542		216		649

Short-term Debt

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

		December 31,
		2007				2006
	Type of Debt	Outstanding Amount		Interest Rate (a)		Outstanding Amount		Interest Rate (a)
Company		(in thousands)				(in thousands)
OPCo	Commercial Paper – JMG (b)	$	701	5.35	%	$	1,203	5.56	%
SWEPCo	Line of Credit – Sabine		285	5.25	%		17,143	6.38	%

(a)	Weighted average rate.
(b)	This commercial paper is specifically associated with the Gavin Scrubber and is backed by a separate credit facility. This commercial paper does not reduce OPCo’s available liquidity.

Sale of Receivables – AEP Credit

AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires from affiliated utility subsidiaries to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities,” allowing the receivables to be taken off of AEP Credit’s balance sheet and allowing AEP Credit to repay any debt obligations. AEP has no ownership interest in the commercial paper conduits and is not required to consolidate these entities in accordance with GAAP. AEP Credit continues to service the receivables. This off-balance sheet transaction was entered into to allow AEP Credit to repay its outstanding debt obligations, continue to purchase the AEP operating companies’ receivables, and accelerate AEP Credit’s cash collections.

In October 2007, AEP renewed AEP Credit’s sale of receivables agreement. The sale of receivables agreement provides a commitment of $650 million from banks and commercial paper conduits to purchase receivables from AEP Credit. Under the agreement, the commitment will increase to $700 million for the months of August and September to accommodate seasonal demand. This agreement will expire in October 2008. AEP intends to extend or replace the sale of receivables agreement. The previous sale of receivables agreement, which expired in August 2007 and was extended until October 2007, provided a commitment of $600 million from a bank conduit to purchase receivables from AEP Credit. At December 31, 2007, $507 million of commitments to purchase accounts receivable were outstanding under the receivables agreement. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivable less an allowance for anticipated uncollectible accounts.

AEP Credit purchases accounts receivable through purchase agreements with CSPCo, I&M, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in all of its regulatory jurisdictions, only a portion of APCo’s accounts receivable are sold to AEP Credit.

Comparative accounts receivable information for AEP Credit is as follows:

	Years Ended December 31,
	2007				2006				2005
	($ in millions)
Proceeds from Sale of Accounts Receivable		$	6,970			$	6,849			$	5,925
Loss on Sale of Accounts Receivable		$	33			$	31			$	18
Average Variable Discount Rate			5.39	%			5.02	%			3.23	%

	December 31,
	2007			2006
	(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts		$	71		$	87
Deferred Revenue from Servicing Accounts Receivable			1			1
Retained Interest if 10% Adverse Change in Uncollectible Accounts			68			85
Retained Interest if 20% Adverse Change in Uncollectible Accounts			66			83

Historical loss and delinquency amounts for the AEP System’s customer accounts receivable managed portfolio is as follows:

	December 31,
	2007			2006
	(in millions)
Customer Accounts Receivable Retained	$	730		$	676
Accrued Unbilled Revenues Retained		379			350
Miscellaneous Accounts Receivable Retained		60			44
Allowance for Uncollectible Accounts Retained		(52	)		(30	)
Total Net Balance Sheet Accounts Receivable		1,117			1,040
Customer Accounts Receivable Securitized		507			536
Total Accounts Receivable Managed	$	1,624		$	1,576

Net Uncollectible Accounts Written Off	$	24		$	31

Customer accounts receivable retained and securitized for the domestic electric operating companies are managed by AEP Credit. Miscellaneous accounts receivable have been fully retained and not securitized.

Delinquent customer accounts receivable for the electric utility affiliates that AEP Credit currently factors were $30 million and $29 million at December 31, 2007 and 2006, respectively. AEP Credit’s delinquent customer accounts receivable represents accounts greater than 30 days past due.

Under the factoring arrangement, participating 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 financing costs, uncollectible accounts experience for each company’s receivables and administrative costs. The costs of factoring customer accounts receivable are reported in Other Operation of the participant’s statement of operations.

The amount of factored accounts receivable and accrued unbilled revenues for each Registrant Subsidiary was as follows:

	December 31,
	2007		2006
Company	(in millions)
APCo	$	83.8	$	102.1
CSPCo		133.1		142.5
I&M		101.0		94.5
OPCo		118.5		140.2
PSO		109.3		119.4
SWEPCo		94.3		102.7

The fees paid by the Registrant Subsidiaries to AEP Credit for factoring customer accounts receivable were:

	Years Ended December 31,
	2007		2006		2005
Company	(in millions)
APCo	$	6.9	$	6.3	$	5.1
CSPCo		15.2		13.7		7.4
I&M		9.3		9.2		7.4
OPCo		12.6		11.1		6.1
PSO		14.1		16.3		11.1
SWEPCo		10.7		10.5		8.3

16.	RELATED PARTY TRANSACTIONS

For other related party transactions, also see “Lines of Credit – AEP System” and “Sale of Receivables-AEP Credit” sections of Note 15.

AEP System Power Pool

APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (the Interconnection Agreement), defining how they share the costs and benefits associated with their generating plants. This sharing is based upon each company’s “member-load-ratio,” which is calculated monthly on the basis of each company’s maximum peak demand in relation to the sum of the maximum peak demands of all five companies during the preceding 12 months. In addition, since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been 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.

Power, gas and risk management activities are conducted by the AEP Power Pool and profits/losses are shared among the parties under the System Integration Agreement. 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 over-the-counter 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, the AEP Power Pool 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. In February 2006, AEP filed with the FERC a proposed amendment to the CSW Operating Agreement to remove TCC and TNC as parties to the agreement. Pursuant to Texas electric restructuring law, those companies exited the generation and load-servicing businesses. AEP made a similar filing to remove those two companies as parties to the System Integration Agreement. The filings were approved effective May 1, 2006 and April 1, 2006, respectively.

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)

AEP’s System Integration Agreement, which has been approved by the FERC, provides for the integration and coordination of AEP’s East companies and 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). It 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 each zone.

In November 2005, AEP filed with the FERC a proposed amendment to the SIA to change the method of allocating profits from off-system electricity sales between the East and West zones. The proposed method causes such profits to be allocated generally on the basis of the zone in which the underlying transactions occur or originate. The filing was made in accordance with a provision of the agreement that called for a re-evaluation of the allocation method effective January 1, 2006 and was approved as filed effective April 1, 2006.

Power generated by or allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any Registrant Subsidiary is primarily sold to customers (or in the case of the ERCOT area of Texas, REPs) by such Registrant Subsidiary at rates approved (other than in Ohio, Virginia and the ERCOT area of Texas) by the public utility commission in the jurisdiction of sale. In Ohio and Virginia, such rates are based on a statutory formula as those jurisdictions transition to the use of market rates for generation (see Note 4). In the ERCOT area of Texas, such rates are market-based.

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.

Affiliated Revenues and Purchases

The following table shows the revenues derived from sales to the pools, direct sales to affiliates, natural gas contracts with AEPES, and other revenues for the years ended December 31, 2007, 2006 and 2005:

	APCo		CSPCo		I&M			OPCo		PSO		SWEPCo
Related Party Revenues	(in thousands)
Year Ended December 31, 2007
Sales to East System Pool	$	161,969	$	124,903	$	237,035		$	671,106	$	N/A	$	N/A
Direct Sales to East Affiliates		75,843		-		-			69,693		2,717		2,172
Direct Sales to West Affiliates		17,366		9,930		10,136			11,729		51,913		35,147
Natural Gas Contracts with AEPES		4,440		697		(1,123	)		343		1,405		1,657
Other		3,448		7,582		2,366			4,181		13,071		14,126
Total Revenues	$	263,066	$	143,112	$	248,414		$	757,052	$	69,106	$	53,102

	APCo			CSPCo			I&M			OPCo			PSO		SWEPCo
Related Party Revenues	(in thousands)
Year Ended December 31, 2006
Sales to East System Pool	$	163,633		$	76,938		$	285,048		$	610,865		$	N/A	$	N/A
Direct Sales to East Affiliates		70,402			-			-			65,386			227		220
Direct Sales to West Affiliates		20,009			12,117			12,538			15,306			47,184		37,284
Natural Gas Contracts with AEPES		(19,998	)		(9,705	)		(9,296	)		(17,219	)		-		-
Other		4,546			6,376			2,743			11,005			4,582		4,941
Total Revenues	$	238,592		$	85,726		$	291,033		$	685,343		$	51,993	$	42,445

APCo

CSPCo

I&M

OPCo

PSO

SWEPCo

Related Party Revenues	(in thousands)
Year Ended December 31, 2005
Sales to East System Pool	$	162,014	$	70,165	$	314,677	$	542,364	$	N/A	$	N/A
Direct Sales to East Affiliates		70,130		-		-		64,449		-		-
Direct Sales to West Affiliates		25,776		14,162		14,998		19,562		33,992		61,555
Natural Gas Contracts with AEPES		60,793		34,324		33,461		46,751		-		-
Other		3,620		5,759		2,896		8,726		5,686		3,853
Total Revenues	$	322,333	$	124,410	$	366,032	$	681,852	$	39,678	$	65,408

N/A =

Not Applicable

The following table shows the purchased power expense incurred from purchases from the pools and affiliates for the years ended December 31, 2007, 2006 and 2005:

	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Related Party Purchases	(in thousands)
Year Ended December 31, 2007
Purchases from East System Pool	$	597,951	$	297,934	$	133,885	$	110,579	$	N/A	$	N/A
Direct Purchases from East Affiliates		733		63,803		207,160		-		31,916		20,982
Direct Purchases from West Affiliates		1,609		911		936		1,080		34,408		51,913
Gas Purchases from AEPES		-		-		-		13,449		N/A		N/A
Total Purchases	$	600,293	$	362,648	$	341,981	$	125,108	$	66,324	$	72,895

	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Related Party Purchases	(in thousands)
Year Ended December 31, 2006
Purchases from East System Pool	$	492,619	$	365,425	$	126,345	$	108,151	$	N/A	$	N/A
Direct Purchases from East Affiliates		-		-		216,723		-		37,504		27,257
Direct Purchases from West Affiliates		137		85		88		104		31,902		47,201
Gas Purchases from AEPES		-		-		-		5,396		N/A		N/A
Total Purchases	$	492,756	$	365,510	$	343,156	$	113,651	$	69,406	$	74,458

	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Related Party Purchases	(in thousands)
Year Ended December 31, 2005
Purchases from East System Pool	$	453,600	$	362,959	$	116,735	$	104,777	$	43,516	$	36,573
Direct Purchases from East Affiliates		-		-		189,382		12,113		281		278
Direct Purchases from West Affiliates		-		-		-		-		61,564		34,060
Total Purchases	$	453,600	$	362,959	$	306,117	$	116,890	$	105,361	$	70,911

N/A =

Not Applicable

The above summarized related party revenues and expenses are reported as consolidated and are presented as Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates on the income statements of each AEP Power Pool member. Since all of the above pool members are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses.

AEP System Transmission Pool

AEP’s System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP’s East companies and AEP West companies zones. Similar to the System Integration Agreement, the System Transmission Integration Agreement functions as an umbrella agreement in addition to the Transmission Equalization Agreement (TEA) and the Transmission Coordination Agreement (TCA). The System Transmission Integration Agreement contains two service schedules that govern:

·	The allocation of transmission costs and revenues and
·	The allocation of third-party transmission costs and revenues and AEP System dispatch costs.

The Transmission Integration Agreement anticipates that additional service schedules may be added as circumstances warrant.

APCo, CSPCo, I&M, KPCo and OPCo are parties to the TEA, 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). Like the Interconnection Agreement, this sharing is based upon each company’s “member-load-ratio.”

The following table shows the net charges (credits) allocated among the Registrant Subsidiaries, party to the TEA, during the years ended December 31, 2007, 2006 and 2005:

	Years Ended December 31,
	2007				2006				2005
Company	(in thousands)
APCo		$	(24,900	)		$	(16,000	)		$	8,900
CSPCo			51,900				46,200				34,600
I&M			(34,600	)			(37,300	)			(47,000	)
OPCo			8,500				9,100				7,000

The net charges (credits) shown above are recorded in Other Operation on the Registrant Subsidiaries’ income statements.

PSO, SWEPCo, TCC, TNC and AEPSC are parties to the TCA, originally dated January 1, 1997. 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 AEP West companies, including 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 tariff.

Under the TCA, the AEP West companies delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. Prior to September 2005, TCA also provided for the allocation among the AEP West companies of revenues collected for transmission and ancillary services provided under the OATT. Since then, these allocations have been governed by the FERC-approved OATT for the SPP (with respect to PSO and SWEPCo) and PUCT-approved protocols for ERCOT (with respect to TCC and TNC).

The following table shows the net charges (credits) allocated among parties to the TCA prior to September 2005, and pursuant to the SPP OATT protocols as described above during the years ended December 31, 2007, 2006 and 2005:

	Years Ended December 31,
	2007				2006				2005
Company	(in thousands)
PSO		$	500			$	1,800			$	3,500
SWEPCo			(500	)			(1,900	)			5,200

The net charges (credits) shown above are recorded in the Other Operation on the Registrant Subsidiaries’ income statements.

ERCOT Contracts Transferred to AEPEP

Effective January 1, 2007, PSO and SWEPCo transferred certain existing ERCOT energy marketing contracts to AEPEP and entered into intercompany financial and physical purchase and sale agreements with AEPEP. This was done to lock in PSO and SWEPCo’s margins on ERCOT trading and marketing contracts and to transfer the future associated commodity price and credit risk to AEPEP. The contracts will mature over the next three years.

PSO and SWEPCo have historically presented third party ERCOT trading and marketing activity on a net basis in Revenues - Electric Generation, Transmission and Distribution. The applicable ERCOT third party trading and marketing contracts that were not transferred to AEPEP will remain until maturity on PSO and SWEPCo and will be presented on a net basis in Sales to AEP Affiliates on PSO’s and SWEPCo’s Statements of Income.

The following table indicates the sales to AEPEP and the amounts reclassified from third party to affiliate:

	Year Ended December 31, 2007
				Third Party Amounts				Net Amount
	Net Settlement			Reclassified to				included in Sales
	With AEPEP			Affiliate				to AEP Affiliates
Company	(in thousands)
PSO		$	163,922		$	(155,274	)		$	8,648
SWEPCo			202,135			(191,940	)			10,195

The following table indicates the affiliated portion of risk management assets and liabilities reflected on PSO’s and SWEPCo’s balance sheets associated with these contracts:

	December 31, 2007
	PSO			SWEPCo
Current	(in thousands)
Risk Management Assets	$	21,174		$	24,973
Risk Management Liabilities		(622	)		(734	)

Noncurrent
Long-term Risk Management Assets	$	1,531		$	1,806
Long-term Risk Management Liabilities		-			-

SPP Customers and Assets Transferred from TNC to SWEPCo

SWEPCo’s and approximately 3% of TNC’s businesses were in SPP. A petition was filed in May 2006 requesting approval to transfer Mutual Energy SWEPCO L.P.’s (a subsidiary of AEP C&I Company, LLC) customers and TNC’s facilities and certificated service territory located in the SPP area to SWEPCo. In January 2007, the final regulatory approval was received for the transfers. The transfers were effective February 2007 and were recorded at net book value of $12 million.

