Unassociated Document

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 and Extraordinary Item	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.	Acquisition	CSPCo
8.	Benefit Plans	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
9.	Nuclear	I&M
10.	Business Segments	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
11.	Derivatives, Hedging and Fair Value Measurements	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
12.	Income Taxes	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
13.	Leases	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
14.	Financing Activities	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
15.	Related Party Transactions	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
16.	Property, Plant and Equipment	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
17.	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 and SWEPCo conducts coal mining operations to fuel certain of its generation facilities.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

The Registrant Subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the nine state operating territories in which they operate. The state regulatory commissions approve retail rates 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 AEP’s, AEPSC’s and the Registrant Subsidiaries’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility holding company subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. A FERC order in 2008 pursuant to the Federal Power Act codified that for non-power goods and services, a non-regulated affiliate can bill a public utility company no more than market while a public utility must bill the higher of cost or market to a non-regulated affiliate. The state regulatory commissions in Virginia and West Virginia also regulate certain intercompany transactions under their affiliates statutes.

The FERC regulates wholesale power markets and wholesale power transactions. The Registrant Subsidiaries’ wholesale power transactions are generally market-based. They are cost-based regulated when the Registrant Subsidiaries negotiate and file a cost-based contract with the FERC or the FERC determines that the Registrant Subsidiaries have “market power” in the region where the transaction occurs. The Registrant Subsidiaries enter into wholesale power supply contracts with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. SWEPCo’s and PSO’s wholesale power transactions in the SPP region are 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 claims jurisdiction over retail transmission rates when retail rates are unbundled in connection with restructuring. CSPCo’s and OPCo’s retail rates in Ohio, APCo’s retail rates in Virginia and I&M’s retail rates in Michigan are unbundled. CSPCo’s and OPCo’s retail transmission rates are based on the FERC’s Open Access Transmission Tariff (OATT) rates that are cost-based. Although APCo’s retail rates in Virginia and I&M’s retail rates in Michigan are unbundled, retail transmission rates are regulated, on a cost basis, by the state regulatory commissions. Starting in 2009, APCo may file, and the Virginia SCC shall approve, a rate adjustment clause that passes through charges associated with the FERC’s OATT rates to APCo’s Virginia retail customers. Bundled retail transmission rates are regulated, on a cost basis, by the state regulatory commissions.

In addition, the FERC regulates the SIA, the Interconnection Agreement, the CSW Operating Agreement, the System Transmission Integration Agreement, the Transmission Equalization Agreement, the Transmission Coordination Agreement and the AEP System Interim Allowance Agreement, all of which allocate shared system costs and revenues to the Registrant Subsidiaries that are parties to each agreement.

The state regulatory commissions regulate all of the retail public utility services/operations (generation/power supply, transmission and distribution operations) and rates except in Ohio. The retail generation/power supply operations and rates for CSPCo and OPCo in Ohio are no longer cost-based regulated. These rates were subject to RSPs through December 31, 2008. The PUCO extended these rates until they issue a ruling on the ESPs or the end of the February 2009 billing cycle, whichever comes first. The ESP rates are under recently enacted legislation, which continues the concept of increasing rates over time to approach market rates. In 2007, the Virginia legislation ended a transition to market-based rates and returned APCo to cost-based regulation. See Note 4 for further information of restructuring legislation and its effects on AEP in Ohio and Michigan.

Both the FERC and state regulatory commissions 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 Subsidiary and its wholly-owned subsidiaries. The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Sabine (a substantially-controlled variable interest entity (VIE)). The consolidated financial statements for OPCo include the Registrant Subsidiary and JMG (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. Equity investments not substantially-controlled and which the subsidiary is not the primary beneficiary of the entity, 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 balance sheets; equity earnings are included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. For years, CSPCo, OPCo, PSO and SWEPCo have had ownership interests in generating units that are jointly-owned with nonaffiliated companies. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets. See “Variable Interest Entities” section of Note 15.

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 the Texas portion of SWEPCo 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 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 re-regulation of APCo’s generation and supply rates on a cost basis.

Use of Estimates

The preparation of these financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, 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 equity 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 regulated electric utility plant. For nonregulated operations, including 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, PSO and SWEPCo. OPCo and CSPCo value fossil fuel inventories at the lower of average cost or market. Materials and supplies inventories are carried at average cost.

Accounts Receivable

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

Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrant Subsidiaries accrue and recognize, as Accrued Unbilled Revenues, 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 14).

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, 2008.

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

Deferred Fuel Costs

The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the amortization of nuclear fuel costs which are computed primarily on the units-of-production method. Where applicable under governing state regulatory commission retail rate orders, fuel cost over-recoveries (the excess of fuel revenues billed to customers over applicable fuel costs incurred) are deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel revenues billed to customers) are deferred as current regulatory assets. These deferrals are amortized when refunded or when 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 the Registrant Subsidiaries' fuel cost calculations and deferrals. When a fuel cost disallowance becomes probable, the Registrant Subsidiaries adjust their deferrals and record provisions for estimated refunds to recognize these probable outcomes. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when the fuel clauses have been suspended or terminated.

In general, changes in fuel costs in Indiana (beginning July 1, 2007) and Michigan for I&M, Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia and West Virginia (beginning July 1, 2006) for APCo are reflected in rates in a timely manner through the fuel cost adjustment clauses in place in those states. All of the profits from off-system sales are shared with customers through fuel clauses in West Virginia (beginning in July 1, 2006). A portion of profits from off-system sales are shared with customers through fuel clauses in Texas, Oklahoma, Louisiana, Arkansas, 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 (prior to July 1, 2007 in Indiana and prior to July 1, 2006 in West Virginia), where fuel clauses were capped, frozen or suspended for a period of years, fuel costs impacted earnings.

Revenue Recognition

Regulatory Accounting

The financial statements of the Registrant Subsidiaries with cost-based rate-regulated operations reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation 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 at each balance sheet date or whenever new events occur. Examples include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the Registrant Subsidiaries write off that regulatory asset as a charge against income.

Traditional Electricity Supply and Delivery Activities

The Registrant Subsidiaries recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrant Subsidiaries recognize the revenues 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. The AEP East companies purchase power from PJM to supply power to their customers. 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 exchanges.

Physical energy purchases including those from 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 for CSPCo and OPCo and Texas for SWEPCo. 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).

For power purchased under derivative contracts in AEP’s west zone where PSO and SWEPCo 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, PSO and SWEPCo 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, PSO and SWEPCo 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

AEPSC, on behalf of the Registrant Subsidiaries and KPCo, engages in wholesale electricity, coal, natural gas and emission allowances marketing and risk management activities focused on wholesale markets where the AEP System owns assets and adjacent markets. These activities include the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options, and over-the-counter options and swaps. Certain energy marketing and risk management transactions are with RTOs.

The Registrant Subsidiaries recognize revenues and expenses from wholesale marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrant Subsidiaries use MTM accounting for wholesale marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or a normal purchase or sale. 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).

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

Certain qualifying wholesale marketing and risk management derivatives transactions are designated as hedges of future cash flows as a result of forecasted transactions (cash flow hedge). The Registrant Subsidiaries initially record the effective portion of the cash flow hedge’s gain or loss as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrant Subsidiaries subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their income statements. For CSPCo and OPCo, the ineffective portion of the gain or loss is recognized in revenues or expense 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 11.

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 defers distribution tree trimming costs above the level included in base rates and amortizes the costs commensurate with recovery through a rate rider in Oklahoma. PSO also amortizes deferred ice storm costs commensurate with their recovery through a rate rider.

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 beginning January 1, 2007, 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, 2008 and 2007.

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 and States. They follow the inventory model for these 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 held for speculation 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 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. Other-than-temporary impairments are considered realized losses as I&M does not make specific investment decisions regarding the assets held in trusts. They 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 9 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) (AOCI)

AOCI is included on the balance sheets in the common shareholder’s equity section. AOCI for the Registrant Subsidiaries as of December 31, 2008 and 2007 is shown in the following table:

	December 31,
	2008			2007
	(in thousands)
Cash Flow Hedges, Net of Tax
APCo	$	(5,392	)	$	(5,944	)
CSPCo		1,531			(650	)
I&M		(9,039	)		(12,151	)
OPCo		3,650			1,157
PSO		(704	)		(887	)
SWEPCo		(5,924	)		(6,021	)

Amortization of Pension and OPEB Deferred Costs, Net of Tax
APCo	$	3,333		$	-
CSPCo		1,128			-
I&M		441			-
OPCo		2,813			-
SWEPCo		941			-

Pension and OPEB Funded Status, Net of Tax
APCo	$	(58,166	)	$	(29,243	)
CSPCo		(53,684	)		(18,144	)
I&M		(13,096	)		(3,524	)
OPCo		(140,321	)		(37,698	)
SWEPCo		(27,137	)		(10,418	)

Earnings Per Share (EPS)

APCo, CSPCo, I&M, OPCo, PSO and SWEPCo are wholly-owned subsidiaries 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. See “FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” section of Note 2 for discussion of changes in netting certain balance sheet amounts. These reclassifications had no impact on the Registrant Subsidiaries’ previously reported net income or changes in shareholders’ equity.

2.	NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM

NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The follow represents a summary of final pronouncements that management has determined relate to the Registrant Subsidiaries’ operations.

Pronouncements Adopted in 2008

The following standards were effective during 2008. Consequently, the financial statements and footnotes reflect their impact.

SFAS 157 “Fair Value Measurements” (SFAS 157)

The Registrant Subsidiaries partially adopted SFAS 157 effective January 1, 2008. The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures.

In February 2008, the FASB issued FSP SFAS 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” (SFAS 157-1) which amends SFAS 157 to exclude SFAS 13 “Accounting for Leases” (SFAS 13) and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13. SFAS 157-1 was effective upon issuance and had an immaterial impact on the financial statements.

In February 2008, the FASB issued FSP SFAS 157-2 “Effective Date of FASB Statement No. 157” (SFAS 157-2) 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 fully adopted SFAS 157 effective January 1, 2009 for items within the scope of SFAS 157-2. The adoption of SFAS 157-2 had an immaterial impact on the financial statements.

In October 2008, the FASB issued FSP SFAS 157-3 “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active” which clarifies application of SFAS 157 in markets that are not active and provides an illustrative example. The FSP was effective upon issuance. The adoption of this standard had no impact on the financial statements.

See “SFAS 157 Fair Value Measurements” Section of Note 11 for further information.

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

The FASB permitted entities to choose to measure many financial instruments and certain other items at fair value. The standard also established 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 162 “The Hierarchy of Generally Accepted Accounting Principles” (SFAS 162)

In May 2008, the FASB issued SFAS 162, clarifying the sources of generally accepted accounting principles in descending order of authority. The statement specifies that the reporting entity, not its auditors, is responsible for its compliance with GAAP.

The Registrant Subsidiaries adopted SFAS 162 in the fourth quarter of 2008. The adoption of this standard had no impact on the financial statements.

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 if the employer 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 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) retrospective application to all prior periods. The Registrant Subsidiaries adopted EITF 06-10 effective January 1, 2008. The impact of this standard was an unfavorable cumulative effect adjustment, net of tax, to beginning retained earnings as follows:

	Retained
	Earnings			Tax
	Reduction			Amount
Company	(in thousands)
APCo		$	2,181		$	1,175
CSPCo			1,095			589
I&M			1,398			753
OPCo			1,864			1,004
PSO			1,107			596
SWEPCo			1,156			622

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 addressed the recognition of income tax benefits of dividends on employee share-based compensation. 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. The adoption of this standard had an immaterial impact on the financial statements.

FSP SFAS 133-1 and FIN 45-4 “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161” (FSP SFAS 133-1 and FIN 45-4)

In September 2008, the FASB issued FSP SFAS 133-1 and FIN 45-4 amending SFAS 133 and FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” Under the SFAS 133 requirements, the seller of a credit derivative shall disclose the following information for each derivative, including credit derivatives embedded in a hybrid instrument, even if the likelihood of payment is remote:

(a)	The nature of the credit derivative.
(b)	The maximum potential amount of future payments.
(c)	The fair value of the credit derivative.
(d)	The nature of any recourse provisions and any assets held as collateral or by third parties.

Further, the standard requires the disclosure of current payment status/performance risk of all FIN 45 guarantees. In the event an entity uses internal groupings, the entity shall disclose how those groupings are determined and used for managing risk.

The Registrant Subsidiaries adopted the standard effective December 31, 2008. The adoption of this standard had no impact on the financial statements and footnote disclosures.

FSP SFAS 140-4 and FIN 46R-8 “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities” (FSP SFAS 140-4 and FIN 46R-8)

In December 2008, the FASB issued FSP SFAS 140-4 and FIN 46R-8 amending SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” and FIN 46R “Consolidation of Variable Interest Entities.” Under the requirements, the transferor of financial assets in the securitization or asset-backed financing arrangement must disclose the following:

(a)	Nature of any restrictions on assets reported by an entity in its balance sheet that relate to a transferred financial asset, including the carrying amounts of such assets.
(b)	Method of reporting servicing assets and servicing liabilities.
(c)	If reported as sales and the transferor has continuing involvement with the transferred financial assets and the transfers are accounted for as secured borrowings, how the transfer of financial assets affects the transferors’ balance sheet, net income and cash flows.

The FIN 46R amendments contain disclosure requirements for a public enterprise that (a) is the primary beneficiary of a variable interest entity (VIE), (b) holds a significant variable interest in a VIE but is not the primary beneficiary or (c) is a sponsor that holds a variable interest in a VIE. The principle objectives of the disclosures required by this standard are to provide financial statement users an understanding of:

(a)	Significant judgments and assumptions made to determine whether to consolidate a variable interest entity and/or disclose information about involvement with a variable interest entity.
(b)	Nature of the restrictions on a consolidated variable interest entity’s assets reported in the balance sheet, including the carrying amounts of such assets.
(c)	Nature of, and changes in, risks associated with a company’s involvement with a variable interest entity.
(d)	A variable interest entity’s effect on the balance sheet, net income and cash flows.
(e)	The nature, purpose, size and activities of any variable interest equity, including how it is financed.

The Registrant Subsidiaries adopted the standard effective December 31, 2008. The adoption of this standard had no impact on the financial statements but increased the footnote disclosures for variable interest entities. See “Variable Interest Entities” section of Note 15.

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

In April 2007, the FASB issued FSP FIN 39-1 amending FIN 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. The amendment 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 the standard effective January 1, 2008. This standard changed the method of netting certain balance sheet amounts and reduced assets and liabilities. It requires retrospective application as a change in accounting principle. Consequently, the Registrant Subsidiaries reclassified the following amounts on their December 31, 2007 balance sheets as shown:

December 2007 10-K	FSP FIN 39-1 Reclassification
Balance Sheet	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
Line Description	(in thousands)
Current Assets:
Risk Management Assets	$	(1,752	)	$	(1,006	)	$	(969	)	$	(1,254	)	$	(30	)	$	(43	)
Margin Deposits		-			-			-			-			(139	)		(164	)
Prepayments and Other		(3,306	)		(1,917	)		(1,841	)		(2,232	)		-			-
Long-term Risk Management Assets		(2,588	)		(1,500	)		(1,441	)		(1,748	)		(18	)		(22	)

Current Liabilities:
Risk Management Liabilities		(3,247	)		(1,881	)		(1,807	)		(2,192	)		(33	)		(39	)
Customer Deposits		(4,340	)		(2,507	)		(2,410	)		(3,002	)		(48	)		(64	)
Long-term Risk Management Liabilities		(59	)		(35	)		(34	)		(40	)		(106	)		(126	)

For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the December 31, 2008 balance sheets, the Registrant Subsidiaries netted collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

	December 31, 2008
	Cash Collateral			Cash Collateral
	Received			Paid
	Netted Against			Netted Against
	Risk Management			Risk Management
	Assets			Liabilities
Company	(in thousands)
APCo		$	2,189		$	5,621
CSPCo			1,229			3,156
I&M			1,189			3,054
OPCo			1,522			3,909
PSO			-			105
SWEPCo			-			124

Pronouncements Adopted During The First Quarter of 2009

The following standards are effective during the first quarter of 2009. Consequently, their impact will be reflected in the first quarter of 2009 financial statements when filed. The following paragraphs discuss their expected impact on future financial statement and footnote disclosures.

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 established 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. The standard 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 can affect tax positions on previous acquisitions. The Registrant Subsidiaries do not have any such tax positions that result in adjustments.

The Registrant Subsidiaries adopted SFAS 141R effective January 1, 2009. It is effective prospectively for business combinations with an acquisition date on or after January 1, 2009. The Registrant Subsidiaries will apply it to any future business combinations.

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

In December 2007, the FASB issued SFAS 160, modifying reporting for noncontrolling interest (minority interest) in consolidated financial statements. The statement 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.

The Registrant Subsidiaries adopted SFAS 160 effective January 1, 2009. The adoption of this standard had an immaterial impact and will be applied retrospectively to prior period financial statements in future filings so the presentation of noncontrolling interest is comparable.

SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161)

In March 2008, the FASB issued SFAS 161, enhancing disclosure requirements for derivative instruments and hedging activities. Affected entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how an entity accounts for derivative instruments and related hedged items and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The standard requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation.

The Registrant Subsidiaries adopted SFAS 161 effective January 1, 2009. This standard will increase the disclosure requirements related to derivative instruments and hedging activities in future reports.

EITF Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5)

In September 2008, the FASB ratified the consensus on liabilities with third-party credit enhancements when the liability is measured and disclosed at fair value. The consensus treats the liability and the credit enhancement as two units of accounting. Under the consensus, the fair value measurement of the liability does not include the effect of the third-party credit enhancement. Consequently, changes in the issuer’s credit standing without the support of the credit enhancement affect the fair value measurement of the issuer’s liability. Entities will need to provide disclosures about the existence of any third-party credit enhancements related to their liabilities. In the period of adoption, entities must disclose the valuation method(s) used to measure the fair value of liabilities within its scope and any change in the fair value measurement method that occurs as a result of its initial application.

The Registrant Subsidiaries adopted EITF 08-5 effective January 1, 2009. It will be applied prospectively with the effect of initial application included as a change in fair value of the liability in the period of adoption. The adoption of this standard will impact the financial statements in the 2009 Annual Report as the Registrant Subsidiaries report fair value of long-term debt annually.

EITF Issue No. 08-6 “Equity Method Investment Accounting Considerations” (EITF 08-6)

In November 2008, the FASB ratified the consensus on equity method investment accounting including initial and allocated carrying values and subsequent measurements. It requires initial carrying value be determined using the SFAS 141R cost allocation method. When an investee issues shares, the equity method investor should treat the transaction as if the investor sold part of its interest.

The Registrant Subsidiaries adopted EITF 08-6 effective January 1, 2009 with no impact on the financial statements. It was applied prospectively.

FSP SFAS 142-3 “Determination of the Useful Life of Intangible Assets” (SFAS 142-3)

In April 2008, the FASB issued SFAS 142-3 amending factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. The standard is expected to improve consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure its fair value.

The Registrant Subsidiaries adopted SFAS 142-3 effective January 1, 2009. The guidance is prospectively applied to intangible assets acquired after the effective date. The standard’s disclosure requirements are applied prospectively to all intangible assets as of January 1, 2009. The adoption of this standard had no impact on the financial statements.

Pronouncements Effective in the Future

The following standards will be effective in the future and their impacts disclosed at that time.

FSP SFAS 132R-1 “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP SFAS 132R-1)

In December 2008, the FASB issued FSP SFAS 132R-1 providing additional disclosure guidance for pension and OPEB plan assets. The rule requires disclosure of investment policy including target allocations by investment class, investment goals, risk management policies and permitted or prohibited investments. It specifies a minimum of investment classes by further dividing equity and debt securities by issuer grouping. The standard adds disclosure requirements including hierarchical classes for fair value and concentration of risk.

This standard is effective for fiscal years ending after December 15, 2009. Management expects this standard to increase the disclosure requirements related to AEP’s benefit plans. The Registrant Subsidiaries will adopt the standard effective for the 2009 Annual Report.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, management cannot determine the impact on the reporting of the Registrant Subsidiaries’ operations and financial position that may result from any such future changes. The FASB is currently working on several projects including revenue recognition, contingencies, liabilities and equity, emission allowances, leases, insurance, hedge accounting, consolidation policy, trading inventory 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 net income 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.

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 was $8.8 million and $9.9 million at December 31, 2008 and 2007, respectively, 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,
			2008				2007
	Amortization Life		Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
	(in years)		(in millions)				(in millions)
Advanced Royalties		15	$	29.4	$	20.6	$	29.4	$	19.5

Amortization of the intangible asset was $1 million, $3 million and $3 million for 2008, 2007 and 2006, respectively. SWEPCo’s estimated total amortization is $1.1 million per year for 2009 through 2016, when the asset will be fully amortized with no residual value.

The Advanced Royalties asset class relates to the lignite mine of DHLC, a wholly-owned subsidiary of SWEPCo. In December 2008, SWEPCo received an order from the LPSC that extended the useful life of the mine for an additional five years, beginning January 1, 2008, 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 net income and cash flows.

For discussion of the FERC’s November 2008 order on AEP’s allocation of off-system sales, see “Allocation of Off-system Sales Margins” section within “FERC Rate Matters”.

Ohio Rate Matters

Ohio Electric Security Plan Filings – Affecting CSPCo and OPCo

In April 2008, the Ohio legislature passed Senate Bill 221, which amended the restructuring law effective July 31, 2008 and required electric utilities to adjust their rates by filing an Electric Security Plan (ESP). Electric utilities could include a fuel cost recovery mechanism (FCR) in their ESP filing. Electric utilities also had an option to file a Market Rate Offer (MRO) for generation pricing. An MRO, from the date of its commencement, would have transitioned CSPCo and OPCo to full market rates no sooner than six years and no later than ten years after the PUCO approves an MRO. The PUCO has the authority to approve and/or modify each utility’s ESP request. The PUCO is required to approve an ESP if, in the aggregate, the ESP is more favorable to ratepayers than an MRO. Both alternatives involve a “significantly excessive earnings” test (SEET) based on what public companies, including other utilities with similar risk profiles, earn on equity.

In July 2008, within the parameters of the ESPs, CSPCo and OPCo filed with the PUCO to establish rates for 2009 through 2011. CSPCo and OPCo did not file an optional MRO. CSPCo’s and OPCo’s ESP filings requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year. A significant portion of the requested ESP increases resulted from the implementation of a FCR that primarily includes fuel costs, purchased power costs, consumables such as urea, other variable production costs and gains and losses on sales of emission allowances. The FCR is proposed to be phased into customer bills over the three-year period from 2009 through 2011 and recovered with a weighted average cost of capital carrying cost deferral over seven years from 2012 through 2018. If the ESPs are approved as filed, effective with the implementation of the ESPs, CSPCo and OPCo will defer fuel cost over/under-recoveries and related carrying costs, including amounts unrecovered through the phase in period, for future recovery.

In addition to the FCR, the requested ESP increases would also recover incremental carrying costs associated with environmental costs, Provider of Last Resort (POLR) charges to compensate for the risk of customers changing electric suppliers, automatic increases for distribution reliability costs and for unexpected non-fuel generation costs. The filings also include recovery for programs for smart metering initiatives, economic development, mandated energy efficiency, renewable resources and peak demand reduction programs.

Within the ESP requests, CSPCo and OPCo would also recover existing regulatory assets of $47 million and $39 million, respectively, for customer choice implementation and line extension carrying costs incurred through December 2008. In addition, CSPCo and OPCo would recover related unrecorded equity carrying costs of $31 million and $23 million, respectively, through December 2008. The PUCO had previously issued orders allowing deferral of these costs. Such costs would be recovered over an 8-year period beginning January 2011. If the PUCO does not approve recovery of these regulatory assets in this or some future proceeding, it would have an adverse effect on future net income and cash flows.

Hearings were held in November and December 2008. Many intervenors filed opposing testimony. CSPCo and OPCo requested retroactive application of the new rates, including the FCR, back to the start of the January 2009 billing cycle upon approval of the ESPs. The RSP rates were effective for the years ended December 31, 2006, 2007 and 2008 under which CSPCo and OPCo had three annual generation rate increases of 3% and 7%, respectively. The RSP also allowed additional annual generation rate increases of up to an average of 4% per year to recover new governmentally-mandated costs. In January 2009, CSPCo and OPCo filed an application requesting the PUCO to authorize deferred fuel accounting beginning January 1, 2009. A motion to dismiss the application has been filed by Ohio Partners for Affordable Energy, while the Ohio Consumers’ Counsel has filed comments opposing the application. The PUCO ordered that CSPCo and OPCo continue using their current RSP rates until the PUCO issues a ruling on the ESPs or the end of the March 2009 billing cycle, whichever comes first. Management is unable to predict the financial statement impact of the restructuring legislation until the PUCO acts on specific proposals made by CSPCo and OPCo in their ESPs. CSPCo and OPCo anticipate a final order from the PUCO during the first quarter of 2009.

2008 Generation Rider and Transmission Rider Rate Settlement – Affecting CSPCo and OPCo

On January 30, 2008, the PUCO approved a settlement agreement, among CSPCo, OPCo and other parties, under the additional average 4% generation rate increase and transmission cost recovery rider (TCRR) provisions of the RSP. The increase was due to additional governmentally-mandated costs including incremental environmental costs. Under the settlement, the PUCO also approved recovery through the TCRR of 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 during the first quarter of 2008 of $12 million and $14 million, respectively, related to the future recovery of increased PJM billings previously expensed from June 2007 to December 2007 for transmission line losses. The PUCO also approved a credit applied to the TCRR of $10 million for OPCo and $8 million for CSPCo for a reduction in PJM net congestion costs. To the extent that collections for the TCRR recoveries are under/over actual net costs, CSPCo and OPCo will defer the difference as a regulatory asset or regulatory liability and adjust future customer billings to reflect actual costs, including carrying costs on the deferral. In addition, the PUCO approved recoveries through generation rates of environmental costs and related carrying costs of $29 million for CSPCo and $5 million for OPCo. These RSP rate adjustments were implemented in February 2008. The TCRR continues in CSPCo’s and OPCo’s proposed ESPs to provide for the recovery of PJM related costs.

2009 Generation Rider and Transmission Rider – Affecting CSPCo and OPCo

In October 2008, CSPCo and OPCo filed an application to update the TCRR. The application requested an average decrease of 3% for CSPCo and an average increase of 7% for OPCo, including under recoveries from the prior year and related carrying charges. Based on the requests, CSPCo annual revenues would decrease approximately $5 million and OPCo annual revenues would increase approximately $13 million.

In December 2008, the PUCO issued a final order approving the application with certain modifications. First, the rate to calculate carrying costs will change from using a current weighted average cost of capital rate (WACC), which includes a return on equity and a gross up for income taxes, to a long-term debt rate. CSPCo’s and OPCo’s approved long-term debt rates were 5.73% and 5.71%, respectively. In addition, the TCRR application eliminated the fuel-related credit which had been applied against the PJM transmission marginal line loss since CSPCo’s and OPCo’s proposed fuel adjustment clause in the filing of the ESP includes this credit. The new TCRR became effective with the January 2009 billing cycle.

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 generation rates which may be a market-based standard service offer price for generation and the expected higher 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 allow CSPCo and OPCo 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 pre-construction costs and incurred $11 million in pre-construction costs. As a result, CSPCo and OPCo each established a net regulatory liability of approximately $1 million.

The order also provided that 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 cost recoveries 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 2006, intervenors filed four separate appeals of the PUCO’s order in the IGCC proceeding. In March 2008, the Ohio Supreme Court issued its opinion affirming in part, and reversing in part the PUCO’s order and remanded the matter back to the PUCO. The Ohio Supreme Court held that while there could be an opportunity under existing law to recover a portion of the IGCC costs in distribution rates, traditional rate making procedures would apply to the recoverable portion. The Ohio Supreme Court did not address the matter of refunding the Phase 1 cost recovery and declined to create an exception to its precedent of denying claims for refund of past recoveries from approved orders of the PUCO. In September 2008, the Ohio Consumers’ Counsel filed a motion with the PUCO requesting all Phase 1 costs be refunded to Ohio ratepayers with interest because the Ohio Supreme Court invalidated the underlying foundation for the Phase 1 recovery. In October 2008, CSPCo and OPCo filed a motion with the PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit and contrary to past precedent.

In January 2009, a PUCO Attorney Examiner issued an order that CSPCo and OPCo file a detailed statement outlining the status of the construction of the IGCC plant, including whether CSPCo and OPCo are engaged in a continuous course of construction on the IGCC plant. In February 2009, CSPCo and OPCo filed a statement that CSPCo and OPCo have not commenced construction of the IGCC plant and believe there exist real statutory barriers to the construction of any new base load generation in Ohio, including IGCC plants. The statement also indicated that while construction on the IGCC plant might not begin by June 2011, changes in circumstances could result in the commencement of construction on a continuous course by that time.

As of December 2007 the estimated cost to build the IGCC plant was $2.7 billion which has continued to increase significantly. Management continues to pursue the ultimate construction of the IGCC plant. However, CSPCo and OPCo will not start construction of the IGCC plant until sufficient assurance of regulatory cost recovery exists.

If CSPCo and OPCo were required to refund the $24 million collected and those costs were not recoverable in another jurisdiction in connection with the construction of an IGCC plant, it would have an adverse effect on future net income and cash flows. Management cannot predict the outcome of the cost recovery litigation concerning the Ohio IGCC plant or what, if any effect, the litigation will have on future net income and cash flows.