Natural Gas Contracts with DETM

Effective October 31, 2003, AEPES assigned to AEPSC, as agent for the AEP East companies, approximately $97 million (negative value) associated with its natural gas contracts with DETM. The assignment was executed in order to consolidate DETM positions within AEP. Beginning in 2007, PSO and SWEPCo were allocated a portion of the DETM assignment based on the SIA methodology of sharing trading and marketing margins between the AEP East companies and PSO and SWEPCo. Concurrently, in order to ensure that there would be no financial impact to the AEP East companies, PSO or SWEPCo as a result of the assignment, AEPES and AEPSC entered into agreements requiring AEPES to reimburse AEPSC for any related cash settlements and all income related to the assigned contracts. There is no impact to the AEP consolidated financial statements. The following table represents the Registrant Subsidiaries’ risk management liabilities related to DETM at December 31:

	December 31,
	2007			2006
Company	(in thousands)
APCo	$	(9,439	)	$	(11,224	)
CSPCo		(5,470	)		(7,154	)
I&M		(5,255	)		(7,517	)
OPCo		(6,373	)		(8,503	)
PSO		(331	)		-
SWEPCo		(390	)		-

Fuel Agreement between OPCo and AEPES

OPCo and National Power Cooperative, Inc (NPC) have an agreement whereby OPCo operates a 500 MW gas plant owned by NPC (Mone Plant). AEPES entered into a fuel management agreement with those two parties to manage and procure fuel for the Mone Plant. The gas purchased by AEPES and used in generation is first sold to OPCo then allocated to the AEP East companies, who have an agreement to purchase 100% of the available generating capacity from the plant through May 2012. The related purchases of gas managed by AEPES were as follows:

	Years Ended December 31,
	2007			2006			2005
Company	(in thousands)
APCo		$	4,377		$	1,660		$	3,905
CSPCo			2,483			1,016			2,113
I&M			2,553			1,065			2,255
OPCo			3,106			1,257			2,916

These purchases are reflected in Purchased Electricity for Resale on the Registrant Subsidiaries’ income statements.

Unit Power Agreements (UPA)

Lawrenceburg UPA between CSPCo and AEGCo

In March 2007, CSPCo and AEGCo entered into a 10-year UPA for the entire output from the Lawrenceburg Plant effective with AEGCo’s purchase of the plant in May 2007. The UPA has an option for an additional 2-year period. I&M operates the plant under an agreement with AEGCo. Under the UPA, CSPCo 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. CSPCo paid AEGCo $84.4 million for the year ended December 31, 2007. On its 2007 Consolidated Statements of Income, CSPCo recorded these purchases in Other Operation expense for the capacity and depreciation portion, and in Purchased Electricity from AEP Affiliates for the variable cost portion.

I&M UPA between AEGCo and I&M

A unit power agreement 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. 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) for such amounts, as when added to amounts received by AEGCo from any other sources, will be at least 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.

KPCo UPA between AEGCo and KPCo

Pursuant to an assignment between I&M and KPCo, and a unit power agreement 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 has agreed to pay 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 unit power agreement ends in December 2022. See Affiliated Revenues and Purchases section of this note.

Jointly-Owned Electric Utility Plants

APCo and OPCo jointly own Amos Plant and Sporn Plant. The costs of operating these facilities are apportioned between owners based on ownership interests. Each company’s share of these costs is included in the appropriate expense accounts on its respective Consolidated Statements of Income. Each company’s investment in these plants is included in Property, Plant and Equipment on its respective Consolidated Balance Sheets.

AEGCo and I&M jointly own one generating unit and jointly lease the other generating unit of the Rockport Plant. The costs of operating this facility are equally apportioned between AEGCo and I&M since each company has a 50% interest. Each company’s share of costs is included in the appropriate expense accounts on its respective income statements. Each company’s investment in these plants is included in Property, Plant and Equipment on its respective balance sheets.

PSO and TNC jointly own the Oklaunion power plant along with two nonaffiliated companies. TCC sold its share to one of the nonaffiliated companies in February 2007. The costs of operating the facility are apportioned between owners based on ownership interests. Each company’s share of these costs is included in the appropriate expense accounts on its respective income statement. PSO’s and TNC’s investment in this plant is included in Property, Plant and Equipment on its respective balance sheets.

Cook Coal Terminal

In 2007, 2006 and 2005, Cook Coal Terminal, a division of OPCo, performed coal transloading services at cost for APCo and I&M. OPCo included revenues for these services in Other-Affiliated and expenses in Other Operation on its Consolidated Statements of Income. The coal transloading revenues were as follows:

	Years Ended December 31,
	2007			2006			2005
Company	(in thousands)
APCo		$	53		$	899		$	1,770
I&M			18,364			15,869			13,653

APCo and I&M recorded the cost of the transloading services in Fuel on their respective Consolidated Balance Sheets.

In addition, Cook Coal Terminal provided coal transloading services for OVEC in 2007, 2006 and 2005. OPCo recorded revenue as Other – Nonaffiliated on its Consolidated Statements of Income in the amounts of $290 thousand, $172 thousand and $513 thousand in 2007, 2006 and 2005, respectively. OVEC is 43.47% owned by AEP and CSPCo.

In 2007, 2006 and 2005, Cook Coal Terminal also performed railcar maintenance services at cost for APCo, I&M, PSO and SWEPCo. OPCo includes revenues for these services in Sales to AEP Affiliates and expenses in Other Operation on its Consolidated Statements of Income. The railcar maintenance revenues were as follows:

	Years Ended December 31,
	2007			2006			2005
Company	(in thousands)
APCo		$	8		$	278		$	-
I&M			2,490			2,491			2,816
PSO			307			905			117
SWEPCo			1,479			433			163

APCo, I&M, PSO and SWEPCo record the cost of the railcar maintenance services in Fuel on their respective 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 $2.2 million and $1.2 million for railcar services provided in 2007 and 2006, respectively, and billed PSO $755 thousand and $905 thousand in 2007 and 2006, respectively. These billings, for SWEPCo, and costs, for I&M and PSO, are recorded in Fuel on the Registrant Subsidiaries’ respective balance sheets.

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 records revenues from barging, transloading and other services as Other – Affiliated on its Consolidated Statements of Income. The affiliates record these costs paid to I&M as fuel expense or operation expense. The amount of affiliated revenues and affiliated expenses were:

	Years Ended December 31,
	2007		2006		2005
Company	(in millions)
I&M – revenues	$	49.1	$	47.9	$	43.1
AEGCo – expense		9.2		14.9		11.4
APCo – expense		16.6		14.5		18.5
KPCo - expense		0.1		0.1		0.1
OPCo – expense		7.1		2.1		2.5
MEMCO – expense (Nonutility subsidiary of AEP)		16.1		16.3		10.6

In addition, I&M provided transloading services to OVEC. I&M recorded the revenue, which totaled $89 thousand, $121 thousand and $215 thousand for 2007, 2006 and 2005, respectively, in Other – Nonaffiliated on its Consolidated Statements of Income.

Services Provided by MEMCO

AEP MEMCO LLC (MEMCO) provides services for barge towing and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation. For the years ended December 31, 2007, 2006 and 2005, I&M recorded $18 million, $16 million and $14.1 million, respectively.

Central Machine Shop

APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers on its balance sheet the cost of performing the services, then transfers the cost to the affiliate for reimbursement. The affiliated subsidiaries recorded these billings as capital or maintenance expense 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,
	2007		2006		2005
Company	(in thousands)
CSPCo	$	505	$	617	$	790
I&M		2,464		1,826		3,620
KPCo		167		181		285
OPCo		1,999		2,831		2,684
PSO		317		801		21
SWEPCo		44		2		-

In addition, APCo billed OVEC and IKEC a total of $898 thousand, $951 thousand and $957 thousand for 2007, 2006 and 2005, respectively.

Affiliate Railcar Agreement

Certain AEP affiliated 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 Registrant Subsidiaries record these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on their balance sheets and such costs are recoverable from customers. The following table shows the net effect of the railcar agreement on the affiliated subsidiaries’ respective 2007 balance sheets:

	Billing Company
	AEP Transportation (a)		APCo		I&M		OPCo		PSO		SWEPCo		Total
Billed Company	(in thousands)
APCo	$	-	$	-	$	-	$	1,977	$	-	$	-	$	1,977
I&M		533		-		-		829		387		595		2,344
KPCo		-		90		-		183		-		-		273
OPCo		11		945		429		-		16		17		1,418
PSO		530		-		932		137		-		223		1,822
SWEPCo		1,384		-		2,266		513		197		-		4,360
Total	$	2,458	$	1,035	$	3,627	$	3,639	$	600	$	835	$	12,194

(a) AEP Transportation is a 100%-owned nonutility subsidiary of AEP, Inc.

I&M Urea Transloading

I&M provides urea transloading services to APCo, KPCo and OPCo. Urea is a chemical used to control NOx emissions at certain generation plants in the AEP System. I&M records revenues from urea transloading services as Other – Affiliated on its Consolidated Statements of Income. The affiliates record costs paid to I&M for barging services as Fuel and Other Consumables Used for Electric Generation on their respective statements of income. The amount of affiliated revenues and affiliated expenses were:

	Years Ended December 31,
	2007			2006			2005
Company	(in thousands)
I&M – revenues		$	1,014		$	853		$	1,412
APCo – expense			378			413			644
KPCo – expense			80			68			133
OPCo – expense			556			372			635

OPCo Indemnification Agreement with AEP Resources

OPCo had an indemnification agreement with AEP Resources (AEPR), a nonutility subsidiary of AEP, whereby AEPR held OPCo harmless from market exposure related to OPCo’s Power Purchase and Sale Agreement dated November 15, 2000 with Dow Chemical Company. In 2006 and 2005, AEPR paid OPCo $14.9 million and $29.6 million, respectively, which is reported in OPCo’s Other Operation on its Consolidated Statements of Income. As a result of the sale of the Plaquemine Cogeneration Facility and subsequent termination of OPCo’s Power Purchase and Sale Agreement in November 2006, there were no indemnification payments in 2007. See “TEM Litigation – Affecting OPCo” section of Note 6.

Purchased Power from OVEC

The amounts of power purchased by the Registrant Subsidiaries from OVEC, which is 43.47% owned by AEP and CSPCo, for the years ended December 31, 2007, 2006 and 2005 were:

	Years Ended December 31,
	2007			2006			2005
Company	(in thousands)
APCo		$	81,612		$	82,422		$	77,337
CSPCo			23,102			22,821			20,602
I&M			40,827			38,961			30,961
OPCo			80,561			78,579			66,680

The amounts shown above are recoverable from customers and are included in Purchased Electricity for Resale in the Registrant Subsidiaries’ respective Consolidated Statements of Income.

AEP Power Pool Purchases from OVEC

Beginning in 2006, the AEP Power Pool began purchasing power from OVEC as part of wholesale marketing and risk management activity. These purchases are reflected in Electric Generation, Transmission and Distribution revenues in the Registrant Subsidiaries’ respective Consolidated Statements of Income. The current agreement will expire in May 2008. The following table shows the amounts recorded by the Registrant Subsidiaries for the years ended December 31, 2007 and 2006:

	Years Ended December 31,
	2007			2006
Company	(in thousands)
APCo		$	9,830		$	11,284
CSPCo			5,553			6,915
I&M			5,530			7,189
OPCo			6,526			8,576

Purchased Power from Sweeny

On behalf of the AEP West companies, CSPCo entered into a ten year Power Purchase Agreement (PPA) with Sweeny, which was 50% owned by AEP. The PPA was for unit contingent power up to a maximum of 315 MW from January 1, 2005 through December 31, 2014. The delivery point for the power under the PPA was in TCC’s system. The power was sold in ERCOT. Prior to May 1, 2006, the purchase of Sweeny power and its sale to nonaffiliates were shared among the AEP West companies under the CSW Operating Agreement. After May 1, 2006, the purchases and sales were shared between PSO and SWEPCo. See “CSW Operating Agreement” section of this note. In April 2007, AEP Energy Partners (AEPEP) was assigned the Sweeny PPA from CSPCo and became responsible for purchasing the Sweeny power instead of PSO and SWEPCo. In October 2007, AEP sold its 50% interest in the Sweeny facility along with the ten year PPA to Conoco Phillips. The purchases from Sweeny were:

	Years Ended December 31,
	2007			2006			2005
Company	(in thousands)
PSO		$	13,955		$	53,354		$	57,742
SWEPCo			16,443			62,794			50,618

The amounts shown above are recorded in Purchased Electricity for Resale on the Registrant Subsidiaries’ respective income statements.

OPCo Coal Transfers

In 2006, OPCo sold 115,877 tons of coal from its Mitchell plant inventory to APCo for $4.8 million. The coal was sold at cost, based on a weighted average cost method of carrying inventory. APCo paid for the cost of transporting the coal from OPCo’s facility to its delivery points at APCo’s Amos Plant and Sporn Plant. The amount above was transferred from Fuel on OPCo’s Consolidated Balance Sheet to APCo’s Consolidated Balance Sheet at the time of the sale.

Sales and Purchases of Property

Certain AEP affiliated subsidiaries had sales and purchases of electric property individually amounting to $100 thousand or more, for the years ended December 31, 2007, 2006 and 2005 as shown in the following table:

	Year Ended December 31,
	2007
Companies	(in thousands)
APCo to I&M	$	2,893
APCo to OPCo		2,695
I&M to PSO		1,729
I&M to SWEPCo		212
OPCo to I&M		2,070
OPCo to KPCo		133
OPCo to WPCo		281
PSO to SWEPCo		228
SWEPCo to PSO		212
TNC to SWEPCo		11,649

	Year Ended December 31,
	2006
Companies	(in thousands)
APCo to OPCo	$	1,037
CSPCo to OPCo		592
I&M to CSPCo		173
I&M to SWEPCo		111
I&M to WPCo		201
KPCo to APCo		191
OPCo to APCo		3,822
OPCo to KPCo		1,324
OPCo to PSO		760

	Year Ended December 31, 2005
Companies	(in thousands)
APCo to I&M	$	554
APCo to OPCo		637
I&M to APCo		1,135
I&M to OPCo		3,423
KPCo to OPCo		101
OPCo to APCo		1,057
OPCo to I&M		2,142

In addition, certain AEP affiliated subsidiaries had aggregate affiliated sales and purchases of meters and transformers for the years ended December 31, 2007, 2006 and 2005 as shown in the following table:

Year Ended December 31, 2007

	Purchaser
	APCo		CSPCo		I&M		KGPCo		KPCo		OPCo		PSO		SWEPCo		TCC		TNC		WPCo		TOTAL
Seller	(in thousands)
APCo	$	-	$	38	$	61	$	578	$	518	$	281	$	115	$	33	$	61	$	-	$	13	$	1,698
CSPCo		-		-		11		-		6		1,132		31		20		-		-		-		1,200
I&M		22		79		-		3		4		436		54		29		4		-		20		651
KGPCo		246		-		-		-		1		1		-		-		-		-		-		248
KPCo		345		38		21		10		-		124		85		7		-		-		66		696
OPCo		456		2,978		614		-		197		-		3		145		6		-		299		4,698
PSO		20		77		-		-		-		-		-		73		-		2		-		172
SWEPCo		-		-		3		-		-		1		262		-		26		13		-		305
TCC		20		13		-		-		-		40		1		76		-		763		-		913
TNC		-		-		1		-		-		-		10		456		199		-		-		666
WPCo		-		1		6		-		5		132		-		3		-		-		-		147
Total	$	1,109	$	3,224	$	717	$	591	$	731	$	2,147	$	561	$	842	$	296	$	778	$	398	$	11,394

Year Ended December 31, 2006

	Purchaser
	APCo		CSPCo		I&M		KGPCo		KPCo		OPCo		PSO		SWEPCo		TCC		TNC		WPCo		TOTAL
Seller	(in thousands)
APCo	$	-	$	17	$	187	$	676	$	3,206	$	2,019	$	157	$	669	$	1,631	$	-	$	459	$	9,021
CSPCo		87		-		2		2		1		661		17		-		-		-		-		770
I&M		86		44		-		-		18		2,052		25		158		2		-		10		2,395
KGPCo		179		-		-		-		-		1		-		-		179		-		-		359
KPCo		2,178		75		40		11		-		254		28		-		3		-		9		2,598
OPCo		1,750		2,545		910		-		504		-		330		211		1		-		391		6,642
PSO		1		1		26		-		-		1		-		129		30		2		-		190
SWEPCo		16		-		-		-		-		12		95		-		37		-		-		160
TCC		12		-		-		36		-		18		10		50		-		1,266		-		1,392
TNC		-		-		-		-		-		-		17		4		209		-		-		230
WPCo		7		28		21		-		3		247		8		-		-		-		-		314
Total	$	4,316	$	2,710	$	1,186	$	725	$	3,732	$	5,265	$	687	$	1,221	$	2,092	$	1,268	$	869	$	24,071

Year Ended December 31, 2005

	Purchaser
	APCo		CSPCo		I&M		KGPCo		KPCo		OPCo		PSO		SWEPCo		TCC		TNC		WPCo		TOTAL
Seller	(in thousands)
APCo	$	-	$	9	$	1,847	$	371	$	1,577	$	677	$	208	$	210	$	357	$	-	$	717	$	5,973
CSPCo		36		-		23		-		8		605		47		29		-		-		-		748
I&M		59		8		-		4		22		2,903		-		3		-		-		19		3,018
KGPCo		270		-		4		-		-		19		-		-		-		-		-		293
KPCo		381		1		-		1		-		135		-		-		-		-		-		518
OPCo		1,246		1,901		2,504		28		304		-		182		94		69		-		335		6,663
PSO		12		-		-		-		-		-		-		52		8		3		-		75
SWEPCo		10		-		-		-		-		4		67		-		40		3		-		124
TCC		164		-		2		-		-		29		2		130		-		1,642		-		1,969
TNC		-		-		-		-		-		-		-		17		317		-		-		334
WPCo		-		-		-		-		-		196		-		-		-		-		-		196
Total	$	2,178	$	1,919	$	4,380	$	404	$	1,911	$	4,568	$	506	$	535	$	791	$	1,648	$	1,071	$	19,911

The amounts above are recorded in Property, Plant and Equipment. Transfers are performed at cost.