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 and the difference was recovered through the amortization of an existing $57 million ($15 million for CSPCo and $42 million for OPCo) regulatory liability related to excess deferred state taxes resulting from the phase-out of an Ohio franchise tax recorded in 2005. During 2007, CSPCo and OPCo each amortized $7 million of this regulatory liability to increase income. During 2008, CSPCo and OPCo each amortized $21.5 million of this regulatory liability to income based on PUCO approved market prices. The settlement agreement required CSPCo and OPCo to exhaust the $57 million regulatory liability. Therefore, CSPCo reimbursed OPCo for $13.5 million of OPCo’s unamortized regulatory liability. The previously approved 2007 price of $47.69 per MWH was used through November 2008 when the PUCO approved a 2008 price of $53.03 per MWH. The additional amortization recorded in December 2008 of $11 million each for CSPCo and OPCo related to the increase in the 2008 PUCO approved market price for the period January 2008 through November 2008. As of December 31, 2008, the regulatory liability was fully amortized.

In December 2008, CSPCo, OPCo and Ormet filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet. The arrangement would remain in effect and expire upon the effective date of CSPCo’s and OPCo’s new ESP rates and the effective date of a new arrangement between Ormet and CSPCo/OPCo approved by the PUCO. Under the interim arrangement, Ormet would pay the applicable generation tariff rates and riders. CSPCo and OPCo sought to defer as a regulatory asset beginning in 2009 the difference between the PUCO approved 2008 market price and the applicable generation tariff rates and riders. CSPCo and OPCo propose to recover the deferral through the fuel adjustment clause mechanism they proposed in the ESP proceeding. In January 2009, the PUCO approved the application as an interim arrangement. Although the PUCO did not address recovery in this order, it is expected to be resolved in the pending ESP proceedings. In February 2009, an intervenor filed an application for rehearing of the PUCO’s interim arrangement approval. In February 2009, Ormet filed an application with the PUCO for approval of a proposed power contract for 2009 through 2018. Ormet proposed that it pay varying amounts based on certain conditions, including the price of aluminum. The difference between the amounts paid by Ormet and the otherwise applicable PUCO tariff rate would be either collected from or refunded to CSPCo’s and OPCo’s retail customers.

Hurricane Ike – Affecting CSPCo and OPCo

In September 2008, the service territories of CSPCo and OPCo were impacted by strong winds from the remnants of Hurricane Ike. Under the RSP, CSPCo and OPCo could seek a distribution rate adjustment to recover incremental distribution expenses related to major storm service restoration efforts. In September 2008, CSPCo and OPCo established regulatory assets of $17 million and $10 million, respectively. In December 2008, CSPCo and OPCo filed with the PUCO a request to establish the regulatory assets, plus carrying costs using CSPCo’s and OPCo’s weighted average cost of capital carrying charge rates. In December 2008, the PUCO subsequently approved the establishment of the regulatory assets but authorized CSPCo and OPCo to record a long-term debt only carrying cost on the regulatory asset. In its order approving the deferrals, the PUCO stated that recovery would be determined in CSPCo’s and OPCo’s future filings.

In December 2008, the Consumers for Reliable Electricity in Ohio filed a request with the PUCO asking for an investigation into the service reliability of Ohio’s investor-owned electric utilities, including CSPCo and OPCo. The investigation request includes the widespread outages caused by the September 2008 wind storm. CSPCo and OPCo filed a response asking the PUCO to deny the request.

As a result of the past favorable treatment of storm restoration costs and the RSP provisions, which were in effect when the storm occurred and the filings made, management believes the recovery of the regulatory assets is probable. However, if these regulatory assets are not recovered, it would have an adverse effect on future net income and cash flows.

Virginia Rate Matters

Virginia Base Rate Filing – Affecting APCo

In May 2008, APCo filed an application with the Virginia SCC to increase its base rates by $208 million on an annual basis. The proposed revenue requirement reflected a return on equity of 11.75%. As permitted under Virginia law, APCo implemented these new base rates, subject to refund, effective October 28, 2008.

In October 2008, APCo submitted a $168 million settlement agreement to the Virginia SCC which was accepted by most parties. The $168 million settlement agreement revenue requirement was determined using a 10.2% return on equity and reflected the Virginia SCC staff’s recommended increase as adjusted.

In November 2008, the Virginia SCC issued a final order approving the settlement agreement which increased APCo’s annual base revenues by $168 million. The new authorized rates were implemented in December 2008, retroactive to October 28, 2008. APCo made customer refunds with interest in January 2009 for the difference between the interim rates and the approved rates.

Virginia E&R Costs Recovery Filing – Affecting APCo

In May 2008, APCo filed a request with the Virginia SCC to recover $66 million of its incremental E&R costs incurred for the period of October 2006 to December 2007. In September 2008, a settlement was reached and a stipulation agreement (stipulation) to recover $61 million of costs was submitted to the hearing examiner. The stipulation included recovery of $4.5 million representing one-half of a $9 million Virginia jurisdictional portion of NSR settlement expenses recorded in 2007. In accordance with the stipulation, APCo will request the remaining one-half of the $9 million of NSR settlement expenses in APCo’s 2009 E&R filing.

In September 2008, the hearing examiner recommended that the Virginia SCC accept the stipulation. As a result, in September 2008, APCo deferred as a regulatory asset $9 million of NSR settlement expenses it had expensed in 2007 on the basis that those expenses had become probable of future recovery. In October 2008, the Virginia SCC approved the stipulation which will have a favorable effect on 2009 cash flows of $61 million and on net income for the previously unrecognized equity carrying costs of approximately $11 million.

As of December 31, 2008, APCo has $123 million of deferred Virginia incremental E&R costs (excluding $25 million of unrecognized equity carrying costs). The $123 million consists of $6 million of over recovery of costs collected from the 2008 surcharge, $50 million approved by the Virginia SCC related to APCo’s May 2008 E&R filing to be recovered in 2009, and $79 million, representing costs deferred in 2008, to be included in the 2009 E&R filing, to be collected in 2010.

If the Virginia SCC were to disallow a material portion of APCo’s 2008 deferral of incremental E&R costs including the remaining $4.5 million of the NSR settlement expenses, it would have an adverse effect on future net income and cash flows.

Virginia Fuel Clause Filing – Affecting APCo

In July 2008, APCo initiated a fuel factor proceeding with the Virginia SCC and requested an annualized increase of $132 million effective September 1, 2008. The increase primarily related to increases in coal costs. In October 2008, the Virginia SCC ordered an annualized increase of $117 million based on differences in estimated future costs and inclusive of PJM transmission marginal line losses, subject to subsequent true-up to actual.

APCo’s Filings for an IGCC Plant – Affecting APCo

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

In June 2007, APCo sought pre-approval with the WVPSC for a surcharge rate mechanism to provide for the timely recovery of 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. In March 2008, the WVPSC granted APCo the CPCN to build the plant and approved the requested cost recovery. In March 2008, various intervenors filed petitions with the WVPSC to reconsider the order. No action has been taken on the requests for rehearing.

In July 2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to recover initial costs associated with a proposed IGCC plant. The filing requested recovery of an estimated $45 million over twelve months beginning January 1, 2009. The $45 million included a return on projected CWIP and development, design and planning pre-construction costs incurred from July 1, 2007 through December 31, 2009. APCo also requested authorization to defer a carrying cost on deferred pre-construction costs incurred beginning July 1, 2007 until such costs are recovered.

The Virginia SCC issued an order in April 2008 denying APCo’s requests, in part, upon its finding that the estimated cost of the plant was uncertain and may escalate. The Virginia SCC also expressed concern that the $2.2 billion estimated cost did not include a retrofitting of carbon capture and sequestration facilities. In July 2008, based on the unfavorable order received in Virginia, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed. Comments were filed by various parties, including APCo, but the WVPSC has not taken any action.

Through December 31, 2008, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to the West Virginia jurisdiction, approximately $2 million applicable to the FERC jurisdiction and approximately $9 million allocated to the Virginia jurisdiction.

In July 2008, the IRS allocated $134 million in future tax credits to APCo for the planned IGCC plant contingent upon the commencement of construction, qualifying expense being incurred and certification of the IGCC plant prior to July 2010.

Although management continues to pursue the construction of the IGCC plant, APCo will not start construction of the IGCC plant until sufficient assurance of cost recovery exists. If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs. If the plant is cancelled and if the deferred costs are not recoverable, it would have an adverse effect on future net income and cash flows.

Mountaineer Carbon Capture Project – Affecting APCo

In January 2008, APCo and ALSTOM Power Inc. (Alstom), an unrelated third party, entered into an agreement to jointly construct a CO2 capture demonstration facility. APCo and Alstom will each own part of the CO2 capture facility. APCo will also construct and own the necessary facilities to store the CO2. RWE AG, a German electric power and natural gas public utility, is participating in the evaluation of the commercial and technical feasibility of taking captured CO2 from the flue gas stream and storing it in deep geologic formations. APCo’s estimated cost for its share of the facilities is $76 million. Through December 31, 2008, APCo incurred $29 million in capitalized project costs which are included in Regulatory Assets. APCo is earning a return on the capitalized project costs incurred through June 30, 2008, as a result of the base rate case settlement approved by the Virginia SCC in November 2008. See the “Virginia Base Rate Filing” section above. APCo plans to seek recovery for the CO2 capture and storage project costs in its next Virginia and West Virginia base rate filings which are expected to be filed in 2009. If a significant portion of the deferred project costs are excluded from base rates and ultimately disallowed in future Virginia or West Virginia rate proceedings, it could have an adverse effect on future net income and cash flows.

West Virginia Rate Matters

APCo’s 2008 Expanded Net Energy Cost (ENEC) Filing – Affecting APCo

In February 2008, APCo filed with the WVPSC for an increase of approximately $140 million including a $122 million increase in the ENEC, a $15 million increase in construction cost surcharges and $3 million of reliability expenditures, to become effective July 2008. In June 2008, the WVPSC issued an order approving a joint stipulation and settlement agreement granting rate increases, effective July 2008, of approximately $95 million based on differences in estimated future costs, including an $79 million increase in the ENEC, a $13 million increase in construction cost surcharges and $3 million of reliability expenditures. The ENEC is an expanded form of a fuel clause mechanism, which includes all energy-related costs including fuel, purchased power expenses, off-system sales credits, PJM costs associated with transmission line losses due to the implementation by PJM transmission marginal line loss pricing and other energy/transmission items.

The ENEC and reliability surcharges are subject to a true-up to actual costs. Therefore, there should be no earnings effect if actual costs exceed the recoveries due to the deferral of any under-recovery of costs. The construction cost is not subject to a true-up to actual costs and could impact future net income and cash flows if actual costs exceed the amounts approved for recovery.

APCo’s Filings for an IGCC Plant – Affecting APCo

See “APCo’s Filings for an IGCC Plant” section within “Virginia Rate Matters” for disclosure.

Mountaineer Carbon Capture Project – Affecting APCo

See “Mountaineer Carbon Capture Project” section within “Virginia Rate Matters” for disclosure.

Indiana Rate Matters

Indiana Base Rate Filing – Affecting I&M

In a January 2008 filing with the IURC, updated in the second quarter of 2008, I&M requested an increase in its Indiana base rates of $80 million including a return on equity of 11.5%. The base rate increase included a $69 million annual reduction in depreciation expense previously approved by the IURC and implemented for accounting purposes effective June 2007. The filing also requested trackers for certain variable components of the cost of service including recently increased PJM costs associated with transmission line losses due to the implementation of PJM transmission marginal line loss pricing and other RTO costs, reliability enhancement costs, demand side management/energy efficiency costs, off-system sales margins and environmental compliance costs. The trackers would initially increase annual revenues by an additional $45 million. I&M proposes to share with customers, through a proposed tracker, 50% of off-system sales margins initially estimated to be $96 million annually with a guaranteed credit to customers of $20 million.

In December 2008, I&M and all of the intervenors jointly filed a settlement agreement with the IURC proposing to resolve all of the issues in the case. The settlement agreement included a $22 million increase in revenue from base rates with an authorized return on equity of 10.5% and a $22 million initial increase in tracker revenue. The agreement also establishes an off-system sales sharing mechanism and trackers for PJM, net emission allowance, and DSM costs, among other provisions which include continued funding for the eventual decommissioning of the Cook Nuclear Plant. I&M anticipates a final order from the IURC during the first quarter of 2009.

Rockport and Tanners Creek – Affecting I&M

In January 2009, I&M filed a petition with the IURC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to use advanced coal technology which would allow I&M to reduce airborne emissions of NOx and mercury from existing coal-fired steam electric generating units at the Rockport and Tanners Creek Plants. In addition, the petition is requesting approval to construct and recover the costs of selective non-catalytic reduction (SNCR) systems at the Tanners Creek plant and to recover the costs of activated carbon injection (ACI) systems on both generating units at the Rockport plant. I&M is requesting to depreciate the ACI systems over a period of 10 years and the SNCR systems over the remaining useful life of the Tanners Creek generating units. I&M requested the IURC to approve a rate adjustment mechanism of unrecovered carrying costs during construction and a return on investment, depreciation expense and operation and maintenance costs, including consumables and new emission allowance costs, once the projects are placed in service. I&M also requested the IURC to authorize deferral of costs and carrying costs until such costs are recognized in the rate adjustment mechanism. The IURC has not issued a procedural schedule at this time for this petition. Management is unable to predict the outcome of this petition.

Indiana Fuel Clause Filing – Affecting I&M

In January 2009, I&M filed with the IURC an application to increase its fuel adjustment charge by approximately $53 million for April through September 2009. The filing included an under-recovery for the period ended November 2008, mainly as a result of the extended outage of the Cook Unit 1 due to damage to the main turbine and generator and increased coal prices, and a projection for the future period of fuel costs including Cook Unit 1 replacement power fuel clause costs. The filing also included an adjustment to reduce the incremental fuel cost of replacement power with a portion of the insurance proceeds from the Cook Unit 1 accidental outage policy. See “Cook Plant Unit 1 Fire and Shutdown” section within the “Commitment, Guarantees and Contingencies” footnote for further details. I&M reached an agreement in February 2009 with intervenors to collect the under-recovery over twelve months instead of over six months as proposed. Under the agreement, the fuel factor will go into effect subject to refund and a subdocket will be established to consider issues relating to the Cook Unit 1 outage and I&M’s fuel procurement practices. A decision from the IURC is still pending.

Michigan Rate Matters

Michigan Restructuring – Affecting I&M

Although customer choice commenced for I&M’s Michigan customers on January 1, 2002, I&M’s rates for generation in Michigan continued to be cost-based regulated because none of I&M's customers elected to change suppliers and no alternative electric suppliers were registered to compete in I&M's Michigan service territory. In October 2008, the Governor of Michigan signed legislation to limit customer choice load to no more than 10% of the annual retail load for the preceding calendar year and to require the remaining 90% of annual retail load to be phased into cost-based rates. The new legislation also requires utilities to meet certain energy efficiency and renewable portfolio standards and permits cost recovery of meeting those standards. Management continues to conclude that I&M's rates for generation in Michigan are cost-based regulated and that I&M can practice regulatory accounting.

Oklahoma Rate Matters

PSO Fuel and Purchased Power – Affecting PSO

2006 and Prior Fuel and Purchased Power

Proceedings addressing PSO’s historic fuel costs through 2006 remain open at the OCC due to the issue of the allocation of off-system sales margins among the AEP operating companies in accordance with a FERC-approved allocation agreement. For further discussion and estimated effect on net income see “Allocation of Off-system Sales Margins” section within “FERC Rate Matters”.

In 2002, PSO under-recovered $42 million of fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to 2002. PSO recovered the $42 million during the period June 2007 through May 2008. In June 2008, the Oklahoma Industrial Energy Consumers (OIEC) appealed an ALJ recommendation that allowed PSO to retain the $42 million from ratepayers. The OIEC requested that PSO be required to refund the $42 million through its fuel clause. In August 2008, the OCC heard the OIEC appeal and a decision is pending.

2007 Fuel and Purchased Power

In September 2008, the OCC initiated a review of PSO’s generation, purchased power and fuel procurement processes and costs for 2007. Management cannot predict the outcome of the pending fuel and purchased power cost recovery filings. However, PSO believes its fuel and purchased power procurement practices and costs were prudent and properly incurred and therefore are legally recoverable.

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 have owned 50% of the new unit. OG&E and PSO requested pre-approval to construct the coal-fired Red Rock Generating Facility (Red Rock) 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 rejected the ALJ’s recommendation and denied PSO’s and OG&E’s applications for construction pre-approval. The OCC stated that PSO failed to fully study other alternatives to a coal-fired plant. Since PSO and OG&E could not obtain pre-approval to build Red Rock, PSO and OG&E cancelled the third party construction contract and their joint venture development contract.

In December 2007, PSO filed an application at the OCC requesting recovery of $21 million in pre-construction costs and contract cancellation fees associated with Red Rock. In March 2008, PSO and all other parties in this docket signed a settlement agreement that provided for recovery of $11 million of Red Rock pre-construction costs and carrying costs at PSO’s AFUDC rate beginning in March 2008 and continuing until the $11 million is included in base rates in PSO’s next base rate case. PSO will recover the costs over the expected life of the peaking facilities at the Southwestern Station, and include the costs in rate base in its next base rate filing. The OCC approved the settlement in May 2008. As a result of the settlement, PSO wrote off $10 million of its deferred pre-construction costs/cancellation fees in the first quarter of 2008. The remaining balance of $11 million was recorded as a regulatory asset. In July 2008, PSO filed a base rate case which included $11 million of deferred Red Rock costs plus carrying charges at PSO’s AFUDC rate beginning in March 2008. In January 2009, the OCC approved the base rate case. See “2008 Oklahoma Base Rate Filing” section below.

Oklahoma 2007 Ice Storms – Affecting PSO

In January and December 2007, PSO incurred maintenance expenses for two large ice storms. Prior to December 2007, PSO filed with the OCC requesting recovery of the maintenance expenses related to the January 2007 service restoration efforts. PSO proposed in its application to establish a regulatory asset to defer the previously expensed ice storm restoration costs and to offset the regulatory asset with gains from the sale of excess SO2 emission allowances.

In February 2008, PSO entered into a settlement agreement for recovery of ice storm restoration costs from both ice storms. In March 2008, the OCC approved the settlement agreement subject to a final audit. Therefore, in March 2008, PSO recorded a regulatory asset for the previously expensed ice storm maintenance costs. In October 2008, PSO received final approval to recover $74 million of ice storm costs. PSO has applied and will continue to apply proceeds from sale of excess SO2 emission allowances to reduce the regulatory asset. The estimated net balance that is not recovered from the sale of emission allowances will be amortized and recovered through a rider over a period of five years which began in November 2008. The rider will ultimately be trued-up to recover the entire $74 million regulatory asset. The regulatory asset earns a return of 10.92% until fully recovered.

2008 Oklahoma Base Rate Filing – Affecting PSO

In July 2008, PSO filed an application with the OCC to increase its base rates by $133 million (later adjusted to $127 million) on an annual basis. PSO has been recovering costs related to new peaking units recently placed into service through a Generation Cost Recovery Rider (GCRR). Subsequent to implementation of the new base rates, the GCRR will terminate and PSO will recover these costs through the new base rates. Therefore, PSO’s net annual requested increase in total revenues was actually $117 million (later adjusted to $111 million). The proposed revenue requirement reflected a return on equity of 11.25%.

In January 2009, the OCC issued a final order approving an $81 million increase in PSO’s non-fuel base revenues and a 10.5% return on equity. The rate increase includes a $59 million increase in base rates and a $22 million increase for costs to be recovered through riders outside of base rates. The $22 million increase includes $14 million for purchase power capacity costs and $8 million for the recovery of carrying costs associated with PSO’s program to convert overhead distribution lines to underground service. The $8 million recovery of carrying costs associated with the overhead to underground conversion program will occur only if PSO makes the required capital expenditures. The final order approved lower depreciation rates and also provides for the deferral of $6 million of generation maintenance expenses to be recovered over a six-year period. This deferral will be recorded in the first quarter of 2009. Additional deferrals were approved for distribution storm costs above or below the amount included in base rates and for certain transmission reliability expenses. The new rates reflecting the final order were implemented with the first billing cycle of February 2009.

In January 2009, PSO and one intervenor filed motions with the OCC to modify its final order. PSO filed an appeal with the Oklahoma Supreme Court challenging an adjustment the OCC made on prepaid pension funding contained within the OCC final order. The OCC subsequently declined to consider the motions to modify. In February 2009, the Oklahoma Attorney General and several intervenors also filed appeals with the Oklahoma Supreme Court raising several issues. If the Attorney General and/or the intervenor’s Supreme Court appeals are successful, it could have an adverse effect on future net income and cash flows.

Louisiana Rate Matters

Louisiana Compliance Filing – Affecting SWEPCo

In connection with SWEPCo’s merger related compliance filings, the LPSC approved a settlement agreement in April 2008 that prospectively resolves all issues regarding claims that SWEPCo had over-earned its allowed return. SWEPCo agreed to a formula rate plan (FRP) with a three-year term. Under the plan, beginning in August 2008, rates shall be established to allow SWEPCo to earn an adjusted return on common equity of 10.565%. The adjustments are standard Louisiana rate filing adjustments.

If in the second and third year 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 recovery deferrals for refund or future recovery under this FRP.

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

In addition, the settlement provides for a reduction in generation depreciation rates effective October 2007. SWEPCo deferred as a regulatory liability the effects of the expected depreciation reduction through July 2008. SWEPCo will amortize this 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.

In April 2008, SWEPCo filed the first FRP which would increase its annual Louisiana retail rates by $11 million in August 2008 to earn an adjusted return on common equity of 10.565%. In accordance with the settlement, SWEPCo recorded a $4 million regulatory liability related to the reduction in generation depreciation rates. The amount of the unamortized regulatory liability for the reduction in generation depreciation was $3 million as of December 31, 2008. In August 2008, the LPSC approved the settlement and SWEPCo implemented the FRP rates, subject to refund. No provision for refund has been recorded as SWEPCo believes that the rates as implemented are in compliance with the settlement.

Stall Unit – Affecting SWEPCo

In May 2006, SWEPCo announced plans to build a new intermediate load, 500 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 to the PUCT, the APSC, the LPSC and the Louisiana Department of Environmental Quality to seek approvals to construct the unit. The Stall Unit is currently estimated to cost $384 million, excluding AFUDC, and is expected to be in-service in mid-2010. The Louisiana Department of Environmental Quality issued an air permit for the Stall unit in March 2008.

In March 2007, the PUCT approved SWEPCo’s request for a certificate for the facility based on a prior cost estimate. In July 2008, a Louisiana ALJ issued a recommendation that SWEPCo be authorized to construct, own and operate the Stall Unit and recommended that costs be capped at $445 million (excluding transmission). In October 2008, the LPSC issued a final order effectively approving the ALJ recommendation. In December 2008, SWEPCo submitted an amended filing seeking approval from the APSC to construct the unit. The APSC has established a procedural schedule with a public hearing for April 2009.

If SWEPCo does not receive appropriate authorizations and permits to build the Stall Unit, SWEPCo would seek recovery of the capitalized construction costs including any cancellation fees. As of December 31, 2008, SWEPCo has capitalized construction costs of $252 million (including AFUDC) and has contractual construction commitments of an additional $99 million. As of December 31, 2008, if the plant had been cancelled, cancellation fees of $33 million would have been required in order to terminate the construction commitments. If SWEPCo cancels the plant and cannot recover its capitalized costs, including any cancellation fees, it would have an adverse effect on future net income, cash flows and possibly financial condition.

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 the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas. SWEPCo submitted filings with the APSC, the PUCT and the LPSC seeking certification of the plant. SWEPCo will own 73% of the Turk Plant and will operate the facility. During 2007, SWEPCo signed joint ownership agreements with the Oklahoma Municipal Power Authority (OMPA), the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric Cooperative (ETEC) for the remaining 27% of the Turk Plant. The Turk Plant is currently estimated to cost $1.6 billion, excluding AFUDC, with SWEPCo’s portion estimated to cost $1.2 billion. If approved on a timely basis, the plant is expected to be in-service in 2012.

In November 2007, the APSC granted approval to build the Turk Plant. Certain landowners filed a notice of appeal to the Arkansas State Court of Appeals. In March 2008, the LPSC approved the application to construct the Turk Plant.

In August 2008, the PUCT issued an order approving the Turk Plant with the following four conditions: (a) the capping of capital costs for the Turk Plant at the previously estimated $1.522 billion projected construction cost, excluding AFUDC, (b) capping CO2 emission costs at $28 per ton through the year 2030, (c) holding Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers and (d) providing the PUCT all updates, studies, reviews, reports and analyses as previously required under the Louisiana and Arkansas orders. In October 2008, SWEPCo appealed the PUCT’s order regarding the two cost cap restrictions. If the cost cap restrictions are upheld and construction or emissions costs exceed the restrictions, it could have a material adverse impact on future net income and cash flows. In October 2008, an intervenor filed an appeal contending that the PUCT’s grant of a conditional Certificate of Public Convenience and Necessity for the Turk Plant was not necessary to serve retail customers.

A request to stop pre-construction activities at the site was filed in federal court by Arkansas landowners. In July 2008, the federal court denied the request and the Arkansas landowners appealed the denial to the U.S. Court of Appeals.

In November 2008, SWEPCo received the air permit approval from the Arkansas Department of Environmental Quality and commenced construction. In December 2008, Arkansas landowners filed an appeal with the Arkansas Pollution Control and Ecology Commission (APCEC) which caused construction of the Turk Plant to halt until the APCEC took further action. In December 2008, SWEPCo filed a request with the APCEC to continue construction of the Turk Plant and the APCEC ruled to allow construction to continue while an appeal of the Turk Plant’s permit is heard. SWEPCo is also working with the U.S. Army Corps of Engineers for the approval of a wetlands and stream impact permit.

In January 2008 and July 2008, SWEPCo filed Certificate of Environmental Compatibility and Public Need (CECPN) applications with the APSC to construct transmission lines necessary for service from the Turk Plant. Several landowners filed for intervention status and one landowner also contended he should be permitted to re-litigate Turk Plant issues, including the need for the generation. The APSC granted their intervention but denied the request to re-litigate the Turk Plant issues. In June 2008, the landowner filed an appeal to the Arkansas State Court of Appeals requesting to re-litigate Turk Plant issues. SWEPCo responded and the appeal was dismissed. In January 2009, the APSC approved the CECPN applications.

The Arkansas Governor’s Commission on Global Warming issued its final report to the Governor in October 2008. The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas. The Commission’s final report included a recommendation that the Turk Plant employ post combustion carbon capture and storage measures as soon as it starts operating. If legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s proposal to build the Turk Plant.

If SWEPCo does not receive appropriate authorizations and permits 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 paid costs. If that occurred, SWEPCo would seek recovery of its capitalized costs including any cancellation fees and joint owner reimbursements. As of December 31, 2008, SWEPCo has capitalized approximately $510 million of expenditures (including AFUDC) and has significant contractual construction commitments for an additional $727 million. As of December 31, 2008, if the plant had been cancelled, SWEPCo would have incurred cancellation fees of $61 million. If the Turk Plant does not receive all necessary approvals on reasonable terms and SWEPCo cannot recover its capitalized costs, including any cancellation fees, it would have an adverse effect on future net income, cash flows and possibly financial condition.

Arkansas Base Rate Filing – Affecting SWEPCo

In February 2009, SWEPCo filed an application with the APSC for a base rate increase of $25 million based on a requested return on equity of 11.5%. SWEPCo also requested a separate rider to concurrently recover financing costs related to the Stall and Turk generation plants that are currently under construction. A decision is not expected until the fourth quarter of 2009 or the first quarter of 2010.

Stall Unit – Affecting SWEPCo

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

FERC Rate Matters

Regional 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 at FERC’s direction 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 the AEP East companies and ultimately their internal load retail customers to make up the short fall in revenues. 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 should not have been 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.

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, based on advice of legal counsel, 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. AEP and SECA ratepayers have engaged in settlement discussions in an effort to settle the SECA issue. However, if the ALJ’s initial decision is upheld in its entirety, it could result in a disallowance of a large portion on any unsettled SECA revenues.

Based on anticipated settlements, the AEP East companies provided reserves for net refunds for current and future SECA settlements totaling $39 million and $5 million in 2006 and 2007, respectively, applicable to a total of $220 million of SECA revenues. 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	$	12.4
CSPCo		0.9		6.9
I&M		1.0		7.3
OPCo		1.3		9.4

In December 2008, an additional settlement agreement was approved by the FERC resulting in the completion of a $2 million settlement applicable to $17 million of SECA revenue. Including this most recent settlement, AEP has completed settlements totaling $9 million applicable to $92 million of SECA revenues. The balance in the reserve for future settlements as of December 2008 was $35 million. In-process settlements total $1 million applicable to $20 million of SECA revenues. In February 2009, the FERC approved the in-process settlements resulting in the completion of a $1 million settlement application to $20 million of SECA revenues. APCo’s, CSPCo’s, I&M’s and OPCo’s reserve balance at December 31, 2008 was:

	December 31, 2008
Company	(in millions)
APCo	$	11.0
CSPCo		6.1
I&M		6.5
OPCo		8.4

If the FERC adopts the ALJ’s decision and/or AEP cannot settle all of the remaining unsettled claims within the remaining amount reserved for refund, it will have an adverse effect on future net income and cash flows. 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 available reserve of $34 million is adequate to settle the remaining $108 million of contested SECA revenues. However, management cannot predict the ultimate outcome of ongoing settlement discussions or future FERC proceedings or court appeals, if any.