Global Borrowing Notes

AEP issued long-term debt, portions of which were loaned to the Registrant Subsidiaries. The debt is reflected in Long-term Debt – Affiliated on the Registrant Subsidiaries’ respective balance sheets. AEP pays the interest on the global notes, but the Registrant Subsidiaries accrue interest for their respective share of the global borrowing and remit the interest to AEP. The accrued interest is reflected in either Accrued Interest or Other in the Current Liabilities section of the Registrant Subsidiaries’ respective balance sheets. APCo, CSPCo, OPCo, PSO and SWEPCo participated in the global borrowing arrangement during the reporting periods.

AEPSC

AEPSC provides certain managerial and professional services to AEP System companies. The costs of the services are billed to its affiliated companies by AEPSC on a direct-charge basis, whenever possible, and on reasonable bases 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, which is furnished to AEPSC by AEP. Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered and are recoverable from customers. During 2005, AEPSC and its billings were subject to regulation by the SEC under the PUHCA of 1935. Effective February 8, 2006, the PUHCA of 2005 was enacted, which repealed the PUHCA of 1935 and transferred the regulatory responsibility from the SEC to the FERC.

Intercompany Billings

The Registrant Subsidiaries and other AEP affiliated 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 bases 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. Billings between affiliated subsidiaries are capitalized or expensed depending on the nature of the services rendered.

17.	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 table provides the annual composite depreciation rates by functional class generally used by the Registrant Subsidiaries:

APCo

2007	Regulated												Nonregulated

Functional Class of Property	Property, Plant and Equipment			Accumulated Depreciation				Annual Composite Depreciation Rate			Depreciable Life Ranges		Property, Plant and Equipment			Accumulated Depreciation			Annual Composite Depreciation Rate	Depreciable Life Ranges
	(in thousands)										(in years)		(in thousands)							(in years)
Production		$	3,625,788		$	1,531,999			2.0	%		40-121		$	-		$	-	N.M.	N.M.
Transmission			1,675,081			408,126			1.3	%		25-87			-			-	N.M.	N.M.
Distribution			2,372,687			502,503			3.1	%		11-52			-			-	N.M.	N.M.
CWIP			713,063			(15,104	)	N.M.			N.M.				-			-	N.M.	N.M.
Other			318,190			151,746			7.1	%		24-55			33,637			12,563	N.M.	N.M.
Total		$	8,704,809		$	2,579,270								$	33,637		$	12,563

2006	Regulated												Nonregulated

Functional Class of Property	Property, Plant and Equipment			Accumulated Depreciation				Annual Composite Depreciation Rate			Depreciable Life Ranges		Property, Plant and Equipment			Accumulated Depreciation				Annual Composite Depreciation Rate		Depreciable Life Ranges
	(in thousands)										(in years)		(in thousands)									(in years)
Production		$	1,320,507		$	697,275			2.6	%		40-121		$	1,524,296		$	604,290		2.6	%	40-121
Transmission			1,620,512			457,129			1.8	%		25-87			-			-		N.M.		N.M.
Distribution			2,237,887			562,672			3.3	%		11-52			-			-		N.M.		N.M.
CWIP			500,641			(7,263	)	N.M.			N.M.				456,985			(5,054	)	N.M.		N.M.
Other			305,811			154,829			7.7	%		24-55			33,639			12,412		N.M.		N.M.
Total		$	5,985,358		$	1,864,642								$	2,014,920		$	611,648

2005	Regulated			Nonregulated
Functional Class of Property	Annual Composite Depreciation Rate		Depreciable Life Ranges	Annual Composite Depreciation Rate		Depreciable Life Ranges
			(in years)			(in years)
Production	2.9	%	40-120	2.9	%	40-120
Transmission	2.2	%	35-65	N.M.		N.M.
Distribution	3.2	%	10-60	N.M.		N.M.
Other	9.3	%	N.M.	3.2	%	N.M.

N.M. = Not Meaningful

CSPCo

2007	Regulated										Nonregulated

Functional Class of Property	Property, Plant and Equipment			Accumulated Depreciation				Annual Composite Depreciation Rate		Depreciable Life Ranges	Property, Plant and Equipment		Accumulated Depreciation		Annual Composite Depreciation Rate		Depreciable Life Ranges
	(in thousands)									(in years)	(in thousands)						(in years)
Production		$	-		$	-		N.M.		N.M.	$	2,072,564	$	861,213	3.0	%	40-59
Transmission			510,107			209,369		2.3	%	33-50		-		-	N.M.		N.M.
Distribution			1,552,999			536,408		3.6	%	12-56		-		-	N.M.		N.M.
CWIP			114,130			(5,773	)	N.M.		N.M.		301,197		129	N.M.		N.M.
Other			142,044			75,271		8.6	%	N.M.		56,432		21,176	N.M.		N.M.
Total		$	2,319,280		$	815,275					$	2,430,193	$	882,518

2006	Regulated										Nonregulated

Functional Class of Property	Property, Plant and Equipment			Accumulated Depreciation				Annual Composite Depreciation Rate		Depreciable Life Ranges	Property, Plant and Equipment			Accumulated Depreciation			Annual Composite Depreciation Rate		Depreciable Life Ranges
	(in thousands)									(in years)	(in thousands)								(in years)
Production		$	-		$	-		N.M.		N.M.		$	1,896,073		$	812,541	3.1	%	40-59
Transmission			479,119			202,585		2.3	%	33-50			-			-	N.M.		N.M.
Distribution			1,475,758			514,042		3.5	%	12-56			-			-	N.M.		N.M.
CWIP			77,484			(4,749	)	N.M.		N.M.			216,654			704	N.M.		N.M.
Other			168,911			83,782		8.7	%	N.M.			22,192			2,138	N.M.		N.M.
Total		$	2,201,272		$	795,660						$	2,134,919		$	815,383

2005

Regulated

Nonregulated

Functional

Class of

Property

Annual Composite Depreciation Rate

Depreciable Life Ranges

Annual Composite Depreciation Rate

Depreciable

Life Ranges

(in years)

Production

N.M.

3.1

40-59

Transmission

2.3

33-50

N.M.

Distribution

3.6

12-56

N.M.

Other

10.2

N.M.

N.M. = Not Meaningful

OPCo

2007	Regulated									Nonregulated

Functional Class of Property	Property, Plant and Equipment			Accumulated Depreciation			Annual Composite Depreciation Rate		Depreciable Life Ranges	Property, Plant and Equipment			Accumulated Depreciation		Annual Composite Depreciation Rate		Depreciable Life Ranges
	(in thousands)								(in years)	(in thousands)							(in years)
Production		$	-	$	-		N.M.		N.M.		$	5,641,537	$	2,008,046	2.6	%	35-61
Transmission			1,068,387		439,542		2.3	%	27-70			-		-	N.M.		N.M.
Distribution			1,394,988		374,421		3.9	%	12-55			-		-	N.M.		N.M.
CWIP			73,902		(1,696	)	N.M.		N.M.			642,738		1,806	N.M.		N.M.
Other			188,382		88,522		8.6	%	N.M.			130,423		56,644	N.M.		N.M.
Total		$	2,725,659	$	900,789						$	6,414,698	$	2,066,496

2006	Regulated										Nonregulated

Functional Class of Property	Property, Plant and Equipment			Accumulated Depreciation				Annual Composite Depreciation Rate		Depreciable Life Ranges	Property, Plant and Equipment			Accumulated Depreciation		Annual Composite Depreciation Rate		Depreciable Life Ranges
	(in thousands)									(in years)	(in thousands)							(in years)
Production		$	-		$	-		N.M.		N.M.		$	4,413,340	$	1,925,883	2.8	%	35-61
Transmission			1,030,934			420,748		2.3	%	27-70			-		-	N.M.		N.M.
Distribution			1,322,103			356,629		3.9	%	12-55			-		-	N.M.		N.M.
CWIP			82,615			(1,115	)	N.M.		N.M.			1,257,016		6,666	N.M.		N.M.
Other			238,456			117,946		9.2	%	N.M.			61,181		9,827	N.M.		N.M.
Total		$	2,674,108		$	894,208						$	5,731,537	$	1,942,376

2005	Regulated			Nonregulated
Functional Class of Property	Annual Composite Depreciation Rate		Depreciable Life Ranges	Annual Composite Depreciation Rate		Depreciable Life Ranges
			(in years)			(in years)
Production	N.M.		N.M.	2.8	%	35-61
Transmission	2.3	%	27-70	N.M.		N.M.
Distribution	3.9	%	12-55	N.M.		N.M.
Other	10.7	%	N.M.	3.0	%	N.M.

N.M. = Not Meaningful

SWEPCo

2007	Regulated										Nonregulated

Functional Class of Property	Property, Plant and Equipment			Accumulated Depreciation				Annual Composite Depreciation Rate		Depreciable Life Ranges	Property, Plant and Equipment			Accumulated Depreciation			Annual Composite Depreciation Rate		Depreciable Life Ranges
	(in thousands)									(in years)	(in thousands)								(in years)
Production		$	1,119,022		$	652,802		3.0	%	30-57		$	624,176		$	364,125	3.0	%	30-57
Transmission			737,975			231,406		2.7	%	40-55			-			-	N.M.		N.M.
Distribution			1,312,746			374,084		3.5	%	16-65			-			-	N.M.		N.M.
CWIP			279,717			(5,336	)	N.M.		N.M.			171,511			-	N.M.		N.M.
Other			323,543			135,015		9.4	%	N.M.			308,222			186,948	N.M.		N.M.
Total		$	3,773,003		$	1,387,971						$	1,103,909		$	551,073

2006	Regulated										Nonregulated

Functional Class of Property	Property, Plant and Equipment			Accumulated Depreciation				Annual Composite Depreciation Rate		Depreciable Life Ranges	Property, Plant and Equipment			Accumulated Depreciation				Annual Composite Depreciation Rate		Depreciable Life Ranges
	(in thousands)									(in years)	(in thousands)									(in years)
Production		$	949,867		$	596,453		3.1	%	30-57		$	626,333		$	393,295		3.1	%	30-57
Transmission			668,008			213,618		2.5	%	40-55			-			-		N.M.		N.M.
Distribution			1,228,948			375,659		3.1	%	16-65			-			-		N.M.		N.M.
CWIP			169,700			(5,709	)	N.M.		N.M.			89,962			(403	)	N.M.		N.M.
Other			361,138			119,361		8.6	%	N.M.			234,291			141,871		N.M.		N.M.
Total		$	3,377,661		$	1,299,382						$	950,586		$	534,763

2005	Regulated			Nonregulated
Functional Class of Property	Annual Composite Depreciation Rate		Depreciable Life Ranges	Annual Composite Depreciation Rate		Depreciable Life Ranges
			(in years)			(in years)
Production	3.1	%	30-57	3.1	%	30-57
Transmission	2.5	%	40-55	N.M.		N.M.
Distribution	3.1	%	16-65	N.M.		N.M.
Other	8.6	%	N.M.	N.M.		N.M.

N.M. = Not Meaningful

	I&M										PSO

2007	Regulated										Regulated

Functional Class of Property	Property, Plant and Equipment			Accumulated Depreciation				Annual Composite Depreciation Rate		Depreciable Life Ranges	Property, Plant and Equipment			Accumulated Depreciation			Annual Composite Depreciation Rate		Depreciable Life Ranges
	(in thousands)									(in years)	(in thousands)								(in years)
Production		$	3,529,524		$	2,037,943		2.7	%	59-132		$	1,110,657	$	622,866		2.2	%	9-70
Transmission			1,078,575			394,982		1.7	%	46-75			569,746		158,269		1.9	%	40-75
Distribution			1,196,397			361,200		3.2	%	14-70			1,337,038		263,561		3.0	%	27-65
CWIP			122,296			(13,601	)	N.M.		N.M.			200,018		(8,066	)	N.M.		N.M.
Other			473,860			110,796		11.3	%	N.M.			237,254		145,541		6.8	%	5-35
Total		$	6,400,652		$	2,891,320						$	3,454,713	$	1,182,171

	Nonregulated										Nonregulated
Functional Class of Property	Property, Plant and Equipment			Accumulated Depreciation				Annual Composite Depreciation Rate		Depreciable Life Ranges	Property, Plant and Equipment			Accumulated Depreciation			Annual Composite Depreciation Rate		Depreciable Life Ranges
	(in thousands)									(in years)	(in thousands)								(in years)
Other		$	152,530		$	107,096		N.M.		N.M.		$	4,468	$	-		N.M.		N.M.

2006	Regulated										Regulated

Functional Class of Property	Property, Plant and Equipment			Accumulated Depreciation				Annual Composite Depreciation Rate		Depreciable Life Ranges	Property, Plant and Equipment			Accumulated Depreciation			Annual Composite Depreciation Rate		Depreciable Life Ranges
	(in thousands)									(in years)	(in thousands)								(in years)
Production		$	3,363,813		$	1,948,199		3.6	%	40-119		$	1,091,910	$	638,599		2.7	%	30-57
Transmission			1,047,264			420,256		1.9	%	30-65			503,638		158,115		2.0	%	40-75
Distribution			1,102,033			355,059		4.0	%	12-65			1,215,236		269,306		3.0	%	25-65
CWIP			183,893			(11,627	)	N.M.		N.M.			141,283		(8,252	)	N.M.		N.M.
Other			373,983			94,183		10.2	%	N.M.			229,759		129,339		6.7	%	N.M.
Total		$	6,070,986		$	2,806,070						$	3,181,826	$	1,187,107

	Nonregulated										Nonregulated
Functional Class of Property	Property, Plant and Equipment			Accumulated Depreciation				Annual Composite Depreciation Rate		Depreciable Life Ranges	Property, Plant and Equipment			Accumulated Depreciation			Annual Composite Depreciation Rate		Depreciable Life Ranges
	(in thousands)									(in years)	(in thousands)								(in years)
Other		$	155,744		$	108,061		N.M.		N.M.		$	4,468	$	-		N.M.		N.M.