The FERC PJM Regional Transmission Rate Proceeding

With the elimination of T&O rates, the expiration of SECA rates and after considerable administrative litigation at the FERC in which AEP sought to mitigate the effect of the 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 would 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 by PJM. In February 2008, AEP filed a Petition for Review of the FERC orders in this case in the United States Court of Appeals. 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, net income and cash flows.

The AEP East companies filed for and in 2006 obtained increases in their wholesale transmission rates to recover lost revenues previously applied to reduce those rates. AEP has also sought and received retail rate increases in Ohio, Virginia, West Virginia and Kentucky. As a result, AEP is now recovering approximately 80% of the lost T&O transmission revenues. The remaining 20% is being incurred by AEP until it can revise its rates in Indiana and Michigan to recover these lost revenues. AEP received net SECA transmission revenues of $128 million in 2005. I&M requested recovery of its portion of these lost revenues in its Indiana rate filing in January 2008 but does not expect to commence recovering the new rates until early 2009. Future net income and cash flows will continue to be adversely affected in Indiana and Michigan until the remaining 20% of the lost T&O 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 to be effective February 1, 2008. All of the transmission owners in PJM and MISO, with the exception of AEP and one MISO transmission owner, elected to support continuation of 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 argued 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. AEP filed a rehearing request with the FERC in March 2008. In December 2008, the FERC denied AEP’s request for rehearing. In February 2009, AEP filed an appeal in the U.S. Court of Appeals. If the court appeal is successful, earnings could benefit for a certain period of time due to regulatory lag until the AEP East companies reduce future retail revenues in their next fuel or base rate proceedings. Management is unable to predict the outcome of this case.

PJM Transmission Formula Rate Filing – Affecting APCo, CSPCo, I&M and OPCo

In July 2008, AEP filed an application with the FERC to increase its rates for wholesale transmission service within PJM by $63 million annually. The filing seeks to implement a formula rate allowing annual adjustments reflecting future changes in AEP's cost of service. The requested increase would result in a combined increase in annual revenues for the AEP East companies of approximately $9 million from nonaffiliated customers within PJM. The remaining $54 million requested would be billed to the AEP East companies but would be offset by compensation from PJM for use of AEP’s transmission facilities so that retail rates for jurisdictions other than Ohio are not affected. Retail rates for CSPCo and OPCo would be increased through the Transmission Cost Recovery Rider (TCRR) totaling approximately $10 million and $12 million, respectively. The TCRR includes a true-up mechanism so CSPCo’s and OPCo’s net income will not be adversely affected by a FERC ordered transmission rate increase. AEP requested an effective date of October 1, 2008. In September 2008, the FERC issued an order conditionally accepting AEP’s proposed formula rate, subject to a compliance filing, suspended the effective date until March 1, 2009 and established a settlement proceeding with an ALJ. In October 2008, AEP began settlement discussions and filed the required compliance filing. Management is unable to predict the outcome of this filing.

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. If approved as filed, the revised tariff will increase annual network transmission service revenues from nonaffiliated municipal and rural cooperative utilities in the AEP pricing zone of SPP 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 a hearing schedule and settlement proceedings. New rates, subject to refund, were implemented in February 2008. Multiple intervenors have protested or requested re-hearing of the order. A settlement agreement was reached. However, the final settlement documents have not been filed with FERC pending final approval by settling parties.

Allocation of Off-system Sales Margins – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

In August 2008, the OCC filed a complaint at the FERC alleging that AEP inappropriately allocated off-system sales margins between the AEP East companies and the AEP West companies and did not properly allocate off-system sales margins within the AEP West companies. The PUCT, the APSC and the Oklahoma Industrial Energy Consumers intervened in this filing. In November 2008, the FERC issued a final order concluding that AEP inappropriately deviated from off-system sales margin allocation methods in the AEP SIA and the CSW Operating Agreement for the period June 2000 through March 2006. The FERC ordered AEP to recalculate and reallocate the off-system sales margins in compliance with the AEP SIA and to have the AEP East companies issue refunds to the AEP West companies. Although the FERC determined that AEP deviated from the CSW Operating Agreement, the FERC determined the allocation methodology to be reasonable. The FERC ordered AEP to submit a revised CSW Operating Agreement for the period June 2000 to March 2006. In December 2008, AEP filed a motion for rehearing and a revised CSW Operating Agreement for the period June 2000 to March 2006. The motion for rehearing is still pending. In January 2009, AEP filed a compliance filing with the FERC and refunded approximately $250 million from the AEP East companies to the AEP West companies. The AEP West companies shared a portion of such revenues with their wholesale and retail customers during this period. In December 2008, the AEP West companies recorded a provision for refund which had a $97 million unfavorable effect on AEP net income. In January 2009, SWEPCo refunded approximately $13 million to FERC wholesale customers. In February 2009, SWEPCo filed a settlement agreement with the PUCT that provides for the Texas retail jurisdiction refund to be made through the fuel clause recovery mechanism. PSO will begin refunding approximately $54 million plus accrued interest to Oklahoma retail customers through the fuel adjustment clause over a 12-month period beginning with the March 2009 billing cycle. TCC and TNC in Texas and SWEPCo in Arkansas and Louisiana will be working with their state commissions to determine the effect the FERC order will have on retail rates. Management believes that the existing provision for refund is adequate to address existing and any future refunds that may result from the FERC order.

The table below lists the respective amounts the AEP East companies and the AEP West companies recorded in December 2008 including the net increase (decrease) to net income for the year ended December 31, 2008:

	Amounts to be (Transferred)/ Received Including Interest			Increase/ (Decrease) to Net Income
AEP East Companies	(in millions)
APCo	$	(77	)	$	(50	)
I&M		(48	)		(32	)
OPCo		(62	)		(40	)
CSPCo		(44	)		(28	)
KPCo		(19	)		(12	)
Total – AEP East Companies		(250	)		(162	)

AEP West Companies
PSO	$	72		$	12
SWEPCo		85			20
TCC		68			23
TNC		25			10
Total – AEP West Companies		250			65

Total – AEP Consolidated	$	-		$	(97	)

The table below shows the vintage year of the associated AEP SIA refunds:

	For the Twelve Months Ended December 31,
	2006 and Prior			2007			2008			Total
AEP East Companies	(in millions)
APCo	$	(66	)	$	(6	)	$	(5	)	$	(77	)
I&M		(41	)		(4	)		(3	)		(48	)
OPCo		(53	)		(5	)		(4	)		(62	)
CSPCo		(40	)		(3	)		(1	)		(44	)
KPCo		(17	)		(1	)		(1	)		(19	)
Total – AEP East Companies		(217	)		(19	)		(14	)		(250	)

AEP West Companies
PSO		62			6			4			72
SWEPCo		74			6			5			85
TCC		59			5			4			68
TNC		22			2			1			25
Total – AEP West Companies		217			19			14			250

Total – AEP Consolidated	$	-		$	-		$	-		$	-

Management cannot predict the outcome of the requested FERC rehearing proceeding or any future regulatory proceedings but believes the provision regarding future regulatory proceedings is adequate.

Transmission Equalization Agreement – Affecting APCo, CSPCo, I&M and OPCo

Certain transmission equipment placed in service in 1998 was inadvertently excluded from the AEP East companies’ TEA calculation prior to January 2009. Management believes that it is not probable that a material retroactive adjustment will result from the omission. If a retroactive adjustment is required for APCo, CSPCo, I&M and OPCo, it could have an adverse effect on future net income, cash flows and financial condition.

5.	EFFECTS OF REGULATION

Regulatory assets and liabilities are comprised of the following items:

	APCo					I&M
	December 31,					December 31,
Regulatory Assets:	2008		2007		Notes	2008		2007		Notes
	(in thousands)					(in thousands)
Current Regulatory Asset
Under-recovered Fuel Costs	$	165,906	$	-	(c) (h)	$	33,066	$	844	(a) (h)

Noncurent Regulatory Assets
SFAS 109 Regulatory Asset, Net (See Note 12)	$	424,334	$	400,580	(a) (g)	$	117,956	$	106,981	(a) (g)
SFAS 158 Regulatory Asset (See Note 8)		344,624		91,619	(a) (g)		269,087		57,517	(a) (g)
Environmental and Reliability Costs (See Note 4)		123,060		81,488	(c) (i)		-		-
Mountaineer Carbon Capture Project (See Note 4)		29,250		-	(c) (o)		-		-
SFAS 112 Regulatory Asset		21,473		16,939	(a) (g)		8,188		6,354	(a) (g)
Asset Retirement Obligation		16,630		18,666	(a) (j)		1,609		1,515	(a) (o)
Unamortized Loss on Reacquired Debt		15,367		13,541	(b) (m)		17,923		18,359	(b) (n)
Restructuring Transition Costs – Virginia		8,489		12,734	(a) (i)		-		-
Cook Nuclear Plant Refueling Outage Levelization		-		-			24,966		33,891	(a) (f)
Other		15,834		17,172	(c) (g)		15,403		21,818	(c) (g)
Total Noncurrent Regulatory Assets	$	999,061	$	652,739		$	455,132	$	246,435

Regulatory Liabilities:

Current Regulatory Liabilities
Over-recovered Fuel Costs	$	-	$	23,637	(c) (h) (p)	$	2,513	$	5,979	(b) (h) (p)

Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Asset Removal Costs	$	438,042	$	417,087	(d)	$	321,612	$	313,014	(d)
Unrealized Gain on Forward Commitments		38,345		22,274	(a) (g)		29,754		26,087	(a) (g)
Deferred State Income Tax Coal Credits		25,131		20,746	(a) (g)		-		-
Deferred Investment Tax Credits		15,075		19,284	(c) (k)		60,048		62,244	(a) (l)
Over-recovered ENEC Costs		3,824		25,110	(b) (h)		-		-
Excess ARO for Nuclear Decommissioning (See Note 10)		-		-			208,190		361,599	(e)
Other		1,091		1,055	(b) (g)		36,792		26,402	(c) (g)
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	521,508	$	505,556		$	656,396	$	789,346

(a)	Amount does not earn a return.
(b)	Amount earns a return.
(c)	A portion of this amount earns a return.
(d)	The liability for removal costs, 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 “Accounting for Asset Retirement Obligations.” This amount earns a return, accrues monthly and will be paid when the nuclear plant is decommissioned.
(f)	Amortized and recovered 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 – 2 years.
(j)	Recovery/refund period – up to 9 years.
(k)	Recovery/refund period – up to 12 years.
(l)	Recovery/refund period – up to 78 years.
(m)	Recovery/refund period – up to 28 years.
(n)	Recovery/refund period – up to 24 years.
(o)	Recovery method and timing to be determined in future proceedings.
(p)	Current Regulatory Liability – Over-recovered Fuel Costs are recorded in Other on APCo’s and I&M’s Consolidated Balance Sheets.

	CSPCo					OPCo
	December 31,					December 31,
	2008		2007		Notes	2008		2007		Notes
Regulatory Assets:	(in thousands)					(in thousands)

Noncurrent Regulatory Assets
SFAS 158 Regulatory Asset (See Note 8)	$	187,821	$	71,180	(a) (e)	$	203,326	$	68,062	(a) (e)
Customer Choice Deferrals (See Note 4)		27,377		26,608	(b) (j)		27,707		26,867	(b) (j)
Line Extension Carrying Costs		19,933		15,657	(b) (j)		11,341		7,071	(b) (j)
Hurricane Ike (See Note 4)		17,300		-	(b) (j)		10,100		-	(b) (j)
SFAS 109 Regulatory Asset, Net (See Note 12)		15,070		15,135	(a) (e)		170,357		166,011	(a) (e)
Unamortized Loss on Reacquired Debt		10,100		10,858	(b) (h)		8,497		10,116	(b) (i)
Restructuring Transition Costs – Ohio		-		49,356	(a) (f)		-		-
Other		20,756		47,089	(c) (e)		17,888		44,978	(c) (e)
Total Noncurrent Regulatory Assets	$	298,357	$	235,883		$	449,216	$	323,105

Regulatory Liabilities:

Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Asset Removal Costs	$	132,493	$	130,014	(d)	$	117,410	$	116,685	(d)
Deferred Investment Tax Credits		18,813		20,767	(a) (h)		2,917		3,859	(c) (g)
Unrealized Gain on Forward Commitments		3,487		-	(a) (f)		4,319		-	(a) (f)
Excess Deferred State Income Taxes Due to the Phase Out of the Ohio Franchise Tax (See Note 4 - Ormet)		-		8,150	(a) (f)		-		34,910	(a) (f)
Other		6,309		6,704	(c) (e)		3,142		5,267	(a) (e)
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	161,102	$	165,635		$	127,788	$	160,721

(a)	Amount does not earn a return.
(b)	Amount earns a return.
(c)	A portion of this amount earns a return.
(d)	The liability for removal costs, 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 11 years.
(h)	Recovery/refund period – up to 16 years.
(i)	Recovery/refund period – up to 30 years.
(j)	Recovery method and timing to be determined in future proceedings.

	PSO					SWEPCo
	December 31,					December 31,
	2008		2007		Notes	2008		2007		Notes
	(in thousands)					(in thousands)
Regulatory Assets:

Current Regulatory Asset
Under-recovered Fuel Costs	$	146	$	-	(b) (f) (n)	$	75,006	$	5,859	(b) (f)

Noncurrent Regulatory Assets
SFAS 158 Regulatory Asset (See Note 8)	$	176,071	$	63,077	(a) (e)	$	142,554	$	52,266	(a) (e)
Oklahoma 2007 Ice Storms (See Note 4)		61,994		-	(b) (l)		-		-
Lawton Settlement		21,101		32,303	(b) (k)		-		-
Vegetation Management		17,900		15,464	(a) (e)		-		-
Red Rock Generating Facility (See Note 4)		10,508		20,614	(b) (m)		-		-
Unamortized Loss on Reacquired Debt		6,521		8,632	(b) (g)		15,243		15,569	(b) (j)
Unrealized Loss on Forward Commitments		-		18,641	(a) (e)		-		14,465	(a) (e)
SFAS 109 Regulatory Asset, Net (See Note 12)		N/A		N/A			40,479		37,614	(b) (e)
Other		10,642		-	(c) (e)		11,898		13,703	(c) (e)
Total Noncurrent Regulatory Assets	$	304,737	$	158,731		$	210,174	$	133,617

Regulatory Liabilities:

Current Regulatory Liability
Over-recovered Fuel Costs	$	58,395	$	11,697	(b) (f)	$	5,162	$	22,879	(b) (f)

Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Asset Removal Costs	$	284,262	$	267,504	(d)	$	303,865	$	284,345	(d)
Deferred Investment Tax Credits		27,364		25,535	(a) (i)		18,894		22,859	(a) (h)
SFAS 109 Regulatory Liability, Net (See Note 12)		7,077		8,795	(b) (e)		N/A		N/A
Unrealized Gain on Forward Commitments		1,598		25,473	(a) (e)		1,575		19,565	(a) (e)
Other		3,449		11,481	(c) (e)		11,415		7,245	(c) (e)
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	323,750	$	338,788		$	335,749	$	334,014

(a)	Amount does not earn a return.
(b)	Amount earns a return.
(c)	A portion of this amount earns a return.
(d)	The liability for removal costs, 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 11 years.
(h)	Recovery/refund period – up to 9 years.
(i)	Recovery/refund period – up to 56 years.
(j)	Recovery/refund period – up to 35 years.
(k)	Recovery/refund period – 2 years.
(l)	Recovery/refund period – 5 years.
(m)	Recovery/refund period – up to 48 years.
(n)	Current Regulatory Asset – Under-recovered Fuel Costs are recorded in Prepayments and Other on PSO’s Balance Sheets.

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

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 insurance company, EIS, together with and/or in addition to various industry mutual and commercial insurance carriers.

See Note 9 for a discussion of I&M’s nuclear exposures and related insurance.

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could have a material adverse effect on net income, 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 budgeted construction expenditures by Registrant Subsidiary for 2009:

	Budgeted
	Construction
	Expenditures
Company	(in millions)
APCo		$	367.5
CSPCo			269.6
I&M			361.6
OPCo			439.4
PSO			187.7
SWEPCo			457.4

Budgeted 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 purchase fuel, materials, supplies, services and property, plant and equipment under contract as part of their normal course of business. Certain supply contracts contain penalty provisions for early termination. Management does not expect to incur penalty payments under these provisions that would materially affect net income, cash flows or financial condition.

The following table summarizes the Registrant Subsidiaries’ actual contractual commitments at December 31, 2008:

	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
Contractual Commitments – APCo	(in millions)
Fuel Purchase Contracts (a)	$	990.5	$	1,061.1	$	474.8	$	1,166.1	$	3,692.5
Energy and Capacity Purchase Contracts (b)		14.3		32.5		26.9		212.8		286.5
Construction Contracts for Capital Assets (c)		85.2		160.9		89.3		-		335.4
Total	$	1,090.0	$	1,254.5	$	591.0	$	1,378.9	$	4,314.4

	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
Contractual Commitments - CSPCo	(in millions)
Fuel Purchase Contracts (a)	$	215.7	$	405.0	$	279.3	$	400.2	$	1,300.2
Energy and Capacity Purchase Contracts (b)		1.5		4.7		0.9		-		7.1
Construction Contracts for Capital Assets (c)		35.6		43.2		40.8		-		119.6
Total	$	252.8	$	452.9	$	321.0	$	400.2	$	1,426.9

	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
Contractual Commitments – I&M	(in millions)
Fuel Purchase Contracts (a)	$	539.6	$	780.3	$	178.5	$	30.0	$	1,528.4
Energy and Capacity Purchase Contracts (b)		1.4		4.5		0.9		-		6.8
Construction Contracts for Capital Assets (c)		16.5		27.4		14.4		-		58.3
Total	$	557.5	$	812.2	$	193.8	$	30.0	$	1,593.5

	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
Contractual Commitments – OPCo	(in millions)
Fuel Purchase Contracts (a)	$	1,253.2	$	1,576.7	$	1,032.1	$	3,157.7	$	7,019.7
Energy and Capacity Purchase Contracts (b)		1.9		5.8		1.1		-		8.8
Construction Contracts for Capital Assets (c)		19.4		29.1		43.7		-		92.2
Total	$	1,274.5	$	1,611.6	$	1,076.9	$	3,157.7	$	7,120.7

	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
Contractual Commitments – PSO	(in millions)
Fuel Purchase Contracts (a)	$	244.7	$	120.4	$	42.6	$	-	$	407.7
Energy and Capacity Purchase Contracts (b)		13.1		14.5		-		-		27.6
Construction Contracts for Capital Assets (c)		10.6		51.4		73.3		-		135.3
Total	$	268.4	$	186.3	$	115.9	$	-	$	570.6

	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
Contractual Commitments – SWEPCo	(in millions)
Fuel Purchase Contracts (a)	$	379.9	$	670.4	$	523.4	$	2,607.7	$	4,181.4
Energy and Capacity Purchase Contracts (b)		18.5		9.4		9.6		54.6		92.1
Construction Contracts for Capital Assets (c)		313.4		554.8		278.7		-		1,146.9
Total	$	711.8	$	1,234.6	$	811.7	$	2,662.3	$	5,420.4

(a)	Represents contractual commitments to purchase coal, natural gas and other consumables as fuel for electric generation along with related transportation of the fuel. The longest contract extends to 2020 for APCo, 2021 for CSPCo, 2014 for I&M, 2021 for OPCo, 2013 for PSO and 2035 for SWEPCo. The contracts provide for periodic price adjustments and contain various clauses that would release the Registrant Subsidiary from its commitments under certain conditions.
(b)	Represents contractual commitments for energy and capacity purchase contracts.
(c)	Represents only capital assets that are contractual commitments.

GUARANTEES

There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

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

Certain Registrant Subsidiaries enter into standby letters of credit (LOCs) with third parties. These LOCs cover items such as insurance programs, security deposits and debt service reserves. These LOCs were issued in the ordinary course of business under the two $1.5 billion credit facilities which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $46 million following its bankruptcy.

At December 31, 2008, the maximum future payments of the LOCs were as follows:

				Borrower
	Amount		Maturity	Sublimit
Company	(in thousands)
$1.5 billion LOC:
I&M	$	1,113	March 2009		N/A
SWEPCo		4,000	December 2009		N/A

$650 million LOC:
APCo	$	126,716	June 2009	$	300,000
I&M		77,886	May 2009		230,000
OPCo		166,899	June 2009		400,000

Guarantees of Third-Party Obligations – Affecting SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation 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 46R. 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, 2008, SWEPCo has collected approximately $38 million through a rider for final mine closure costs, of which approximately $700 thousand is recorded in Other Current Liabilities and $37.6 million 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 to customers through its fuel clause.

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

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. Prior to December 31, 2008, Registrant Subsidiaries entered into sale agreements which included indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary. There are no material liabilities recorded for any indemnifications.

The 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.

Lease Obligations

Certain Registrant Subsidiaries lease certain equipment under master lease agreements. See “Master Lease Agreements” and “Railcar Lease” sections of Note 13 for disclosure of lease residual value guarantees.

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. Cases with similar allegations against CSPCo, Dayton Power and Light Company (DP&L) and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units.

In 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 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			2007
Company	(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

In October 2008, the court approved a consent decree for a settlement reached with the Sierra Club in a case involving CSPCo’s share of jointly-owned units at the Stuart Station. The Stuart units, operated by DP&L, are equipped with SCR and FGD controls. Under the terms of the settlement, the joint-owners agreed to certain emission targets related to NOx, SO2 and PM. They also agreed to make energy efficiency and renewable energy commitments that are conditioned on receiving PUCO approval for recovery of costs. The joint-owners also agreed to forfeit 5,500 SO2 allowances and provide $300 thousand to a third party organization to establish a solar water heater rebate program. Another case involving a jointly-owned Beckjord unit had a liability trial in 2008. Following the trial, the jury found no liability for claims made against the jointly-owned Beckjord unit. In December 2008, however, the court ordered a new trial in the Beckjord case.

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 pending CAA proceeding for Beckjord. Management is also unable to predict the timing of resolution of these matters. If the joint-owners do not prevail, 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 APCo, CSPCo, I&M and OPCo are unable to recover such costs or if material penalties are imposed, it would adversely affect their future net income, 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. In April 2008, the parties filed a proposed consent decree to resolve all claims in this case and in the pending appeal of the altered permit for the Welsh Plant. The consent decree requires SWEPCo to install continuous particulate emission monitors at the Welsh Plant, secure 65 MW of renewable energy capacity by 2010, fund $2 million in emission reduction, energy efficiency or environmental mitigation projects by 2012 and pay a portion of plaintiffs’ attorneys’ fees and costs. The consent decree was entered as a final order in June 2008.

In 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant. A permit alteration was issued in March 2007 that clarified or eliminated certain of the permit conditions. In June 2007, TCEQ denied a motion to overturn the permit alteration. The permit alteration was appealed to the Travis County District Court, but was resolved by entry of the consent decree in the federal citizen suit action, and dismissed with prejudice in July 2008. Notice of an administrative settlement of the TCEQ enforcement action was published in June 2008. The settlement requires SWEPCo to pay an administrative penalty of $49 thousand and to fund a supplemental environmental project in the amount of $49 thousand, and resolves all violations alleged by TCEQ. In October 2008, TCEQ approved the settlement.

In February 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 met with the Federal EPA to discuss the alleged violations in March 2008. The Federal EPA did not object to the settlement of similar alleged violations in the federal citizen suit.

Management is unable to predict the timing of any future action by the Federal EPA or the effect of such actions on net income, cash flows or financial condition.

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

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 2006. 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 which were provided in 2007. Management believes the actions are without merit and intends to defend against the claims.

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

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil & gas companies, a coal company, and other electric generating companies. The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million. The defendants filed motions to dismiss the action. The motions are pending before the court. Management believes the action is 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, 2008, APCo is named as a Potentially Responsible Party (PRP) for one site and CSPCo, I&M and OPCo are each named a PRP for two sites by the Federal EPA. There are eight 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 two sites each under state law including the I&M site discussed in the next paragraph. 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 net income.

In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M requested remediation proposals from environmental consulting firms. In May 2008, I&M issued a contract to one of the consulting firms. I&M recorded approximately $4 million of expense through December 31, 2008. As the remediation work is completed, I&M’s cost may increase. Management cannot predict the amount of additional cost, if any. At present, management’s estimates do not anticipate material cleanup costs for this site.

Management evaluates the potential liability for each Superfund site separately, but several general statements can be made regarding 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.

Clean Air Interstate Rule – Affecting I&M

Cook Plant Unit 1 Fire and Shutdown – Affecting I&M

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, likely caused by blade failure, which resulted in a fire on the electric generator. This equipment, located in the turbine building, is separate and isolated from the nuclear reactor. The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period. The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship. I&M is working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and its turbine vendor, Siemens, to evaluate the extent of the damage resulting from the incident and the costs to return the unit to service. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $330 million. Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process. Management’s current analysis indicates that with successful repairs and timely parts deliveries, Unit 1 could resume operations as early as September 2009 at reduced power. If the rotors cannot be repaired, replacement of parts will extend the outage into 2010.

The refueling outage for Cook Plant Unit 2, which continues to operate at full power, will take place as scheduled in the spring of 2009. The refueling outage scheduled for the fall of 2009 for Unit 1 is currently being evaluated. Management anticipates that the loss of capacity from Unit 1 will not affect I&M’s ability to serve customers due to the existence of sufficient generating capacity in the AEP Power Pool.

I&M maintains property insurance through NEIL with a $1 million deductible. As of December 31, 2008, I&M recorded $28 million in Prepayments and Other on its Consolidated Balance Sheet representing recoverable amounts under property insurance proceeds. I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12-week deductible period, I&M is entitled to weekly payments of $3.5 million for the first 52 weeks following the deductible period. After the initial 52 weeks of indemnity, the policy pays $2.8 million per week for up to an additional 110 weeks. I&M began receiving payments under the accidental outage policy effective December 15, 2008. If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if the unit is not returned to service in a reasonable period of time, it could have an adverse impact on net income, cash flows and financial condition.

In January 2009, I&M filed its regular semi-annual fuel filing in Indiana which determines the fuel rate for the period April 2009 through September 2009. I&M filed to provide to customers a portion of the accidental outage insurance proceeds expected during the forecast period. I&M has deferred $9 million of accidental outage insurance proceeds as of December 31, 2008 which is included in Other Current Liabilities on its Consolidated Balance Sheet.

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.

Rail Transportation Litigation – Affecting PSO

In October 2008, the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville, Texas, as co-owners of Oklaunion Plant, filed a lawsuit in United States District Court, Western District of Oklahoma against AEP alleging breach of contract and breach of fiduciary duties related to negotiations for rail transportation services for the plant. The plaintiffs allege that AEP assumed the duties of the project manager, PSO, and operated the plant for the project manager and is therefore responsible for the alleged breaches. In December 2008, the court denied AEP’s motion to dismiss the case. Management intends to vigorously defend against these allegations. Management believes a provision recorded in 2008 should be sufficient.

FERC Long-term Contracts – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

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 to the U.S. Supreme Court. In June 2008, the U.S. Supreme Court affirmed the validity of contractually-agreed rates except in cases of serious harm to the public. The U.S. Supreme Court affirmed the Ninth Circuit’s remand on two issues, market manipulation and excessive burden on consumers. The FERC initiated remand procedures and gave the parties time to attempt to settle the issues. Management believes a provision recorded in 2008 should be sufficient. 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. Management is unable to predict the outcome of these proceedings or their ultimate impact on future net income and cash flows.

7.	ACQUISITION

2008

None

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

8.	BENEFIT PLANS

APCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in AEP sponsored qualified pension plans (merged at December 31, 2008) and unfunded 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 OPEB 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 in December 2006 and recognized the obligations associated with defined benefit pension plans and OPEB plans in their balance sheets. APCo, CSPCo, I&M, OPCo, PSO and SWEPCo recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. APCo, CSPCo, I&M, OPCo, PSO and SWEPCo record a SFAS 71 regulatory asset for qualifying SFAS 158 costs of regulated operations that for ratemaking purposes are deferred for future recovery. The effect of SFAS 158 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:

							Deferred			AOCI
	Total			Regulatory			Income			Equity
	Adjustment			Asset			Tax			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 market conditions, 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, 2008, and their funded status as of December 31 for each year:

Projected Plan Obligations, Plan Assets, Funded Status as of December 31, 2008 and 2007

	Pension Plans						Other Postretirement Benefit Plans
	2008			2007			2008			2007
	(in millions)
Change in Projected Benefit Obligation
Projected Obligation at January 1	$	4,109		$	4,108		$	1,773		$	1,818
Service Cost		100			96			42			42
Interest Cost		249			235			113			104
Actuarial Loss (Gain)		139			(64	)		2			(91	)
Plan Amendments		-			18			-			-
Benefit Payments		(296	)		(284	)		(120	)		(130	)
Participant Contributions		-			-			24			22
Medicare Subsidy		-			-			9			8
Projected Obligation at December 31	$	4,301		$	4,109		$	1,843		$	1,773

Change in Fair Value of Plan Assets
Fair Value of Plan Assets at January 1	$	4,504		$	4,346		$	1,400		$	1,302
Actual Gain (Loss) on Plan Assets		(1,054	)		435			(368	)		115
Company Contributions		7			7			82			91
Participant Contributions		-			-			24			22
Benefit Payments		(296	)		(284	)		(120	)		(130	)
Fair Value of Plan Assets at December 31	$	3,161		$	4,504		$	1,018		$	1,400

Funded (Underfunded) Status at December 31	$	(1,140	)	$	395		$	(825	)	$	(373	)

AEP has significant investments in several trust funds to provide for future pension and OPEB payments. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The value of the investments in these trusts declined substantially in 2008 due to decreases in domestic and international equity markets. Although the asset values are lower, this decline has not affected the funds’ ability to make their required payments.