N.M. = Not Meaningful

	I&M			PSO

2005	Regulated			Regulated
Functional Class of Property	Annual Composite Depreciation Rate		Depreciable Life Ranges	Annual Composite Depreciation Rate		Depreciable Life Ranges
			(in years)			(in years)
Production	3.8	%	40-119	2.7	%	30-57
Transmission	1.9	%	30-65	2.1	%	40-75
Distribution	4.1	%	12-65	3.1	%	25-65
Other	11.7	%	N.M.	7.4	%	N.M.

Nonregulated

Functional

Class of

Property

Annual Composite Depreciation Rate

Depreciable Life Ranges

Annual Composite Depreciation Rate

Depreciable

Life Ranges

(in years)

Other

3.4

N.M.

N.M. = Not Meaningful

The Registrant Subsidiaries provide 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. The Registrant Subsidiaries use 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. The Registrant Subsidiaries include these costs in the cost of coal charged to fuel expense. The average amortization rate for coal rights and mine development costs related to SWEPCo was $0.66 per ton in 2007, 2006 and 2005.

For cost-based 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 (see “Asset Retirement Obligations (ARO)” section of this note).

Asset Retirement Obligations (ARO)

The Registrant Subsidiaries implemented SFAS 143 effective January 1, 2003. SFAS 143 requires entities to record a liability at fair value for any legal obligations for future asset retirements when the related assets are acquired or constructed. Upon establishment of a legal liability, SFAS 143 requires a corresponding ARO asset to be established, which will be depreciated over its useful life. Upon settlement of an ARO, the Registrant Subsidiaries recognize any difference between the ARO liability and actual costs as income or expense.

The Registrant Subsidiaries adopted FIN 47 during the fourth quarter of 2005. FIN 47 interprets the application of SFAS 143. It clarifies that conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Entities are required to record a liability for the fair value of a conditional ARO if the fair value of the liability can be reasonably estimated. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO.

The Registrant Subsidiaries completed a review of their FIN 47 conditional ARO and concluded that legal liabilities exist for asbestos removal and disposal in general buildings and generating plants. In 2005, the Registrant Subsidiaries recorded conditional ARO in accordance with FIN 47. The cumulative effect of certain retirement costs for asbestos removal related to regulated operations was generally charged to a regulatory liability. The Registrant Subsidiaries with nonregulated generation operations recorded an unfavorable cumulative effect related to asbestos removal for those operations. This adjustment is reflected in Cumulative Effect of Accounting Change, Net of Tax on certain Registrant Subsidiaries’ 2005 statements of income.

The following table shows the liability for conditional ARO and cumulative effect recorded in 2005 for FIN 47 by Registrant Subsidiary:

	Liability		Cumulative Effect
	Recorded		Pretax			Net of Tax
Company	(in thousands)
APCo	$	8,972	$	(3,470	)	$	(2,256	)
CSPCo		1,981		(1,292	)		(839	)
I&M		5,801		-			-
OPCo		9,513		(7,039	)		(4,575	)
PSO		6,056		-			-
SWEPCo		6,702		(1,926	)		(1,252	)

As of December 31, 2007 and 2006, I&M’s ARO liability was $846 million and $803 million for nuclear decommissioning of the Cook Plant. These liabilities are reflected in Asset Retirement Obligations on I&M’s Consolidated Balance Sheets. As of December 31, 2007 and 2006, the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.1 billion and $974 million, respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s Consolidated Balance Sheets.

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.

The following is a reconciliation of the 2007 and 2006 aggregate carrying amounts of ARO by Registrant Subsidiary:

	ARO at December 31, 2006		Accretion Expense		Liabilities Incurred		Liabilities Settled			Revisions in Cash Flow Estimates		ARO at December 31, 2007
Company	(in thousands)
APCo (a)(d)	$	37,506	$	2,744	$	-	$	(2,518	)	$	2,287	$	40,019
CSPCo (a)(d)		19,603		1,321		-		(2,034	)		2,768		21,658
I&M (a)(b)(d)		809,853		43,254		-		(482	)		21		852,646
OPCo (a)(d)		71,319		5,385		-		(2,542	)		3,192		77,354
PSO (d)		6,437		398		-		(327	)		13		6,521
SWEPCo (a)(c)(d)(e)		48,018		2,961		3,582		(4,579	)		280		50,262

	ARO at December 31, 2005		Accretion Expense		Liabilities Incurred		Liabilities Settled			Revisions in Cash Flow Estimates		ARO at December 31, 2006
Company	(in thousands)
APCo (a)(d)	$	35,496	$	2,620	$	307	$	(1,422	)	$	505	$	37,506
CSPCo (a)(d)		17,844		1,310		304		(891	)		1,036		19,603
I&M (a)(b)(d)		737,959		48,806		-		(507	)		23,595		809,853
OPCo (a)(d)		65,557		4,949		-		(2,295	)		3,108		71,319
PSO (d)		6,056		382		-		(188	)		187		6,437
SWEPCo (a)(c)(d)(e)		43,077		2,437		8,362		(6,581	)		723		48,018

(a)	Includes ARO related to ash ponds.
(b)	Includes ARO related to nuclear decommissioning costs for the Cook Plant ($846 million and $803 million at December 31, 2007 and 2006, respectively).
(c)	Includes ARO related to Sabine Mining Company and Dolet Hills Lignite Company, LLC.
(d)	Includes ARO related to asbestos removal.
(e)	The current portion of SWEPCo’s ARO, totaling $434 thousand and $935 thousand, at December 31, 2007 and 2006, respectively, is included in Other in the Current Liabilities section of SWEPCo’s Consolidated Balance Sheets.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

The amounts of AFUDC included in Allowance For Equity Funds Used During Construction on the Registrant Subsidiaries’ Consolidated Statements of Income for 2007, 2006 and 2005 were as follows:

	Years Ended December 31,
	2007		2006		2005
Company	(in millions)
APCo	$	7.3	$	12.0	$	8.0
CSPCo		3.0		1.9		1.6
I&M		4.5		7.9		4.5
OPCo		2.3		2.6		1.4
PSO		1.4		0.7		0.9
SWEPCo		10.2		1.3		2.4

The amounts of allowance for borrowed funds used during construction or interest capitalized included in Interest Expense on the Registrant Subsidiaries’ Consolidated Statements of Income for 2007, 2006 and 2005 were as follows:

	Years Ended December 31,
	2007		2006		2005
Company	(in millions)
APCo	$	6.9	$	17.7	$	8.7
CSPCo		7.3		6.0		1.5
I&M		5.3		7.5		4.3
OPCo		36.6		42.7		16.4
PSO		5.2		1.5		0.6
SWEPCo		9.8		2.2		1.2

Jointly-owned Electric Utility Plant

CSPCo, PSO and SWEPCo have generating units that are jointly-owned with affiliated and nonaffiliated companies. Each of the participating companies 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 operations and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows:

					Company’s Share at December 31, 2007
	Fuel Type	Percent of Ownership			Utility Plant in Service		Construction Work in Progress (h)		Accumulated Depreciation
Company					(in thousands)
CSPCo
W.C. Beckjord Generating Station (Unit No. 6) (a)	Coal		12.5	%	$	15,926	$	943	$	7,792
Conesville Generating Station (Unit No. 4) (b)	Coal		43.5			84,472		83,734		50,206
J.M. Stuart Generating Station (c)	Coal		26.0			295,664		156,948		134,394
Wm. H. Zimmer Generating Station (a)	Coal		25.4			763,038		1,046		324,120
Transmission	N/A	(d)				62,725		5,958		43,973
Total					$	1,221,825	$	248,629	$	560,485

PSO
Oklaunion Generating Station (Unit No. 1) (e)	Coal		15.6	%	$	87,145	$	332	$	56,705

SWEPCo
Dolet Hills Generating Station (Unit No. 1) (f)	Lignite		40.2	%	$	240,926	$	11,437	$	174,795
Flint Creek Generating Station (Unit No. 1) (g)	Coal		50.0			97,909		2,553		59,970
Pirkey Generating Station (Unit No. 1) (g)	Lignite		85.9			486,464		4,078		325,054
Total					$	825,299	$	18,068	$	559,819

					Company’s Share at December 31, 2006
	Fuel Type	Percent of Ownership			Utility Plant in Service		Construction Work in Progress (h)		Accumulated Depreciation
Company					(in thousands)
CSPCo
W.C. Beckjord Generating Station (Unit No. 6) (a)	Coal		12.5	%	$	15,702	$	280	$	7,560
Conesville Generating Station (Unit No. 4) (b)	Coal		43.5			85,253		31,691		49,150
J.M. Stuart Generating Station (c)	Coal		26.0			284,142		101,769		127,591
Wm. H. Zimmer Generating Station (a)	Coal		25.4			751,148		4,797		302,053
Transmission	N/A	(d)				62,876		86		42,433
Total					$	1,199,121	$	138,623	$	528,787

PSO
Oklaunion Generating Station (Unit No. 1) (e)	Coal		15.6	%	$	86,676	$	543	$	55,951

SWEPCo
Dolet Hills Generating Station (Unit No. 1) (f)	Lignite		40.2	%	$	240,471	$	5,248	$	166,938
Flint Creek Generating Station (Unit No. 1) (g)	Coal		50.0			96,799		1,637		57,303
Pirkey Generating Station (Unit No. 1) (g)	Lignite		85.9			481,093		4,847		310,271
Total					$	818,363	$	11,732	$	534,512

(a)	Operated by Duke Energy Corporation, a nonaffiliated company.
(b)	Operated by CSPCo.
(c)	Operated by The Dayton Power & Light Company, a nonaffiliated company.
(d)	Varying percentages of ownership.
(e)	Operated by PSO.
(f)	Operated by Cleco Corporation, a nonaffiliated company.
(g)	Operated by SWEPCo.
(h)	Primarily relates to environmental upgrades, including the installation of flue gas desulfurization projects at Conesville Generating Station and J.M. Stuart Generating Station.

N/A	= Not Applicable

18.	UNAUDITED QUARTERLY FINANCIAL INFORMATION

The unaudited quarterly financial information for each Registrant Subsidiary is provided below. 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.

Quarterly Periods Ended:	APCo			CSPCo		I&M		OPCo		PSO				SWEPCo
	(in thousands)
March 31, 2007
Operating Revenues	$	665,728		$	447,912	$	492,869	$	679,441	$	315,313			$	344,099
Operating Income (Loss)		137,174			82,596		63,835		140,532		(25,187	)	(b)		26,462
Net Income (Loss)		70,227			46,981		29,463		79,261		(20,426	)	(b)		9,605

June 30, 2007
Operating Revenues	$	557,410		$	506,022	$	486,037	$	670,933	$	321,639			$	346,022
Operating Income		33,844			134,576		64,122		140,294		21,478				14,940
Income Before Extraordinary Loss		3,281			80,022		30,035		74,340		6,295				1,624
Extraordinary Loss – Reapplication of Regulatory Accounting for Generation, Net of Tax (a)		(78,763	)		-		-		-		-				-
Net Income (Loss)		(75,482	)		80,022		30,035		74,340		6,295				1,624

September 30, 2007
Operating Revenues	$	706,576		$	607,141	$	559,176	$	757,743	$	448,036			$	448,510
Operating Income		67,833			149,730		89,156		146,689		70,670				76,617
Net Income		24,058			85,454		49,124		75,262		36,571				44,120

December 31, 2007
Operating Revenues	$	677,555		$	482,237	$	505,110	$	706,095	$	310,562			$	344,831
Operating Income		81,975			80,459		60,053		98,837		(71,796	)	(b)		16,683
Net Income		35,933			45,631		28,273		39,701		(46,564	)	(b)		10,915

(a)	See “Extraordinary Items” section of Note 2 and “Virginia Restructuring” section of Note 3 for discussions of the extraordinary loss booked in the second quarter of 2007.
(b)	See “Oklahoma 2007 Ice Storms” section of Note 4 for discussion of expenses incurred from ice storms in January and December 2007.

Quarterly Periods Ended:	APCo		CSPCo		I&M		OPCo		PSO			SWEPCo
	(in thousands)
March 31, 2006
Operating Revenues	$	634,441	$	428,768	$	515,779	$	702,606	$	354,729		$	305,132
Operating Income (Loss)		138,473		92,497		103,438		157,063		(1,163	)		38,960
Net Income (Loss)		73,594		51,337		57,878		95,032		(5,357	)		17,872

June 30, 2006
Operating Revenues	$	514,588	$	417,109	$	469,454	$	616,007	$	347,046		$	359,484
Operating Income		30,601		61,331		57,461		53,069		30,024			54,932
Net Income		9,647		32,262		28,525		23,399		14,638			28,312

September 30, 2006
Operating Revenues	$	648,601	$	539,898	$	525,535	$	764,908	$	458,441		$	456,700
Operating Income		89,716		140,636		66,401		145,100		77,577			91,273
Net Income		30,536		84,021		34,561		83,342		42,023			49,706

December 31, 2006
Operating Revenues	$	596,398	$	420,960	$	466,179	$	641,354	$	281,568		$	310,523
Operating Income (Loss)		106,853		43,186		24,891		70,059		(15,445	)		4,453
Net Income (Loss)		67,672		17,959		204		26,870		(14,444	)		(4,167	)

For each of the Registrant Subsidiaries, there were no significant, nonrecurring events in the fourth quarter of 2007 or 2006.

COMBINED MANAGEMENT’S 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 results of operations and is meant to be read with (i) Management’s Financial Discussion and Analysis, (ii) financial statements, (iii) footnotes and (iv) the schedules of each individual registrant.

Source of Funding

Short-term funding for the Registrant Subsidiaries comes from AEP’s commercial paper program and revolving credit facilities. Proceeds are loaned to the Registrant Subsidiaries through intercompany notes. AEP and its Registrant Subsidiaries also operate a money pool to minimize the AEP System’s external short-term funding requirements and sell accounts receivable to provide liquidity for certain electric subsidiaries. The Registrant Subsidiaries generally use short-term funding sources (the money pool or receivables sales) to provide for interim financing of capital expenditures that exceed internally generated funds and periodically reduce their outstanding short-term debt through issuances of long-term debt, sale-leaseback, leasing arrangements and additional capital contributions from AEP.

Credit Markets

Management believes the Registrant Subsidiaries have adequate liquidity under AEP’s credit facilities and the ability to issue long-term debt in the current credit markets. As of December 31, 2007, the Registrant Subsidiaries had tax-exempt long-term debt (Pollution Control Bonds) sold at auction rates that are reset every 7, 28 or 35 days and are insured by bond insurers previously AAA-rated, namely Ambac Assurance Corporation, Financial Guaranty Insurance Co., MBIA Insurance Corporation and XL Capital Assurance Inc. As of December 31, 2007, the amount outstanding by Registrant Subsidiary are as follows:

	Amount
	Outstanding
	(in millions)
APCo	$	213
CSPCo		193
I&M		262
OPCo		468
PSO		34
SWEPCo		176

Dividend Restrictions

Under the Federal Power Act, the Registrant Subsidiaries are restricted from paying dividends out of stated capital.

Sale of Receivables Through AEP Credit

In October 2007, AEP renewed AEP Credit’s sale of receivables agreement. The sale of receivables agreement provides a commitment of $650 million from banks and commercial paper conduits to purchase receivables from AEP Credit. Under the agreement, the commitment will increase to $700 million for the months of August and September to accommodate seasonal demand. This agreement will expire in October 2008. Management intends to extend or replace the sale of receivables agreement. At December 31, 2007, $507 million of commitments to purchase accounts receivable were outstanding under the receivables agreement. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivable less an allowance for anticipated uncollectible accounts.

AEP Credit purchases accounts receivable through purchase agreements with certain Registrant Subsidiaries. These subsidiaries include CSPCo, 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 jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit.

Budgeted Construction Expenditures

Construction expenditures for the Registrant Subsidiaries for 2008 through 2010 are:

	Estimated Construction Expenditures
	2008		2009		2010		Total
Company	(in millions)
APCo	$	726.1	$	753.2	$	628.6	$	2,107.9
CSPCo		404.2		351.0		329.8		1,085.0
I&M		385.7		440.2		380.3		1,206.2
OPCo		634.7		591.1		549.9		1,775.7
PSO		276.5		363.3		463.3		1,103.1
SWEPCo		741.0		620.0		637.6		1,998.6

Significant Factors

Ohio Restructuring

As permitted by the current Ohio restructuring legislation, CSPCo and OPCo can implement market-based rates effective January 2009, following the expiration of their RSPs on December 31, 2008. The RSP plans include generation rates which are between cost and higher market rates. In August 2007, legislation was introduced that would significantly reduce the likelihood of CSPCo’s and OPCo’s ability to charge market-based rates for generation at the expiration of their RSPs. The Ohio Senate passed legislation and it is being considered by the Ohio House of Representatives. Management continues to analyze the proposed legislation and is working with various stakeholders to achieve a principled, fair and well-considered approach to electric supply pricing. At this time, management is unable to predict whether CSPCo and OPCo will transition to market pricing, extend their RSP rates, with or without modification, or become subject to a legislative reinstatement of some form of cost-based regulation for their generation supply business on January 1, 2009. The return to cost-based regulation could cause the generation business of CSPCo and OPCo, in whole or in part, to meet the criteria for application of SFAS 71. If CSPCo and OPCo are required to reestablish certain net regulatory liabilities applicable to their generation business, it could result in an extraordinary item and a decrease in future results of operations and financial condition.

Oklahoma 2007 Ice Storms

PJM Marginal Loss Pricing

These incremental PJM billings for the period June through December 2007 are as follows:

PJM Billings For Marginal-Loss Pricing

(in millions)

	PJM Billings
APCo	$	34
I&M		19
OPCo		23
CSPCo		19

Management believes these additional costs should be recoverable through retail and/or cost-based wholesale rates and is deferring these incremental costs as regulatory assets where recovery is currently probable (Ohio, Virginia and West Virginia). We are also seeking recovery in Indiana and plan to seek recovery in Michigan.

AEP currently is deferring and/or collecting approximately 75% of these incremental PJM billings.

New Generation

AEP is in various stages of construction of the following generation facilities. Certain plants are pending regulatory approval:

Commercial

Total

Operation

Operating

Project

Projected

Date

Company

Name

Location

Cost (a)

CWIP (b)

Fuel Type

Plant Type

Capacity

(Projected)

(in millions)

SWEPCo

Mattison

Arkansas

131

(c)

Gas

Simple-cycle

340

(c)

2007

PSO

Southwestern

Oklahoma

(d)

Gas

Simple-cycle

170

2008

PSO

Riverside

Oklahoma

(d)

Gas

Simple-cycle

170

2008

AEGCo

Dresden

(e)

Ohio

266

(e)

Gas

Combined-cycle

580

2010

SWEPCo

Stall

Louisiana

378

Gas

Combined-cycle

480

2010

SWEPCo

Turk

(f)

Arkansas

1,300

(f)

272

Coal

Ultra-supercritical

600

(f)

2012

APCo

Mountaineer

West Virginia

2,230

Coal

IGCC

629

2012

CSPCo/OPCo

Great Bend

Ohio

2,700

(g)

Coal

IGCC

629

2017

(a)	Amount excludes AFUDC.
(b)	Amount includes AFUDC.
(c)	Includes Units 3 and 4, 170 MW, declared in commercial operation on July 12, 2007 and Units 1 and 2, 170 MW, declared in commercial operations on December 28, 2007.
(d)	In April 2007, the OCC authorized PSO to recover through a rider, subject to a $135 million cost cap, all of the traditional costs associated with plant in service at the time these units are placed in service.
(e)	In September 2007, AEGCo purchased the partially completed Dresden plant from Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85 million, which is included in the “Total Projected Cost” section above.
(f)	SWEPCo plans to own approximately 73%, or 438 MW, totaling about $950 million in capital investment. See “Turk Plant” section below.
(g)	Front-end engineering and design study is complete. Cost estimates, updated to reflect cost escalations due to revised commercial operation date of 2017, are not yet filed with the PUCO due to the pending appeals to the Supreme Court of Ohio resulting from the PUCO’s April 2006 opinion and order. See “Ohio IGCC Plant” section of Note 4.

AEP acquired the following generation facilities in 2007:

Operating

Purchase

Company

Plant Name

Location

Cost

Fuel Type

Plant Type

Capacity

Date

(in millions)

CSPCo

Darby

(a)

Ohio

102

Gas

Simple-cycle

480

April 2007

AEGCo

Lawrenceburg

(b)

Indiana

325

Gas

Combined-cycle

1,096

May 2007

(a)	CSPCo purchased Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company.
(b)	AEGCo purchased Lawrenceburg Generating Station (Lawrenceburg), adjacent to I&M’s Tanners Creek Plant, from an affiliate of Public Service Enterprise Group (PSEG). AEGCo sells the power to CSPCo under a FERC-approved unit power agreement.

Turk Plant

Red Rock Generating Facility

In October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of additional capacity by the year 2012, but denied PSO and OG&E’s applications for construction preapproval. The OCC stated that PSO failed to fully study other alternatives. Since PSO and OG&E could not obtain preapproval to build the Red Rock Generating Facility, PSO and OG&E cancelled the third party construction contract and their joint venture development contract. PSO believes the Red Rock preconstruction costs, associated contract cancellation fees and applicable carrying costs are probable of recovery and established a regulatory asset for future recovery. In December 2007, PSO made a filing requesting recovery of the $21 million regulatory asset that included associated carrying costs to date, and requested to recover future carrying costs at the weighted average cost of capital ordered in PSO’s last rate case. In the filing, PSO proposed to amortize the asset commensurate with gains from the sale of excess SO2 allowances until recovered. If a settlement agreement signed in February 2008 is approved, see the “Oklahoma 2007 Ice Storms” above, PSO will have to amend its Red Rock filing since the gains from the sale of excess SO2 allowances originally expected to offset Red Rock costs are instead expected to be fully used to offset ice storm costs in accordance with the settlement. PSO continues to believe that the prudently incurred Red Rock pre-construction and cancellation costs will be recovered. If recovery becomes no longer probable or is denied, future results of operations and cash flows would be adversely affected by the reversal of the regulatory asset. As a result of the OCC’s decision, PSO will restudy various alternative options to meet its capacity and energy needs.

Pension and Postretirement Benefit Plans

AEP maintains qualified, defined benefit pension plans (Qualified Plans), which cover a substantial majority of nonunion and certain union employees, and unfunded, nonqualified supplemental plans to provide benefits in excess of amounts permitted under the provisions of the tax law to be paid to participants in the Qualified Plans (collectively the Pension Plans). Additionally, AEP entered into individual retirement agreements with certain current and retired executives that provide additional retirement benefits as a part of the nonqualified, supplemental plans. AEP also sponsors other postretirement benefit plans to provide medical and life insurance benefits for retired employees (Postretirement Plans). The Pension Plans and Postretirement Plans are collectively the Plans.

The following table shows the net periodic benefit cost and assumed rate of return on Plan assets for AEP’s Pension Plans and Postretirement Plans:

	Years Ended December 31,
	2007				2006				2005
Net Periodic Benefit Cost	(in millions)
Pension Plans		$	50			$	71			$	61
Postretirement Plans			81				96				109
Assumed Rate of Return
Pension Plans			8.50	%			8.50	%			8.75	%
Postretirement Plans			8.00	%			8.00	%			8.37	%

The net periodic cost is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on the Plans’ assets. In developing the expected long-term rate of return assumption for 2008, AEP evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions. AEP also considered historical returns of the investment markets as well as its ten-year average return, for the period ended December 2007, of approximately 7.99%. AEP anticipates that the investment managers employed for the Pension Plans will continue to generate future returns averaging 8.00%.

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. The investment returns for the Postretirement Plans are assumed to be slightly less than those of the Pension Plans as a portion of the returns for the Postretirement Plans is taxable. AEP’s assumptions are summarized in the following table:

		Pension								Other Postretirement Benefit Plans
							Assumed/							Assumed/
		2007			2008		Expected			2007		2008		Expected
		Actual			Target		Long-term			Actual		Target		Long-term
		Asset			Asset		Rate of			Asset		Asset		Rate of
		Allocation			Allocation		Return			Allocation		Allocation		Return

	Equity	57		%	55	%	9.58	%		62	%	66	%	9.05	%
	Real Estate	6		%	5	%	7.38	%		-	%	-	%	-	%
	Debt Securities	36		%	39	%	6.00	%		35	%	33	%	5.83	%
	Cash and Cash Equivalents	1		%	1	%	4.75	%		3	%	1	%	3.65	%
	Total	100		%	100	%				100	%	100	%

			2008 Pension						2008 Other Postretirement Benefit Plans
Overall Expected Return (weighted average)			8.00%						8.00%

AEP regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation. Due to changes in the target allocation from year end 2006 to year end 2007, AEP continues to reallocate investments. AEP believes that 8.00% for the Pension Plans and Postretirement Plans is a reasonable long-term rate of return on the Plans’ assets despite the recent market volatility. The Plans’ assets had an actual gain of 9.21% and 12.78% for the twelve months ended December 31, 2007 and 2006, respectively. AEP 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, 2007, AEP had cumulative gains of approximately $143 million that remain to be recognized in the calculation of the market-related value of assets. These unrecognized net actuarial gains 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 SFAS No. 87, “Employers’ Accounting for Pensions.”

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 similar to those included in the Moody’s Aa bond index was constructed but with a duration matching the benefit plan liability. The composite yield on the hypothetical bond portfolio was used as the discount rate for the plan. The discount rate at December 31, 2007 under this method was 6.00% for the Pension Plans and 6.20% for the Postretirement Plans. Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on the Pension Plans’ assets of 8.00%, a discount rate of 6.00% and various other assumptions, AEP estimates that the pension costs for all pension plans will approximate $33 million, $22 million and $21 million in 2008, 2009 and 2010, respectively. Based on an expected rate of return on the OPEB plans’ assets of 8.00%, a discount rate of 6.20% and various other assumptions, AEP estimates Postretirement Plan costs will approximate $73 million, $70 million and $69 million in 2008, 2009 and 2010, respectively. Future actual cost will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans. The actuarial assumptions used may differ materially from actual results. The effects of a 50 basis point change to selective actuarial assumptions are in “Pension and Other Postretirement Benefits” within the “Critical Accounting Estimates” section of this Combined Management’s Discussion and Analysis of Registrant Subsidiaries.

The value of AEP’s Pension Plans’ assets increased to $4.5 billion at December 31, 2007 from $4.3 billion at December 31, 2006 primarily due to investment returns on the assets. The Qualified Plans paid $277 million in benefits to plan participants during 2007 (nonqualified plans paid $7 million in benefits). The value of AEP’s Postretirement Plans’ assets increased to $1.4 billion at December 31, 2007 from $1.3 billion at December 31, 2006. The Postretirement Plans paid $130 million in benefits to plan participants during 2006.

AEP’s Qualified Plans remained fully funded as of December 31, 2007. AEP’s nonqualified pension plans are unfunded, and are therefore considered underfunded for accounting purposes. For the nonqualified pension plans, the accumulated benefit obligation in excess of plan assets was $77 million and $78 million at December 31, 2007 and 2006, respectively.

Certain pension plans AEP sponsors and maintains contain a cash balance benefit feature. In recent years, cash balance benefit features have become a focus of scrutiny, as government regulators and courts consider how the Employee Retirement Income Security Act of 1974, as amended, the Age Discrimination in Employment Act of 1967, as amended, and other relevant federal employment laws apply to plans with such a cash balance plan feature. AEP believes that its defined benefit pension plans comply with the applicable requirements of such laws.

Investments within AEP’s Pension and Postretirement Plans’ trusts have limited exposure to subprime mortgage markets at December 31, 2007.

Trust assets as of December 31, 2007 include approximately $224 million in real estate and private equity investments in the pension fund that are illiquid and are valued based on appraisal or other methods requiring judgment.

The Pension Protection Act of 2006 did not materially impact AEP’s plans.

Litigation

Environmental Litigation

New Source Review (NSR) Litigation: The Federal EPA, a number of states and certain special interest groups filed complaints alleging that APCo, CSPCo, I&M, and OPCo modified certain units at their coal-fired generating plants in violation of the NSR requirements of the CAA.

In December 2007, the U.S. District Court for the Southern District of Ohio approved the AEP System’s consent decree with the Federal EPA, the DOJ, the states and the special interest groups. Under the consent decree, management agreed to annual SO2 and NOx emission caps for sixteen coal-fired power plants located in Indiana, Kentucky, Ohio, Virginia and West Virginia. In addition to completing the installation of previously announced environmental retrofit projects at many of the plants, management agreed to install selective catalytic reduction (SCR) and flue gas desulfurization (FGD or scrubbers) emissions control equipment on the Rockport Plant units.

Under the consent decree, the Registrant Subsidiaries and KPCo paid a $15 million civil penalty in 2008 and provided $36 million for environmental projects coordinated with the federal government and $24 million to the states for environmental mitigation. See “Federal EPA Complaint and Notice of Violation” section of Note 6. The Registrant Subsidiaries expensed their share of these amounts in 2007 as follows:

			Environmental		Total Expensed in
	Penalty		Mitigation Costs		September 2007
	(in thousands)
APCo	$	4,974	$	20,659	$	25,633
CSPCo		2,883		11,973		14,856
I&M		2,770		11,503		14,273
OPCo		3,355		13,935		17,290

Litigation continues against two plants CSPCo jointly-owns with Duke Energy Ohio, Inc. and Dayton Power and Light Company, which they operate. Management is unable to predict the outcome of these cases. Management believes the Registrant Subsidiaries can recover any capital and operating costs of additional pollution control equipment that may be required through future regulated rates or market prices for electricity. If the Registrant Subsidiaries are unable to recover such costs or if material penalties are imposed for CSPCo’s jointly-owned units, it would adversely affect future results of operations and cash flows.

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 have a material adverse effect on results of operations, cash flows and financial condition.

Environmental Matters

The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements. The sources of these requirements include:

·	Requirements under the CAA to reduce emissions of SO2, NOx, particulate matter (PM) and mercury from fossil fuel-fired power plants; and
·	Requirements under the Clean Water Act (CWA) to reduce the impacts of water intake structures on aquatic species at certain power plants.

In addition, the Registrant Subsidiaries are engaged in litigation with respect to certain environmental matters, 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. Management also monitors possible future requirements to reduce CO2 and other greenhouse gases (GHG) emissions to address concerns about global climate change. All of these matters are discussed below.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality, and control mobile and stationary sources of air emissions. The major CAA programs affecting power plants are briefly described below. The states implement and administer many of these programs and could impose additional or more stringent requirements.

National Ambient Air Quality Standards: The CAA requires the Federal EPA to periodically review the available scientific data for six criteria pollutants and establish a concentration level in the ambient air for those substances that is adequate to protect the public health and welfare with an extra safety margin. These concentration levels are known as national ambient air quality standards (NAAQS).

Each state identifies those areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (nonattainment areas). Each state must develop a state implementation plan (SIP) to bring nonattainment areas into compliance with the NAAQS and maintain good air quality in attainment areas. All SIPs are submitted to the Federal EPA for approval. If a state fails to develop adequate plans, the Federal EPA develops and implements a plan. In addition, as the Federal EPA reviews the NAAQS, the attainment status of areas can change, and states may be required to develop new SIPs. The Federal EPA adopted a new PM NAAQS in 2006, proposed a new ozone NAAQS in 2007 and is conducting periodic reviews for additional criteria pollutants.