Amounts Recognized on AEP’s Balance Sheets as of December 31, 2008 and 2007

	Pension Plans						Other Postretirement Benefit Plans
	2008			2007			2008			2007
	(in millions)
Employee Benefits and Pension Assets – Prepaid Benefit Costs	$	-		$	482		$	-		$	-
Other Current Liabilities – Accrued Short-term Benefit Liability		(9	)		(8	)		(4	)		(4	)
Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability		(1,131	)		(79	)		(821	)		(369	)
Funded (Underfunded) Status	$	(1,140	)	$	395		$	(825	)	$	(373	)

SFAS 158 Amounts Recognized in AEP’s Accumulated Other Comprehensive Income (AOCI) as of December 31, 2008, 2007 and 2006

								Other Postretirement
	Pension Plans							Benefit Plans
	2008		2007		2006			2008		2007		2006
Components	(in millions)
Net Actuarial Loss	$	2,024	$	534	$	759		$	715	$	231	$	354
Prior Service Cost (Credit)		13		14		(5	)		3		4		4
Transition Obligation		-		-		-			70		97		124
Pretax AOCI	$	2,037	$	548	$	754		$	788	$	332	$	482

Recorded as
Regulatory Assets	$	1,660	$	453	$	582		$	502	$	204	$	293
Deferred Income Taxes		132		33		60			100		45		66
Net of Tax AOCI		245		62		112			186		83		123
Pretax AOCI	$	2,037	$	548	$	754		$	788	$	332	$	482

Components of the Change in AEP’s Plan Assets and Benefit Obligations Recognized in Pretax AOCI during the years ended December 31, 2008 and 2007 are as follows:

							Other Postretirement
	Pensions Plans						Benefit Plans
	2008			2007			2008			2007
Components	(in millions)
Actuarial Loss (Gain) During the Year	$	1,527		$	(166	)	$	492		$	(111	)
Amortization of Actuarial Loss		(37	)		(59	)		(9	)		(12	)
Prior Service Cost (Credit)		(1	)		19			-			-
Amortization of Transition Obligation		-			-			(27	)		(27	)
Total Pretax AOCI Change for the Year	$	1,489		$	(206	)	$	456		$	(150	)

Pension and Other Postretirement Plans’ Assets

The asset allocations for AEP’s pension plans at the end of 2008 and 2007, and the target allocation for 2009 by asset category, are as follows:

	Target Allocation		Percentage of Plan Assets at Year End
	2009		2008	2007
Asset Category
Equity Securities		55%	47%	57%
Real Estate		5%	6%	6%
Debt Securities		39%	42%	36%
Cash and Cash Equivalents		1%	5%	1%
Total		100%	100%	100%

The asset allocations for AEP’s OPEB plans at the end of 2008 and 2007, and target allocation for 2009 by asset category, are as follows:

	Target Allocation		Percentage of Plan Assets at Year End
	2009		2008	2007
Asset Category
Equity Securities		65%	53%	62%
Debt Securities		34%	43%	35%
Cash and Cash Equivalents		1%	4%	3%
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. AEP’s investment policies prohibit the benefit trust funds from purchasing AEP securities (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, AEP’s investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law, including ERISA.

The value of the pension plans’ assets decreased substantially to $3.2 billion at December 31, 2008 from $4.5 billion at December 31, 2007. The qualified plans paid $289 million in benefits to plan participants during 2008 (nonqualified plans paid $7 million in benefits). The value of AEP’s OPEB plans’ assets decreased substantially to $1 billion at December 31, 2008 from $1.4 billion at December 31, 2007. The OPEB plans paid $120 million in benefits to plan participants during 2008.

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,
	2008			2007
Accumulated Benefit Obligation	(in millions)
Qualified Pension Plans		$	4,119		$	3,914
Nonqualified Pension Plans			80			77
Total		$	4,199		$	3,991

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, 2008 and 2007 were as follows:

	Underfunded Pension Plans
	December 31,
	2008			2007
	(in millions)
Projected Benefit Obligation		$	4,301		$	81

Accumulated Benefit Obligation		$	4,199		$	77
Fair Value of Plan Assets			3,161			-
Underfunded Accumulated Benefit Obligation		$	1,038		$	77

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:

									Other Postretirement
	Pension Plans								Benefit Plans
	2008				2007				2008			2007
Assumptions
Discount Rate		6.00	%			6.00	%			6.10	%		6.20	%
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 2008, 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 2009 expected cash flows for AEP’s pension (qualified and nonqualified) and OPEB plans is as follows:

				Other
				Postretirement
	Pension Plans			Benefit Plans
Employer Contributions	(in millions)
Required Contributions (a)		$	9		$	4
Additional Discretionary Contributions			-			158

(a)	Contribution required to meet minimum funding requirement under ERISA plus direct payments for unfunded benefits.

The contribution to the pension plans is based on the minimum amount required by ERISA plus the amount to pay unfunded nonqualified benefits. The contribution to the OPEB plans is generally based on the amount of the OPEB 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 OPEB are as follows:

	Pension Plans			Other Postretirement Benefit Plans
	Pension			Benefit			Medicare Subsidy
	Payments			Payments			Receipts
	(in millions)
2009		$	378		$	116		$	(10	)
2010			379			126			(11	)
2011			377			136			(12	)
2012			378			143			(13	)
2013			384			151			(14	)
Years 2014 to 2018, in Total			1,920			876			(87	)

Components of Net Periodic Benefit Cost

The following table provides the components of AEP’s net periodic benefit cost for the plans for the years ended December 31, 2008, 2007 and 2006:

													Other Postretirement
	Pension Plans												Benefit Plans
	Years Ended December 31,
	2008				2007				2006				2008				2007				2006
	(in millions)
Service Cost		$	100			$	96			$	97			$	42			$	42			$	39
Interest Cost			249				235				231				113				104				102
Expected Return on Plan Assets			(336	)			(340	)			(335	)			(111	)			(104	)			(94	)
Amortization of Transition Obligation			-				-				-				27				27				27
Amortization of Prior Service Cost (Credit)			1				-				(1	)			-				-				-
Amortization of Net Actuarial Loss			37				59				79				9				12				22
Net Periodic Benefit Cost			51				50				71				80				81				96
Capitalized Portion			(16	)			(14	)			(21	)			(25	)			(25	)			(27	)
Net Periodic Benefit Cost Recognized as Expense		$	35			$	36			$	50			$	55			$	56			$	69

Estimated amounts expected to be amortized to net periodic benefit costs for AEP’s plans during 2009 are shown in the following table:

			Other
			Postretirement
	Pension Plans		Benefit Plans
Components	(in millions)
Net Actuarial Loss	$	56	$	46
Prior Service Cost		1		1
Transition Obligation		-		27
Total Estimated 2009 Pretax AOCI Amortization	$	57	$	74

Expected to be Recorded as
Regulatory Asset	$	46	$	48
Deferred Income Taxes		4		9
Net of Tax AOCI		7		17
Total	$	57	$	74

Net Benefit Cost by Registrant

The following table provides the net periodic benefit cost (credit) for the plans by Registrant Subsidiary for the years ended December 31, 2008, 2007 and 2006:

	Pension Plans											Other Postretirement Benefit Plans
	December 31,
	2008				2007				2006			2008			2007			2006
Company	(in thousands)
APCo		$	3,337			$	3,367			$	5,876		$	14,896		$	14,241		$	17,953
CSPCo			(1,398	)			(1,030	)			820			6,041			5,964			7,222
I&M			7,283				7,599				9,319			9,765			10,121			11,805
OPCo			1,277				1,451				3,307			11,357			11,207			13,582
PSO			2,033				1,697				3,912			5,581			5,722			6,352
SWEPCo			3,742				2,987				4,890			5,539			5,677			6,311

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
	2008			2007			2006			2008			2007			2006
Discount Rate		6.00	%		5.75	%		5.50	%		6.20	%		5.85	%		5.65	%
Expected Return on Plan Assets		8.00	%		8.50	%		8.50	%		8.00	%		8.00	%		8.00	%
Rate of Compensation Increase		5.90	%		5.90	%		5.90	%		N/A			N/A			N/A

N/A = Not Applicable

The expected return on plan assets for 2008 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 OPEB plans measurement purposes are shown below:

Health Care Trend Rates	2008			2007
Initial		7.0	%		7.5	%
Ultimate		5.0	%		5.0	%
Year Ultimate Reached	2012			2012

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

	1% Increase			1% Decrease
	(in millions)
Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$	20		$	(16	)

Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation			196			(163	)

American Electric Power System Retirement Savings Plans

APCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in an AEP sponsored defined contribution retirement savings plan, the American Electric Power System Retirement Savings Plan, for substantially all employees who are not members of the United Mine Workers of America (UMWA). This qualified plan offers participants an opportunity to contribute a portion of their pay, includes features under Section 401(k) of the Internal Revenue Code and provides for company matching contributions. The matching contributions to the plan was 75% of the first 6% of eligible compensation contributed by the employee in 2008. Effective January 1, 2009, the match is 100% of the first 1% of eligible employee contributions and 70% of the next 5% of contributions.

The amounts of contributions below for SWEPCo include a legacy savings plan of an acquired subsidiary.

The following table provides the cost for contributions to the retirement savings plans by the Registrant Subsidiaries for the years ended December 31, 2008, 2007 and 2006:

	Years Ended December 31,
	2008		2007		2006
Company	(in thousands)
APCo	$	8,226	$	7,787	$	7,471
CSPCo		3,678		3,442		3,224
I&M		9,501		9,075		8,764
OPCo		7,246		6,842		6,440
PSO		3,933		3,673		3,312
SWEPCo		4,943		4,623		4,284

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 2008, 2007 and 2006.

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 most recent decommissioning study was performed in 2006. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste ranges from $733 million to $1.3 billion in 2006 nondiscounted dollars. The wide range in estimated costs is caused by variables in assumptions. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amount recovered in rates was $27 million in 2008, $32 million in 2007 and $30 million in 2006. Decommissioning costs recovered from customers are deposited in external trusts. The settlement agreement in I&M’s base rate case will reduce the annual decommissioning cost recovery amount effective in 2009 to reflect the extension of the units’ operating licenses granted by the NRC.

I&M deposited an additional $4 million in 2008, 2007 and 2006 in its decommissioning trust under funding provisions approved by regulatory commissions. At December 31, 2008 and 2007, the total decommissioning trust fund balance was $959 million and $1.1 billion, respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability.

I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income, 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, 2008 and 2007, fees and related interest of $264 million and $259 million, respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $301 million and $285 million, respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.

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.

See “SFAS 157 Fair Value Measurements” section of Note 11 for disclosure of the fair value of assets within the trust.

The following is a summary of nuclear trust fund investments at December 31:

	December 31,
	2008							2007
	Estimated Fair Value		Gross Unrealized Gains		Other-Than- Temporary Impairments			Estimated Fair Value		Gross Unrealized Gains		Other-Than- Temporary Impairments
	(in millions)
Cash	$	18	$	-	$	-		$	22	$	-	$	-
Debt Securities		773		52		(3	)		823		27		(6	)
Equity Securities		469		89		(82	)		502		205		(11	)
Spent Nuclear Fuel and Decommissioning Trusts	$	1,260	$	141	$	(85	)	$	1,347	$	232	$	(17	)

Proceeds from sales of nuclear trust fund investments were $732 million, $696 million and $631 million in 2008, 2007 and 2006, respectively. Purchases of nuclear trust fund investments were $804 million, $777 million and $692 million in 2008, 2007 and 2006, respectively.

Gross realized gains from the sales of nuclear trust fund investments were $33 million, $15 million and $7 million in 2008, 2007 and 2006, respectively. Gross realized losses from the sales of nuclear trust fund investments were $7 million, $5 million and $7 million in 2008, 2007 and 2006, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at December 31, 2008 was as follows:

	Fair Value of Debt Securities
	(in millions)
Within 1 year	$	51
1 year – 5 years		172
5 years – 10 years		209
After 10 years		341
Total	$	773

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 weekly indemnity payments resulting from an insured 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 $37 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 $12.5 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $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 $117.5 million on each licensed reactor in the U.S. payable in annual installments of $17.5 million. As a result, I&M could be assessed $235 million per nuclear incident payable in annual installments of $35 million. The number of incidents for which payments could be required is not limited.

In the event of an incident of a catastrophic nature, I&M is initially covered for the first $300 million through commercially available insurance. The next level of liability coverage of up to $12.2 billion would be covered by claims made under the Price-Anderson Act. If the liability were in excess of amounts recoverable from insurance and retrospective claim payments made under the Price-Anderson Act, I&M would seek to recover those amounts from customers through rate increases. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, net income, cash flows and financial condition could be adversely affected.

10.	BUSINESS SEGMENTS

The 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.

11.	DERIVATIVES, HEDGING AND FAIR VALUE MEASUREMENTS

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 risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events 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 net income and cash flows if market prices are not consistent with management’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 in the income statements on an accrual 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 net income during the period of change. For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects net income. The Registrant Subsidiaries recognize hedge ineffectiveness in net income immediately during the period of change, except in regulated jurisdictions (APCo, I&M, PSO and the non-Texas portion of SWEPCo) 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 statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in Revenues or Expenses on the statements of income depending on the relevant facts and circumstances. However, unrealized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Fair Value Hedging Strategies

At certain times, the Registrant Subsidiaries enter into interest rate derivative transactions in order to manage existing fixed 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 2008, 2007 and 2006, 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, enters 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, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the statements of income, 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 2008, 2007 and 2006, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo designated cash flow hedge relationships using these commodities and recognized immaterial amounts in net income related to hedge ineffectiveness.

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 2008, 2007 and 2006, APCo, I&M, OPCo, PSO and SWEPCo designated interest rate derivatives as cash flow hedges and recognized immaterial amounts in net income due to hedge ineffectiveness.