In 1997, the Federal EPA established new PM and ozone NAAQS. In 2005, the Federal EPA issued a final rule, the Clean Air Interstate Rule (CAIR), that required further reductions in SO2 and NOx emissions and assists states developing new SIPs to meet the 1997 NAAQS. CAIR reduces regional emissions of SO2 and NOx (which can be transformed into PM and ozone) from power plants in the Eastern U.S. (29 states and the District of Columbia). CAIR requires power plants within these states to reduce emissions of SO2 by 50 percent by 2010, and by 65 percent by 2015. NOx emissions will be subject to additional limits beginning in 2009, and will be reduced by a total of 70 percent from current levels by 2015. Reductions of both SO2 and NOx would be achieved through a cap-and-trade program. The rule has been challenged in the courts, but no decision has been issued. States were required to develop and submit SIPs to implement CAIR by November 2006. Nearly all of the states in which the Registrant Subsidiaries’ power plants are located will be covered by CAIR and have or are developing CAIR SIPs. Oklahoma is not affected, while Texas and Arkansas will be covered only by certain parts of CAIR. A SIP that complies with CAIR will also establish compliance with other CAA requirements, including certain visibility goals. The Federal EPA or the states may elect to seek further reductions of SO2 and NOx in the future in response to more stringent PM and ozone NAAQS.

Hazardous Air Pollutants: As a result of the 1990 Amendments to the CAA, the Federal EPA investigated hazardous air pollutant (HAP) emissions from the electric utility sector and submitted a report to Congress, identifying mercury emissions from coal-fired power plants as warranting further study. In 2005, the Federal EPA issued a Clean Air Mercury Rule (CAMR) setting mercury standards for new coal-fired power plants and requiring all states to issue new SIPs including mercury requirements for existing coal-fired power plants. The Federal EPA issued a model federal rule based on a cap-and-trade program for mercury emissions from existing coal-fired power plants that would reduce mercury emissions to 38 tons per year from all existing plants in 2010, and to 15 tons per year in 2018. The national cap of 38 tons per year in 2010 is intended to reflect the level of reduction in mercury emissions that will be achieved as a result of installing controls to reduce SO2 and NOx emissions in order to comply with CAIR. States were required to develop and submit their SIPs to implement CAMR by November 2006.

Various states and special interest groups challenged the rule in the D.C. Circuit Court of Appeals. The Court ruled that the Federal EPA’s action delisting fossil fuel-fired power plants did not conform to the procedures specified in the CAA, and vacated and remanded the federal rules for both new and existing coal-fired power plants to the Federal EPA. Management is unable to predict how the Federal EPA will respond to the remand.

The Acid Rain Program: The 1990 Amendments to the CAA include a cap-and-trade emission reduction program for SO2 emissions from power plants. By 2000, the program established a nationwide cap on power plant SO2 emissions of 8.9 million tons per year. The 1990 Amendments also contained requirements for power plants to reduce NOx emissions through the use of available combustion controls.

The success of the SO2 cap-and-trade program encouraged the Federal EPA and the states to use it as a model for other emission reduction programs, including CAIR and CAMR. The Registrant Subsidiaries continue to meet their obligations under the Acid Rain Program through the installation of controls, use of alternate fuels and participation in the emissions allowance markets. CAIR uses the SO2 allowances originally allocated through the Acid Rain Program as the basis for its SO2 cap-and-trade system.

Regional Haze: The CAA establishes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing impairment of visibility in these areas (the “Regional Haze” program). In 2005, the Federal EPA issued its Clean Air Visibility Rule (CAVR), detailing how the CAA’s best available retrofit technology (BART) requirements will be applied 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. The final rule contains a demonstration that CAIR will result in more visibility improvements than BART for power plants subject to it. Thus, states are allowed to substitute CAIR requirements in their Regional Haze SIPs for controls that would otherwise be required by BART. For BART-eligible facilities located in states (Oklahoma, Texas and Arkansas of the AEP System) not subject to CAIR requirements for SO2 and NOx, some additional controls will be required. The courts upheld the final rule.

Estimated Air Quality Environmental Investments

The CAIR, CAVR and the consent decree signed to settle the NSR litigation require significant additional investments, some of which are estimable. Management’s estimates are subject to significant uncertainties, and will be affected by any changes in the outcome of several interrelated variables and assumptions, including: the timing of implementation; required levels of reductions; methods for allocation of allowances; and selected compliance alternatives and their costs. In short, management cannot estimate compliance costs with certainty, and the actual costs to comply could differ significantly from the estimates discussed below.

By the end of 2007, APCo, CSPCo and OPCo installed selective catalytic reduction (SCR) technology on a total of 10,575 MW at their power plants to comply with NOx requirements. The Registrant Subsidiaries comply with SO2 requirements by installing scrubbers, using alternate fuels and SO2 allowances. They receive allowances through allocation and purchase at either the annual Federal EPA auction or in the market. Decreasing allowance allocations, their diminishing SO2 allowance banks, increasing allowance costs, CAIR, CAVR and commitments in the consent decree will require installation of additional controls on the Registrant Subsidiaries’ power plants through 2019. The Registrant Subsidiaries plan to install additional scrubbers on over 9,300 MW for SO2 control. From 2008 to 2012, the following table shows the total estimated costs for environmental investment and additional scrubbers and other SO2 equipment by Registrant Subsidiary:

	Total Environmental		Cost of Additional Scrubbers and SO2 Equipment
Company	(in millions)
APCo	$	826	$	404
CSPCo		293		193
I&M		77		-
OPCo		663		236
PSO		381		354
SWEPCo		400		367

These estimates may be revised as a result of the Court’s decision remanding the CAMR. The Registrant Subsidiaries will also incur additional operation and maintenance expenses in future years due to the costs associated with the maintenance of additional controls, disposal of byproducts and purchase of reagents.

Due to CAIR, CAMR and CAVR programs and the NSR settlement discussed above, the Registrant Subsidiaries expect to incur additional costs for pollution control technology retrofits between 2013 and 2020 totaling approximately $3 billion. However, this estimate is highly uncertain due to the variability associated with: (1) the states’ implementation of these regulatory programs, including the potential for SIPs that impose standards more stringent than CAIR or CAMR, and the Court decision remanding the CAMR; (2) the actual performance of the pollution control technologies installed on each unit; (3) changes in costs for new pollution controls; (4) new generating technology developments; and (5) other factors. Associated operational and maintenance expenses will also increase during those years. Management cannot estimate these additional operational and maintenance costs due to the uncertainties described above, but they are expected to be significant.

The Registrant Subsidiaries will seek recovery of expenditures for pollution control technologies, replacement or additional generation and associated operating costs from customers through regulated rates (in regulated jurisdictions). The Registrant Subsidiaries should be able to recover these expenditures through market prices in deregulated jurisdictions. If not, those costs could adversely affect future results of operations, cash flows and possibly financial condition.

Clean Water Act Regulation

In 2004, the Federal EPA issued a final rule requiring all large existing power plants with once-through cooling water systems to meet certain standards to reduce mortality of aquatic organisms pinned against the plant’s cooling water intake screen or entrained in the cooling water. The standards vary based on the water bodies from which the plants draw their cooling water. Management expected additional capital and operating expenses, which the Federal EPA estimated could be $193 million for the Registrant Subsidiaries’ plants. The Registrant Subsidiaries undertook site-specific studies and have been evaluating site-specific compliance or mitigation measures that could significantly change these cost estimates. The following table shows the investment amount per Registrant Subsidiary.

	Estimated Compliance Investments
Company	(in millions)
APCo	$	21
CSPCo		19
I&M		118
OPCo		31

The rule was challenged and in January 2007, the Second Circuit Court of Appeals issued a decision remanding significant portions of the rule to the Federal EPA. In July 2007, the Federal EPA suspended the 2004 rule, except for the requirement that permitting agencies develop best professional judgment (BPJ) controls for existing facility cooling water intake structures that reflect the best technology available for minimizing adverse environmental impact. The result is that the BPJ control standard for cooling water intake structures in effect prior to the 2004 rule is the applicable standard for permitting agencies pending finalization of revised rules by the Federal EPA. Management cannot predict further action of the Federal EPA or what effect it may have on similar requirements adopted by the states. The Registrant Subsidiaries sought further review and filed for relief from the schedules included in their permits.

Potential Regulation of CO2 and GHG Emissions

At the Third Conference of the Parties to the United Nations Framework Convention on Climate Change held in Kyoto, Japan in 1997, more than 160 countries, including the U.S., negotiated a treaty requiring legally-binding reductions in emissions of GHG. The U.S. signed the Kyoto Protocol in 1998, but the treaty was not submitted by President Clinton to the Senate for its consent. During 2004, enough countries ratified the treaty for it to become enforceable against the ratifying countries in February 2005. The first commitment period under the Kyoto Protocol ends in 2012.

Since 2005, several members of Congress have introduced bills seeking regulation of GHG emissions, including emissions from power plants. Congress has passed no legislation. The Registrant Subsidiaries participate in a number of voluntary programs to monitor, mitigate, and reduce greenhouse gas emissions, including the Federal EPA’s Climate Leaders program, the Department of Energy’s GHG reporting program and the Chicago Climate Exchange. Through the end of 2006, the AEP System reduced its emissions by more than 39 million metric tons from levels in 1998-2001 as a result of these voluntary actions.

Management supports a reasonable approach to GHG emission reductions, including a mandate to achieve economy-wide reductions, that recognizes a reliable and affordable electric supply is vital to economic stability. The Registrant Subsidiaries have taken measurable, voluntary actions to reduce and offset GHG emissions. Management believes that global warming is a global issue and that the United States should assume a leadership role in developing a new international approach that will address growing emissions from all nations, including developing countries such as India and China.

Management, along with the International Brotherhood of Electrical Workers (IBEW), proposed that a consistent national policy for reasonable carbon controls should include the following principles:

·	Comprehensiveness
·	Cost-effectiveness
·	Realistic emission reduction objectives
·	Reliable monitoring and verification mechanisms
·	Incentives to develop and deploy GHG reduction technologies
·	Removal of regulatory or economic barriers to GHG emission reductions
·	Recognition for early actions/investments in GHG reduction/mitigation
·	Inclusion of adjustment provisions if largest emitters in developing world do not take action

In July 2007, management, along with several other utilities and labor unions, including the IBEW, announced support for the Low Carbon Economy Act of 2007. This legislation requires GHG reductions beginning in 2012 through an economy-wide cap-and-trade program. It contemplates reducing GHG emissions to their 2006 levels by 2020, and to their 1990 levels by 2030. Allowances to emit GHG would be allocated, auctioned or a combination of each, including a safety valve allowance price of $12 per metric ton, subject to increasing adjustments. The legislation also includes incentives for other nations to adopt measures to limit GHG emissions. Management endorses this legislation because it sets reasonable and achievable reduction targets and includes key elements of the AEP-IBEW principles.

The Bush administration sent representatives to the United Nations Framework Convention on Climate Change, held in Bali during December 2007. The Bali conference launched efforts designed to lead to a global pact on limiting GHG emissions after the Kyoto Protocol expires. Organizers anticipate two years of negotiation and hope to include the United States and developing economies, including China and India, in designing a successful global pact.

Management expects that GHG emissions, including those associated with the operation of fossil-fueled generating plants, will be limited by law or regulation in the future. The manner or timing of any such limitations cannot be predicted at this point. While the Registrant Subsidiaries are exploring a number of alternatives, including the capture and storage of GHG emissions from new and existing power generation facilities, there is currently no demonstrated technology on a commercial scale that controls the emissions of GHG from fossil-fueled generating plants. Carbon capture and storage or other GHG limiting technology, if successfully demonstrated, is likely to have a material impact on the cost of operating fossil-fueled generating plants. The Registrant Subsidiaries will seek recovery of expenditures for potential regulation of GHG emissions from customers through regulated rates and market prices of electricity.

Other Environmental Concerns

Management performs environmental reviews and audits on a regular basis for the purpose of identifying, evaluating and addressing environmental concerns and issues. In addition to the matters discussed above, the Registrant Subsidiaries manage other environmental concerns that are not believed to be material or potentially material at this time. If they become significant or if any new matters arise that could be material, they could have a material adverse effect on results of operations, cash flows and possibly financial condition.

Critical Accounting 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 results of operations 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 disclosure 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’ most 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 and a portion of CSPCo, OPCo and SWEPCo) 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 recognition with the recovery of such expense in regulated revenues. Likewise, they match income with the regulated revenues from their customers in the same accounting period. Regulatory liabilities are also recorded for refunds, or probable refunds, to customers that have not been made.

Assumptions and Approach Used: When regulatory assets are probable of recovery through regulated rates, the Registrant Subsidiaries record them as assets on the balance sheet. Regulatory assets are tested for probability of recovery whenever new events occur, for example, 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, the rate of return earned on invested capital and the 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 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 the results of operations. Refer to Note 5 of the Notes to Financial Statements of Registrant Subsidiaries for further detail related to regulatory assets and liabilities.

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 the Arkansas, Louisiana, Oklahoma and Texas jurisdictions and in accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue.

Incremental unbilled electric utility revenues included in Revenue for the years ended December 31 were as follows:

	Years Ended December 31,
	2007			2006			2005
Company	(in thousands)
APCo	$	(11,059	)	$	711		$	14,024
CSPCo		5,432			4,545			(5,404	)
I&M		12,363			1,166			1,783
OPCo		11,717			(3,312	)		14,689
PSO		7,523			157			494
SWEPCo		2,186			(4,875	)		606

Assumptions and Approach Used: The Registrant Subsidiaries calculate the monthly estimate for unbilled revenues as net generation less the current month’s billed KWH plus the prior month’s unbilled KWH. However, due to the occurrence of problems in meter readings, 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 impact, 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 on the Balance Sheets.

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

APCo, CSPCo, I&M, OPCo, PSO and SWEPCo reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality. Liquidity adjustments are calculated by utilizing future bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time. Credit adjustments are based on estimated defaults by counterparties that are calculated using historical default probabilities for companies with similar credit ratings. APCo, CSPCo, I&M, OPCo, PSO and SWEPCo evaluate the probability of the occurrence of the forecasted transaction within the specified time period as provided for in the original documentation related to hedge accounting.

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 are ultimately settled.

The probability that hedged forecasted transactions will 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 accounting for derivative instruments, see sections labeled Credit Risk and VaR Associated with Risk Management Contracts within “Quantitative and Qualitative Disclosures About Risk Management Activities.”

Long-Lived Assets

Nature of Estimates Required: In accordance with the requirements of SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” 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 or the assets meet the held for sale criteria under SFAS 144. 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 subsidiary records an impairment to the extent that the fair value of the asset is less than its book value. For assets held for sale, an impairment is recognized if the expected net sales price is less than its book value. For regulated assets, 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 as a charge 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, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, the Registrant Subsidiaries estimate fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals. 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 SFAS 144, the fair value of the asset can vary if different estimates and assumptions would have been used in the applied valuation techniques. In cases of impairment as described in Note 8 of the Notes to Financial Statements of Registrant Subsidiaries, 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

Nature of Estimates Required: APCo, CSPCo, I&M, OPCo, PSO and SWEPCo sponsor pension and other retirement and postretirement benefit plans in various forms covering all employees who meet eligibility requirements. These benefits are accounted for under SFAS 87, “Employers’ Accounting For Pensions”, SFAS 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” and SFAS 158. See Note 9 of the Notes to Financial Statements of Registrant Subsidiaries for more information regarding costs and assumptions for employee retirement and postretirement benefits. The measurement of pension and postretirement benefit obligations, costs and liabilities is dependent on a variety of assumptions.

Assumptions and Approach Used: The critical assumptions used in developing the required estimates include the following key factors:

·	Discount rate
·	Rate of compensation increase
·	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:

	Pension Plans						Other Postretirement Benefits Plans
		+0.5%			-0.5%			+0.5%			-0.5%
	(in millions)
Effect on December 31, 2007 Benefit Obligations:
Discount Rate	$	(177	)	$	192		$	(116	)	$	124
Compensation Increase Rate		46			(41	)		3			(3	)
Cash Balance Crediting Rate		16			(15	)		N/A			N/A
Health Care Cost Trend Rate		N/A			N/A			90			(79	)

Effect on 2007 Periodic Cost:
Discount Rate		(15	)		14			(11	)		12
Compensation Increase Rate		9			(9	)		1			(1	)
Cash Balance Crediting Rate		7			(7	)		N/A			N/A
Health Care Cost Trend Rate		N/A			N/A			16			(14	)
Expected Return on Plan Assets		(21	)		21			(6	)		6

N/A = Not Applicable

Adoption of New Accounting Pronouncements

FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold (whether a tax position is more likely than not to be sustained) without which, the benefit of that position is not recognized in the financial statements. It requires a measurement determination for recognized tax positions based on the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 requires that the cumulative effect of applying this interpretation be reported and disclosed as an adjustment to the opening balance of retained earnings for that fiscal year and presented separately. The Registrant Subsidiaries adopted FIN 48 effective January 1, 2007. See “FIN 48 “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 “Definition of Settlement in FASB Interpretation No. 48”” section of Note 2 and see Note 13 – Income Taxes. The impact of this interpretation was an unfavorable (favorable) adjustment to retained earnings as follows:

Company	(in thousands)
APCo	$	2,685
CSPCo		3,022
I&M		(327	)
OPCo		5,380
PSO		386
SWEPCo		1,642

New Accounting Pronouncements

In September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity. The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures. It emphasizes that fair value is market-based with the highest measurement hierarchy level being market prices in active markets. The standard requires fair value measurements be disclosed by hierarchy level, an entity include its own credit standing in the measurement of its liabilities and modifies the transaction price presumption. The standard also nullifies the consensus reached in EITF Issue No. 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3) that prohibited the recognition of trading gains or losses at the inception of a derivative contract, unless the fair value of such derivative is supported by observable market data. In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-1 “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” which amends SFAS 157 to exclude SFAS 13 “Accounting for Leases” and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13. In February 2008, the FASB issued FSP FAS 157-2 “Effective Date of FASB Statement No. 157” which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The provision of SFAS 157 are applied prospectively, except for a) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, b) existing hybrid financial instruments measured initially at fair value using the transaction price, and c) blockage discount factors. Although the statement is applied prospectively upon adoption, in accordance with the provisions of SFAS 157 related to EITF 02-3, the Registrant Subsidiaries recorded an immaterial transition adjustment to beginning retained earnings. The impact of considering AEP’s own credit risk when measuring the fair value of liabilities, including derivatives, had an immaterial impact on fair value measurements upon adoption. The Registrant Subsidiaries partially adopted SFAS 157 effective January 1, 2008. The Registrant Subsidiaries will adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP FAS 157-2.

In April 2007, the FASB issued FSP FIN 39-1. It amends FASB Interpretation No. 39 “Offsetting of Amounts Related to Certain Contracts” by replacing the interpretation’s definition of contracts with the definition of derivative instruments per SFAS 133. It also requires entities that offset fair values of derivatives with the same party under a netting agreement to net the fair values (or approximate fair values) of related cash collateral. The entities must disclose whether or not they offset fair values of derivatives and related cash collateral and amounts recognized for cash collateral payables and receivables at the end of each reporting period. This standard changed the method of netting certain balance sheet amounts and reduced assets and liabilities by an immaterial amount. It requires retrospective application as a change in accounting principle for all periods presented. The Registrant Subsidiaries adopted FSP FIN 39-1 effective January 1, 2008.

In June 2007, the FASB ratified EITF 06-11, a consensus on the treatment of income tax benefits of dividends on employee share-based compensation. The issue is how a company should recognize the income tax benefit received on dividends that are paid to employees holding equity-classified nonvested shares, equity-classified nonvested share units or equity-classified outstanding share options and charged to retained earnings under SFAS 123R, “Share-Based Payments.” Under EITF 06-11, a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and are paid to employees for equity-classified nonvested equity shares, nonvested equity share units and outstanding equity share options should be recognized as an increase to additional paid-in capital. EITF 06-11 was applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards when declared. The adoption of this standard had an immaterial impact on the financial statements. The Registrant Subsidiaries adopted EITF 06-11 effective January 1, 2008.

In December 2007, the FASB issued SFAS 160, modifying reporting for noncontrolling interest (minority interest) in consolidated financial statements. It requires noncontrolling interest be reported in equity and establishes a new framework for recognizing net income or loss and comprehensive income by the controlling interest. Upon deconsolidation due to loss of control over a subsidiary, the standard requires a fair value remeasurement of any remaining noncontrolling equity investment to be used to properly recognize the gain or loss. SFAS 160 requires specific disclosures regarding changes in equity interest of both the controlling and noncontrolling parties and presentation of the noncontrolling equity balance and income or loss for all periods presented. SFAS 160 is effective for interim and annual periods in fiscal years beginning after December 15, 2008. The statement is applied prospectively upon adoption. Early adoption is prohibited. Upon adoption, prior period financial statements will be restated for the presentation of the noncontrolling interest for comparability. Although management has not completed their analysis, management expects that the adoption of this standard will have an immaterial impact on the financial statements. The Registrant Subsidiaries will adopt SFAS 160 effective January 1, 2009.


Glossary of Terms

Forward-Looking Information

AEP Common Stock and Dividend Information

American Electric Power Company, Inc. and Subsidiary Companies:
	Selected Consolidated Financial Data
	Management’s Financial Discussion and Analysis of Results of Operations
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Report of Independent Registered Public Accounting Firm
	Management’s Report on Internal Control Over Financial Reporting
	Consolidated Financial Statements
	Index to Notes to Consolidated Financial Statements

Appalachian Power Company and Subsidiaries:
	Selected Consolidated Financial Data
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
	Management’s Report on Internal Control Over Financial Reporting

Columbus Southern Power Company and Subsidiaries:
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
	Management’s Report on Internal Control Over Financial Reporting

Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
	Management’s Report on Internal Control Over Financial Reporting

Ohio Power Company Consolidated:
	Selected Consolidated Financial Data
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
	Management’s Report on Internal Control Over Financial Reporting


Public Service Company of Oklahoma:
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
	Management’s Report on Internal Control Over Financial Reporting

Southwestern Electric Power Company Consolidated:
	Selected Consolidated Financial Data
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
	Management’s Report on Internal Control Over Financial Reporting

Notes to Financial Statements of Registrant Subsidiaries

Combined Management’s Discussion and Analysis of Registrant Subsidiaries

AEGCo		AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent		American Electric Power Company, Inc.
AEP Consolidated		AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit		AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated domestic electric utility companies.
AEP East companies		APCo, CSPCo, I&M, KPCo and OPCo.
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.
AEPSC		American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AEP System or the System		American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP Power Pool		Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEP West companies		PSO, SWEPCo, TCC and TNC.
AFUDC		Allowance for Funds Used During Construction.
ALJ		Administrative Law Judge.
AOCI		Accumulated Other Comprehensive Income.
APCo		Appalachian Power Company, an AEP electric utility subsidiary.
APSC		Arkansas Public Service Commission.
ARO		Asset Retirement Obligations.
CAA		Clean Air Act.
CO2		Carbon Dioxide.
Cook Plant		Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo		Columbus Southern Power Company, an AEP electric utility subsidiary.
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, by and among PSO, SWEPCo, TCC and TNC governing generating capacity allocation. This agreement was amended in May 2006 to remove TCC and TNC. AEPSC acts as the agent.
CTC		Competition Transition Charge.
CWIP		Construction Work in Progress.
DETM		Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DOE		United States Department of Energy.
DOJ		United States Department of Justice.
E&R		Environmental compliance and transmission and distribution system reliability.
EaR		Earnings at Risk, a method to quantify risk exposure.
EITF		Financial Accounting Standards Board’s Emerging Issues Task Force.
ERCOT		Electric Reliability Council of Texas.
ETA		Electric Transmission America, LLC a 50% equity interest joint venture with MidAmerican Energy Holdings Company formed to own and operate electric transmission facilities in North America outside of ERCOT.

ETT		Electric Transmission Texas, LLC, a 50% equity interest joint venture with MidAmerican Energy Holdings Company formed to own and operate electric transmission facilities in ERCOT.
FASB		Financial Accounting Standards Board.
Federal EPA		United States Environmental Protection Agency.
FERC		Federal Energy Regulatory Commission.
FIN		FASB Interpretation No.
FIN 46		FASB Interpretation No. 46, “Consolidation of Variable Interest Entities.”
FIN 47		FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.”
FIN 48		FIN 48, “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 “Definition of Settlement in FASB Interpretation No. 48.”
GAAP		Accounting Principles Generally Accepted in the United States of America.
GHG		Greenhouse gases.
HPL		Houston Pipeline Company, a former AEP subsidiary.
IGCC		Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
IPP		Independent Power Producer.
IRS		Internal Revenue Service.
IURC		Indiana Utility Regulatory Commission.
I&M		Indiana Michigan Power Company, an AEP electric utility subsidiary.
JMG		JMG Funding LP.
KGPCo		Kingsport Power Company, an AEP electric distribution subsidiary.
KPCo		Kentucky Power Company, an AEP electric utility subsidiary.
KPSC		Kentucky Public Service Commission.
kV		Kilovolt.
KWH		Kilowatthour.
LIG		Louisiana Intrastate Gas, a former AEP subsidiary.
LPSC		Louisiana Public Service Commission.
MISO		Midwest Independent Transmission System Operator.
MLR		Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
MPSC		Michigan Public Service Commission.
MTM		Mark-to-Market.
MW		Megawatt.
MWH		Megawatthour.
NOx		Nitrogen oxide.
Nonutility Money Pool		AEP System’s Nonutility Money Pool.
NRC		Nuclear Regulatory Commission.
NSR		New Source Review.
NYMEX		New York Mercantile Exchange.
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.

PATH		Potomac Appalachian Transmission Highline, LLC and its subsidiaries, a joint venture with Allegheny Energy Inc. formed to own and operate electric transmission facilities in PJM.
PJM		Pennsylvania – New Jersey – Maryland regional transmission organization.
PSO		Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO		Public Utilities Commission of Ohio.
PUCT		Public Utility Commission of Texas.
PUHCA		Public Utility Holding Company Act.
Registrant Subsidiaries		AEP subsidiaries which are SEC registrants; APCo, CSPCo, I&M, OPCo, PSO and SWEPCo.
REP		Texas Retail Electric Provider.
Risk Management Contracts		Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant		A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
RSP		Rate Stabilization Plan.
RTO		Regional Transmission Organization.
S&P		Standard and Poor’s.
SCR		Selective Catalytic Reduction.
SEC		United States Securities and Exchange Commission.
SECA		Seams Elimination Cost Allocation.
SFAS		Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.
SFAS 71		Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation.”
SFAS 109		Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes.”
SFAS 133		Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
SFAS 143		Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”
SFAS 157		Statement of Financial Accounting Standards No. 157, “Fair Value Measurements.”
SFAS 158		Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”
SFAS 159		Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.”
SIA		System Integration Agreement.
SNF		Spent Nuclear Fuel.
SO2		Sulfur Dioxide.
SPP		Southwest Power Pool.
Stall Unit		J. Lamar Stall Unit at Arsenal Hill Plant.
STP		South Texas Project Nuclear Generating Plant.
Sweeny		Sweeny Cogeneration Limited Partnership, owner and operator of a four unit, 480 MW gas-fired generation facility, owned 50% by AEP.
SWEPCo		Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC		AEP Texas Central Company, an AEP electric utility subsidiary.
TEM		SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.).
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.
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.
Utility Money Pool		AEP System’s Utility Money Pool.
VaR		Value at Risk, a method to quantify risk exposure.
Virginia SCC		Virginia State Corporation Commission.
WPCo		Wheeling Power Company, an AEP electric distribution subsidiary.
WVPSC		Public Service Commission of West Virginia.

·	Electric load and customer growth.
·	Weather conditions, including storms.
·	Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·	Availability of generating capacity and the performance of our generating plants.
·	Our ability to recover regulatory assets and stranded costs in connection with deregulation.
·	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 (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs through applicable rate cases or competitive rates.
·	New legislation, litigation and government regulation including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances.
·	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 (including disputes arising from the bankruptcy of Enron Corp. and related matters).
·	Our ability to constrain operation and maintenance costs.
·	The economic climate and growth in our service territory and changes in market demand and demographic patterns.
·	Inflationary and interest rate trends.
·	Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to refinance existing debt at attractive rates.
·	Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.
·	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 debt.
·	Volatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities.
·	Changes in utility regulation, including the potential for new legislation in Ohio and the allocation of costs within RTOs.
·	Accounting pronouncements periodically issued by accounting standard-setting bodies.
·	The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans and nuclear decommissioning trust.
·	Prices for power that we generate and sell at wholesale.
·	Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·	Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.

Quarter Ended	High		Low		Quarter-End Closing Price		Dividend
December 31, 2007	$	49.49	$	45.05	$	46.56	$	0.41
September 30, 2007		48.83		42.46		46.08		0.39
June 30, 2007		51.24		43.39		45.04		0.39
March 31, 2007		49.47		41.67		48.75		0.39

December 31, 2006	$	43.13	$	36.49	$	42.58	$	0.39
September 30, 2006		37.30		34.10		36.37		0.37
June 30, 2006		35.19		32.27		34.25		0.37
March 31, 2006		38.48		33.96		34.02		0.37

(a)	Discontinued Operations, Net of Tax for 2003 primarily represents UK Generation Plants.
(b)	Extraordinary Loss, Net of Tax for 2005 reflects TCC’s stranded cost. See Note 2.
(c)	Including portion due within one year.

·	Approximately 38,000 megawatts of generating capacity, one of the largest complements of generation in the U.S., the majority of which provides a significant cost advantage in most of our market areas.
·	Approximately 39,000 miles of transmission lines, including 2,116 miles of 765kV lines, the backbone of the electric interconnection grid in the Eastern U.S.
·	212,781 miles of distribution lines that deliver electricity to 5.2 million customers.
·	Substantial coal transportation assets (more than 8,400 railcars, 2,650 barges, 52 towboats and a coal handling terminal with 20 million tons of annual capacity).

·	Respect our employees’ health, safety and well being and give them the opportunity to be as successful as they can be.
·	Meet the energy needs of our customers in ways that improve their quality of life and protect the environment today and for generations to come.
·	Improve the environmental and safety performance of our generating fleet, and grow that fleet.
·	Set the standards for safety, efficiency and reliability in our electric transmission and distribution systems.
·	Nurture strong and productive relationships with public officials and regulators.
·	Provide leadership, integrity and compassion as a corporate citizen to every community we serve.

·	Continue construction of over 1,800 MW of additional new generation in Ohio, Arkansas, Louisiana and Oklahoma with commercial operation dates ranging from 2008 through 2012.
·	Continue to pursue regulatory approval for our proposed IGCC plants in Ohio and West Virginia and move forward with the engineering and design of these plants.
·	Aggressively seek needed rate increases by developing innovative rate making approaches that obtain favorable resolutions to our numerous rate proceedings.
·	Continue developing strong regulatory relationships through operating company interaction with the various regulatory bodies.
·	Invest in transmission projects such as PATH, ETT, ETA and others to ensure competitive energy prices for electric consumers in and around congested areas.
·	Maintain our strong financial condition and credit ratings.
·	Control our operating and maintenance costs.

·	Intervention in current regulatory proceedings in Indiana, Oklahoma, Louisiana and at the FERC to keep rates down at the expense of a fair return.
·	Legislative activity in Ohio regarding the future regulatory framework.
·	Fuel cost volatility and fuel cost recovery, including related transportation issues.
·	Wholesale market volatility.
·	Plant availability.
·	Weather.

·	Pursuing favorable resolutions of our pending base rate case in Indiana, E&R filings in Virginia and improve inadequate cost recoveries in Oklahoma.
·	Obtaining a successful legislative outcome regarding Ohio’s future regulatory framework.
·	Seeking approval for our new generation projects in Ohio, Oklahoma, West Virginia, Virginia, Arkansas, Texas and Louisiana.
·	Directing legal proceedings regarding appeals related to Texas stranded cost recoveries.
·	Seeking approval to construct transmission projects in ERCOT with appropriate incentives.
·	Managing regulatory proceedings before the FERC seeking:
	·	proper regional and super-regional transmission rates in our eastern transmission zone,
	·	favorable settlement of SECA rates collected subject to refund and
	·	approval to construct transmission projects in PJM with appropriate incentives.

	(in millions)
Generation	$	1,192
Distribution		1,031
Environmental		875
Transmission		564
Corporate		168
Total Construction Expenditures	$	3,830

(a)	The difference between the requested and implemented amounts of annual rate increase is partially offset by approximately $35 million of incremental E&R costs which APCo recorded as a regulatory asset. APCo will file for recovery of these costs through the E&R surcharge mechanism in 2008. APCo also implemented, beginning September 1, 2007, a net $50 million reduction in credits to customers for off-system sales margins as part of its July 2007 fuel clause filing under the new re-regulation legislation.
(b)	Implemented $9 million in July 2007, increased to $10 million in October 2007.
(c)	In January 2008, the PUCO granted additional requested recoveries of increased PJM costs through the TCRR.

	2007		2006		2005
	(in millions of KWH)
Retail:
Residential		49,176		47,222		48,720
Commercial		40,545		38,579		38,605
Industrial		57,566		53,914		53,217
Miscellaneous		2,565		2,653		2,745
Total Retail		149,852		142,368		143,287

Wholesale		42,917		44,564		47,785

Texas Wires – Energy delivered to customers served by TNC and TCC in ERCOT		26,682		26,382		26,525
Total KWHs		219,451		213,314		217,597

·	Generation of electricity for sale to U.S. retail and wholesale customers.
·	Electricity transmission and distribution in the U.S.

(a)	All Other includes:
	·	Parent company’s guarantee revenue received from affiliates, interest income and interest expense and other nonallocated costs.
	·	Tax and interest expense adjustments related to our UK operations and SEEBOARD, which were not eligible for discontinued operations treatment and were sold in 2004 and 2002, respectively.
	·	Our gas pipeline and storage operations, which were sold in 2004 and 2005.
	·	Other energy supply related businesses, including the Plaquemine Cogeneration Facility, which was sold in 2006. See “Plaquemine Cogeneration Facility” section of Note 8.

(a)	Eastern Region and Western Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Eastern Region and Western Region cooling degree days are calculated on a 65 degree temperature base.
(d)	Western Region statistics represent PSO/SWEPCo customer base only.

Year Ended December 31, 2006			$	1,028

Changes in Gross Margin:
Retail Margins	372
Off-system Sales	69
Transmission Revenues	25
Other Revenues	9
Total Change in Gross Margin				475

Changes in Operating Expenses and Other:
Other Operation and Maintenance	(226	)
Gain on Dispositions of Assets, Net	(47	)
Depreciation and Amortization	(48	)
Taxes Other Than Income Taxes	(13	)
Carrying Costs Income	(62	)
Other Income, Net	(13	)
Interest and Other Charges	(120	)
Total Change in Operating Expenses and Other				(529	)

Income Tax Expense				57

Year Ended December 31, 2007			$	1,031

·	Retail Margins increased $372 million primarily due to the following:
	·	A $98 million increase in rates implemented in our Ohio jurisdictions, a $63 million rate increase implemented in our other east jurisdictions of Virginia, West Virginia and Kentucky, a $37 million increase in rates in Texas and a $16 million rate increase in Oklahoma.
	·	A $105 million increase in usage related to weather. Compared to the prior year, our eastern region and western region experienced 22% and 33% increases, respectively, in heating degree days. Also, our eastern region experienced a 37% increase in cooling degree days which was partially offset by an 8% decrease in cooling degree days in our western region.
	·	A $100 million increase related to increased residential and commercial usage and customer growth.
	·	A $96 million increase due to the return of Ormet, an industrial customer in Ohio, effective January 1, 2007. See “Ormet” section of Note 4.
	·	A $49 million increase in sales to municipal, cooperative and other wholesale customers primarily resulting from new power supply contracts.
	These increases were partially offset by:
	·	A $67 million decrease in PJM financial transmission rights revenue, net of congestion, primarily due to fewer transmission constraints within the PJM market.
	·	A $53 million decrease due to PJM’s revision of its pricing methodology for transmission line losses to marginal-loss pricing effective June 1, 2007. See “PJM Marginal-Loss Pricing” section of Note 4.
	·	A $24 million decrease due to increased PJM ancillary costs.
	·	A $17 million decrease due to a 2007 provision related to a SWEPCo Texas fuel reconciliation proceeding. See “SWEPCo Fuel Reconciliation – Texas” section of Note 4.
·	Margins from Off-system Sales increased $69 million primarily due to higher trading margins and favorable fuel recovery adjustments in our western territory, offset by lower east physical off-system sales margins mostly due to lower volumes and PJM’s implementation of marginal-loss pricing effective June 1, 2007.
·	Transmission Revenues increased $25 million primarily due to higher revenue in ERCOT and the east.
·	Other Revenues increased $9 million primarily due to higher securitization revenue at TCC resulting from the $1.7 billion securitization in October 2006 offset by fewer gains on sales of emissions allowances. Securitization revenue represents amounts collected to recover securitization bond principal and interest payments related to TCC’s securitized transition assets and are fully offset by amortization and interest expenses.

·	Other Operation and Maintenance expenses increased $226 million primarily due to a $77 million expense resulting from the NSR settlement and an $81 million increase in storm restoration primarily in Oklahoma. The remaining increase relates to generation expenses from plant outages and base operations.
·	Gain on Disposition of Assets, Net decreased $47 million primarily related to an earnings sharing agreement with Centrica from the sale of our Texas REPs in 2002. In 2006, we received $70 million from Centrica for earnings sharing and in 2007 we received $20 million as the earnings sharing agreement expired.
·	Depreciation and Amortization expense increased $48 million primarily due to increased Ohio regulatory asset amortization related to recovery of IGCC pre-construction costs, increased Texas securitized transition asset amortization and higher depreciable property balances, partially offset by commission-approved lower depreciation rates in Indiana, Michigan and Virginia.
·	Carrying Costs Income decreased $62 million primarily due to TCC’s commencement of stranded cost recovery in October 2006, thus eliminating the accrual of carrying costs income, partially offset by higher carrying costs income related to APCo’s Virginia E&R cost deferrals.
·	Interest and Other Charges increased $120 million primarily due to additional debt issued in 2006 and in 2007 including TCC securitization bonds as well as higher rates on variable rate debt.
·	Income Tax Expense decreased $57 million due to unfavorable federal income tax adjustments in 2006 and favorable state tax return adjustments in 2007.

Year Ended December 31, 2005			$	1,018

Changes in Gross Margin:
Retail Margins	352
Off-system Sales	(18	)
Transmission Revenues	(140	)
Other Revenues	47
Total Change in Gross Margin				241

Changes in Operating Expenses and Other:
Other Operation and Maintenance	(39	)
Asset Impairments and Other Related Charges	39
Gain on Dispositions of Assets, Net	(50	)
Depreciation and Amortization	(120	)
Taxes Other Than Income Taxes	8
Carrying Costs Income	59
Other Income, Net	15
Interest and Other Charges	(75	)
Total Change in Operating Expenses and Other				(163	)

Income Tax Expense				(68	)

Year Ended December 31, 2006			$	1,028

·	Retail Margins increased $352 million primarily due to the following:
	·	A $244 million increase related to new rates implemented in our Ohio jurisdictions as approved by the PUCO in our RSPs, a $67 million increase related to new rates implemented in other east jurisdictions of Kentucky, West Virginia and Virginia and a $13 million increase related to new rates implemented in Oklahoma in June 2005.
	·	A $123 million increase related to increased usage and customer growth of which $63 million relates to the purchase of the Ohio service territory of Monongahela Power in December 2005.
	·	A $70 million increase related to increased sales to municipal, cooperative and other customers primarily as a result of new power supply contracts.
	·	A $55 million increase related to decreased sharing of off-system sales margins with retail customers due to lower off-system sales and changes in the SIA.
	These increases were partially offset by:
	·	A $148 million increase in delivered fuel cost related to the AEP East companies with inactive, capped or frozen fuel clauses.
	·	A $95 million decrease in usage related to mild weather. Compared to the prior year, our eastern region and western region experienced 21% and 15% declines, respectively, in heating degree days. Also compared to the prior year, our eastern region experienced a 20% decrease in cooling degree days.

·	Margins from Off-system Sales decreased $18 million primarily due to lower generation availability in the west due to the sale of STP in May 2005, a reversal of a Texas regulatory provision in 2005 and lower margins from trading activities mostly offset by higher margins in the east.
·	Transmission Revenues decreased $140 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $34 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. See the “SECA Revenue Subject to Refund” section of Note 4.
·	Other Revenues increased $47 million primarily due to the sale of emission allowances and increased securitization revenues.

·	During 2007, we issued approximately $2.6 billion of long-term debt, including approximately $304 million of pollution control revenue bonds at a weighted average interest rate of 4.78% and $2.3 billion of senior notes at a weighted average interest rate of 6%. The proceeds from these issuances were used to fund long-term debt maturities and optional redemptions and construction programs. We also remarketed $110 million of pollution control revenue bonds with new weighted average interest rates of 4.94% under the terms of their original issuance documents.
·	During 2007, we entered into $575 million of interest rate derivatives and settled $597 million of such transactions. The settlements resulted in a net cash expenditure of $6 million. As of December 31, 2007, we had in place interest rate derivatives designated as cash flow hedges with a notional amount of $320 million in order to hedge risk exposure of variable interest rate debt.
·	At December 31, 2007, we had credit facilities totaling $3 billion to support our commercial paper program. As of December 31, 2007, we had $659 million of commercial paper outstanding related to the corporate borrowing program. For the corporate borrowing program, the maximum amount of commercial paper outstanding during the year was $865 million in August 2007 and the weighted average interest rate of commercial paper outstanding during the year was 5.54%.

·	In 2008, we retired the following debt:
	·	In January 2008, TCC retired $74 million of its outstanding Securitization Bonds.
	·	In February 2008, CSPCo retired $52 million of 6.51% Senior Unsecured Notes at maturity.
	·	In February 2008, TCC retired $19 million of 7.125% First Mortgage Bonds at maturity.
·	Our capital investment plans for 2008 will require additional funding from the capital markets.

Other Commercial Commitments	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Standby Letters of Credit (a) (b)	$	65	$	-	$	-	$	-	$	65
Guarantees of the Performance of Outside Parties (b)		-		-		-		65		65
Guarantees of Our Performance (c)		691		1,224		23		75		2,013
Transmission Facilities for Third Parties (d)		12		1		-		-		13
Total Commercial Commitments	$	768	$	1,225	$	23	$	140	$	2,156

(a)	We issue standby letters of credit to third parties. These letters of credit, issued in our ordinary course of business, cover gas and electricity risk management contracts, construction contracts, insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. The maximum future payments of these letters of credit are $65 million with maturities ranging from February 2008 to December 2008. As the parent of all of these subsidiaries, AEP holds all assets of the subsidiaries as collateral. There is no recourse to third parties if these letters of credit are drawn.
(b)	See “Guarantees of Third-party Obligations” section of Note 6.
(c)	We issued performance guarantees and indemnifications for energy trading, International Marine Terminal Pollution Control Bonds and various sale agreements.
(d)	As construction agent for third party owners of transmission facilities, we committed by contract terms to complete construction by dates specified in the contracts. Should we default on these obligations, financial payments could be required including liquidating damages of up to $8 million and other remedies required by contract terms.

	Pension Plans						Other Postretirement Benefits Plans
		+0.5%			-0.5%			+0.5%			-0.5%
	(in millions)
Effect on December 31, 2007 Benefit Obligations
Discount Rate	$	(177	)	$	192		$	(116	)	$	124
Compensation Increase Rate		46			(41	)		3			(3	)
Cash Balance Crediting Rate		16			(15	)		N/A			N/A
Health Care Cost Trend Rate		N/A			N/A			90			(79	)

Effect on 2007 Periodic Cost
Discount Rate		(15	)		14			(11	)		12
Compensation Increase Rate		9			(9	)		1			(1	)
Cash Balance Crediting Rate		7			(7	)		N/A			N/A
Health Care Cost Trend Rate		N/A			N/A			16			(14	)
Expected Return on Plan Assets		(21	)		21			(6	)		6

	Utility Operations			Generation and Marketing			All Other			Sub-Total MTM Risk Management Contracts			PLUS: MTM of Cash Flow and Fair Value Hedges			Total
Current Assets	$	171		$	47		$	61		$	279		$	7		$	286
Noncurrent Assets		184			84			70			338			2			340
Total Assets		355			131			131			617			9			626

Current Liabilities		(116	)		(60	)		(63	)		(239	)		(11	)		(250	)
Noncurrent Liabilities		(83	)		(28	)		(76	)		(187	)		(2	)		(189	)
Total Liabilities		(199	)		(88	)		(139	)		(426	)		(13	)		(439	)

Total MTM Derivative Contract Net Assets (Liabilities)	$	156		$	43		$	(8	)	$	191		$	(4	)	$	187

	Utility Operations			Generation and Marketing			All Other			Total
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2006	$	236		$	2		$	(5	)	$	233
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		(116	)		(1	)		(2	)		(119	)
Fair Value of New Contracts at Inception When Entered During the Period (a)		6			59			-			65
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During The Period		2			-			-			2
Changes in Fair Value due to Market Fluctuations During the Period (b)		8			(17	)		(1	)		(10	)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		20			-			-			20
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2007	$	156		$	43		$	(8	)		191
Net Cash Flow and Fair Value Hedge Contracts											(4	)
Ending Net Risk Management Assets at December 31, 2007										$	187

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)	“Change in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected on the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.

·	The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·	The maturity, by year, of our net assets/liabilities, to give an indication of when these MTM amounts will settle and generate cash.

(a)	Prices Provided by Other External Sources - OTC Broker Quotes reflects information obtained from over-the-counter brokers (OTC), industry services, or multiple-party online platforms.
(b)	Prices Based on Models and Other Valuation Methods is used in the absence of independent information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity is limited, such valuations are classified as modeled. Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available including values determinable by other third party transactions.
(c)	There is mark-to-market value of $22 million in individual periods beyond 2012. $8 million of this mark-to-market value is in 2013, $7 million is in 2014, $3 million is in 2015, $2 million is in 2016 and $2 million is in 2017.

Commodity	Transaction Class	Market/Region	Tenor
			(in Months)
Natural Gas	Futures	NYMEX / Henry Hub	60
	Physical Forwards	Gulf Coast, Texas	24
	Swaps	Northeast, Mid-Continent, Gulf Coast, Texas	24
	Exchange Option Volatility	NYMEX / Henry Hub	12
Power	Futures	AEP East - PJM	36
	Physical Forwards	AEP East - Cinergy	48
	Physical Forwards	AEP - PJM West	48
	Physical Forwards	AEP - Dayton (PJM)	48
	Physical Forwards	AEP - ERCOT	36
	Physical Forwards	AEP - Entergy	24
	Physical Forwards	Power West – PV, NP15, SP15, MidC, Mead	36
	Peak Power Volatility (Options)	AEP East - Cinergy, PJM	12
Emissions	Credits	SO2, NOx	48
Coal	Physical Forwards	PRB, NYMEX, CSX	36

	Power			Interest Rate and Foreign Currency			Total
Beginning Balance in AOCI, December 31, 2006	$	17		$	(23	)	$	(6	)
Changes in Fair Value		(1	)		(4	)		(5	)
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled		(17	)		2			(15	)
Ending Balance in AOCI, December 31, 2007	$	(1	)	$	(25	)	$	(26	)

After Tax Portion Expected to be Reclassified to Earnings During Next 12 Months	$	(2	)	$	(3	)	$	(5	)