At times, certain 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 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 2008, 2007 and 2006, 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 at December 31, 2008:

	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
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	)
Effective Portion of Changes in Fair Value		(423	)		1,445			1,399			965			-			(187	)
Reclasses from AOCI to Net Income		975			736			1,713			1,528			183			284
Balance at December 31, 2008	$	(5,392	)	$	1,531		$	(9,039	)	$	3,650		$	(704	)	$	(5,924	)

The following table approximates the net (loss) gain from cash flow hedges in Accumulated Other Comprehensive Income (Loss) at December 31, 2008 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
	Net Income		Exposure to
	During the		Variability of
	Next Twelve		Future Cash
	Months		Flows
Company	(in thousands)		(in months)
APCo	$	959	24
CSPCo		1,476	24
I&M		422	24
OPCo		2,096	24
PSO		(183)	-
SWEPCo		(829)	47

Credit Risk

Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. The Registrant Subsidiaries limit their credit risk by maintaining stringent credit policies whereby the Registrant Subsidiaries assess a counterparty’s creditworthiness prior to transacting with them and continue to assess their creditworthiness on an ongoing basis. The Registrant Subsidiaries employ the use of standardized master agreements which may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit, and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure is exceeded in excess of an established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, collateral agreements also provide that the failure or inability to post collateral is sufficient cause for termination and liquidation of all positions.

FAIR VALUE MEASUREMENTS

SFAS 107 Fair Value Measurements

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 Long-term Debt for the Registrant Subsidiaries at December 31, 2008 and 2007 are summarized in the following table:

	December 31,
	2008						2007
	Book Value			Fair Value			Book Value			Fair Value
Company	(in thousands)
APCo		$	3,174,512		$	2,858,278		$	2,847,299		$	2,811,067
CSPCo			1,443,594			1,410,609			1,298,224			1,290,718
I&M			1,377,914			1,308,712			1,567,427			1,527,320
OPCo			3,039,376			2,953,131			2,849,598			2,865,214
PSO			884,859			823,150			918,316			913,432
SWEPCo			1,478,149			1,358,122			1,197,217			1,190,708

SFAS 157 Fair Value Measurements

As described in Note 2, the Registrant Subsidiaries completed the adoption of SFAS 157 effective January 1, 2009. The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures. The adoption of SFAS 157 had an immaterial impact on the Registrant Subsidiaries’ financial statements. 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 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), 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, APCo, CSPCo and OPCo reduced beginning retained earnings by $440 thousand ($286 thousand, net of tax), $486 thousand ($316 thousand, net of tax) and $434 thousand ($282 thousand, net of tax), respectively, for the transition adjustment. SWEPCo’s transition adjustment was a favorable $16 thousand ($10 thousand, net of tax) adjustment to beginning retained earnings. The impact of considering AEP’s credit risk when measuring the fair value of liabilities, including derivatives, had an immaterial impact on fair value measurements upon adoption.

In accordance with SFAS 157, assets and liabilities are classified based on the inputs utilized in the fair value measurement. SFAS 157 provides definitions for two types of inputs: observable and unobservable. Observable inputs are valuation inputs that reflect the assumptions market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the reporting entity. Unobservable inputs are valuation inputs that reflect the reporting entity’s own assumptions about the assumptions market participants would use in pricing the asset or liability developed based on the best information in the circumstances.

As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 1 inputs primarily consist of exchange traded contracts, listed equities and U.S. government treasury securities that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 inputs are inputs other than quoted prices included within level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in level 1, OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market and certain non-exchange-traded debt securities.

Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.

Risk Management Contracts include exchange traded, OTC and bilaterally executed derivative contracts. Exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified within level 1. Other actively traded derivative fair values are verified using broker or dealer quotations, similar observable market transactions in either the listed or OTC markets, or valued using pricing models where significant valuation inputs are directly or indirectly observable in active markets. Derivative instruments, primarily swaps, forwards, and options that meet these characteristics are classified within level 2. Bilaterally executed agreements are derivative contracts entered into directly with third parties, and at times these instruments may be complex structured transactions that are tailored to meet the specific customer’s energy requirements. Structured transactions utilize pricing models that are widely accepted in the energy industry to measure fair value. Management uses a consistent modeling approach to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data), and other observable inputs for the asset or liability. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in level 2. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. In addition, long-dated and illiquid complex or structured transactions can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in level 3. In certain instances, the fair values of the transactions included in level 3 that use internally developed model inputs are offset partially or in full, by transactions included in level 2 where observable market data exists for the offsetting transaction.

The following table sets forth by level within the fair value hierarchy the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008

APCo
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)

Other Cash Deposits (d)	$	656	$	-	$	-	$	52		$	708

Risk Management Assets
Risk Management Contracts (a)	$	16,105	$	667,748	$	11,981	$	(597,676	)	$	98,158
Cash Flow and Fair Value Hedges (a)		-		6,634		-		(1,413	)		5,221
Dedesignated Risk Management Contracts (b)		-		-		-		12,856			12,856
Total Risk Management Assets		16,105		674,382		11,981		(586,233	)		116,235

Total Assets	$	16,761	$	674,382	$	11,981	$	(586,181	)	$	116,943

Liabilities:

Risk Management Liabilities
Risk Management Contracts (a)	$	18,808	$	628,974	$	3,972	$	(601,108	)	$	50,646
Cash Flow and Fair Value Hedges (a)		-		2,545		-		(1,413	)		1,132
DETM Assignment (c)		-		-		-		5,230			5,230
Total Risk Management Liabilities	$	18,808	$	631,519	$	3,972	$	(597,291	)	$	57,008

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008

CSPCo
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)

Other Cash Deposits (d)	$	31,129	$	-	$	-	$	1,171		$	32,300

Risk Management Assets
Risk Management Contracts (a)		9,042		366,557		6,724		(328,027	)		54,296
Cash Flow and Fair Value Hedges (a)		-		3,725		-		(794	)		2,931
Dedesignated Risk Management Contracts (b)		-		-		-		7,218			7,218
Total Risk Management Assets		9,042		370,282		6,724		(321,603	)		64,445

Total Assets	$	40,171	$	370,282	$	6,724	$	(320,432	)	$	96,745

Liabilities:

Risk Management Liabilities
Risk Management Contracts (a)	$	10,559	$	344,860	$	2,227	$	(329,954	)	$	27,692
Cash Flow and Fair Value Hedges (a)		-		1,429		-		(794	)		635
DETM Assignment (c)		-		-		-		2,937			2,937
Total Risk Management Liabilities	$	10,559	$	346,289	$	2,227	$	(327,811	)	$	31,264

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008

I&M
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)

Risk Management Assets
Risk Management Contracts (a)	$	8,750	$	357,405	$	6,508	$	(319,857	)	$	52,806
Cash Flow and Fair Value Hedges (a)		-		3,605		-		(768	)		2,837
Dedesignated Risk Management Contracts (b)		-		-		-		6,985			6,985
Total Risk Management Assets		8,750		361,010		6,508		(313,640	)		62,628

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)		-		7,818		-		11,845			19,663
Debt Securities (f)		-		771,216		-		-			771,216
Equity Securities (g)		468,654		-		-		-			468,654
Total Spent Nuclear Fuel and Decommissioning Trusts		468,654		779,034		-		11,845			1,259,533

Total Assets	$	477,404	$	1,140,044	$	6,508	$	(301,795	)	$	1,322,161

Liabilities:

Risk Management Liabilities
Risk Management Contracts (a)	$	10,219	$	336,280	$	2,156	$	(321,722	)	$	26,933
Cash Flow and Fair Value Hedges (a)		-		1,383		-		(768	)		615
DETM Assignment (c)		-		-		-		2,842			2,842
Total Risk Management Liabilities	$	10,219	$	337,663	$	2,156	$	(319,648	)	$	30,390

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008

OPCo
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)

Other Cash Deposits (e)	$	4,197	$	-	$	-	$	2,431		$	6,628

Risk Management Assets
Risk Management Contracts (a)		11,200		575,415		8,364		(515,162	)		79,817
Cash Flow and Fair Value Hedges (a)		-		4,614		-		(983	)		3,631
Dedesignated Risk Management Contracts (b)		-		-		-		8,941			8,941
Total Risk Management Assets		11,200		580,029		8,364		(507,204	)		92,389

Total Assets	$	15,397	$	580,029	$	8,364	$	(504,773	)	$	99,017

Liabilities:

Risk Management Liabilities
Risk Management Contracts (a)	$	13,080	$	550,278	$	2,801	$	(517,548	)	$	48,611
Cash Flow and Fair Value Hedges (a)		-		1,770		-		(983	)		787
DETM Assignment (c)		-		-		-		3,637			3,637
Total Risk Management Liabilities	$	13,080	$	552,048	$	2,801	$	(514,894	)	$	53,035

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008

PSO
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)

Risk Management Assets
Risk Management Contracts (a)	$	3,295	$	39,866	$	8	$	(36,422	)	$	6,747

Liabilities:

Risk Management Liabilities
Risk Management Contracts (a)	$	3,664	$	37,835	$	10	$	(36,527	)	$	4,982
DETM Assignment (c)		-		-		-		149			149
Total Risk Management Liabilities	$	3,664	$	37,835	$	10	$	(36,378	)	$	5,131

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008

SWEPCo
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in thousands)

Risk Management Assets
Risk Management Contracts (a)	$	3,883	$	61,471	$	14	$	(55,710	)	$	9,658
Cash Flow and Fair Value Hedges (a)		-		107		-		(80	)		27
Total Risk Management Assets	$	3,883	$	61,578	$	14	$	(55,790	)	$	9,685

Liabilities:

Risk Management Liabilities
Risk Management Contracts (a)	$	4,318	$	58,390	$	17	$	(55,834	)	$	6,891
Cash Flow and Fair Value Hedges (a)		-		265		-		(80	)		185
DETM Assignment (c)		-		-		-		175			175
Total Risk Management Liabilities	$	4,318	$	58,655	$	17	$	(55,739	)	$	7,251

(a)	Amounts in “Other” column primarily represent counterparty netting of risk management contracts and associated cash collateral under FSP FIN 39-1.
(b)	“Dedesignated Risk Management Contracts” are contracts that were originally MTM but were subsequently elected as normal under SFAS 133. At the time of the normal election, the MTM value was frozen and no longer fair valued. This will be amortized into revenues over the remaining life of the contract.
(c)	See “Natural Gas Contracts with DETM” section of Note 15.
(d)	Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 amounts primarily represent investments in money market funds.
(e)	Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 2 amounts primarily represent investments in money market funds.
(f)	Amounts represent corporate, municipal and treasury bonds.
(g)	Amounts represent publicly traded equity securities and equity-based mutual funds.

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

	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
Year Ended December 31, 2008	(in thousands)
Balance as of January 1, 2008	$	(697	)	$	(263	)	$	(280	)	$	(1,607	)	$	(243	)	$	(408	)
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) (a)		393			86			110			1,406			244			410
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)		-			1,724			-			2,082			-			(1	)
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		-			-			-			-			-			-
Purchases, Issuances and Settlements		-			-			-			-			-			-
Transfers in and/or out of Level 3 (b)		(931	)		(537	)		(516	)		(637	)		(1	)		(2	)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		9,244			3,487			5,038			4,319			(2	)		(2	)
Balance as of December 31, 2008	$	8,009		$	4,497		$	4,352		$	5,563		$	(2	)	$	(3	)

(a)	Included in revenues on the Statements of Income.
(b)	“Transfers in and/or out of Level 3” represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.
(c)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected on the Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities.

12.	INCOME TAXES

The details of the Registrant Subsidiaries’ income taxes before extraordinary loss as reported are as follows:

	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Year Ended December 31, 2008
Income Tax Expense (Credit):
Current	$	(97,447	)	$	111,996		$	2,575		$	72,847		$	(24,763	)	$	(25,055	)
Deferred		145,594			(303	)		57,879			42,717			67,874			62,060
Deferred Investment Tax Credits		(4,209	)		(1,954	)		(2,196	)		(942	)		(834	)		(3,964	)
Total Income Tax	$	43,938		$	109,739		$	58,258		$	114,622		$	42,277		$	33,041

	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

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, 2008
Net Income	$	122,863		$	237,130		$	131,875
Income Taxes		43,938			109,739			58,258
Pretax Income	$	166,801		$	346,869		$	190,133

Income Tax on Pretax Income at Statutory Rate (35%)	$	58,380		$	121,404		$	66,547
Increase (Decrease) in Income Tax resulting from the following items:
Depreciation		9,117			3,659			4,971
Nuclear Fuel Disposal Costs		-			-			(4,381	)
Allowance for Funds Used During Construction		(6,159	)		(1,372	)		(3,362	)
Rockport Plant Unit 2 Investment Tax Credit		-			-			397
Removal Costs		(6,596	)		(806	)		(3,839	)
Investment Tax Credits, Net		(4,209	)		(1,954	)		(2,196	)
State and Local Income Taxes		(7,583	)		964			3,077
Parent Company Loss Benefit		(29	)		(6,663	)		(1,023	)
Other		1,017			(5,493	)		(1,933	)
Total Income Taxes	$	43,938		$	109,739		$	58,258

Effective Income Tax Rate		26.3%			31.6%			30.6%

	OPCo			PSO			SWEPCo
	(in thousands)
Year Ended December 31, 2008
Net Income	$	231,123		$	78,484		$	92,754
Income Taxes		114,622			42,277			33,041
Pretax Income	$	345,745		$	120,761		$	125,795

Income Tax on Pretax Income at Statutory Rate (35%)	$	121,011		$	42,266		$	44,028
Increase (Decrease) in Income Tax resulting from the following items:
Depreciation		4,389			(502	)		502
Depletion		-			-			(3,158	)
Allowance for Funds Used During Construction		(1,555	)		(587	)		(5,114	)
Investment Tax Credits, Net		(942	)		(834	)		(3,964	)
State and Local Income Taxes		2,102			3,845			4,121
Other		(10,383	)		(1,911	)		(3,374	)
Total Income Taxes	$	114,622		$	42,277		$	33,041

Effective Income Tax Rate		33.2%			35.0%			26.3%

	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
Parent Company Loss Benefit		(370	)		(2,160	)		(925	)
Other		(1,872	)		51			1,832
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
Parent Company Loss Benefit		(1,725	)		(2,325	)		(1,250	)
Other		(3,588	)		5,175			6,926
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%

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
	(in thousands)
December 31, 2008
Deferred Tax Assets	$	432,117		$	154,855		$	490,673
Deferred Tax Liabilities		(1,550,579	)		(584,866	)		(886,764	)
Net Deferred Tax Liabilities	$	(1,118,462	)	$	(430,011	)	$	(396,091	)

Property Related Temporary Differences	$	(810,749	)	$	(406,952	)	$	(93,085	)
Amounts Due from Customers for Future Federal Income Taxes		(103,558	)		(4,789	)		(24,128	)
Deferred State Income Taxes		(142,558	)		(5,403	)		(47,922	)
Transition Regulatory Assets		(2,971	)		-			-
Deferred Income Taxes on Other Comprehensive Loss		32,429			27,475			11,681
Net Deferred Gain on Sale and Leaseback-Rockport Plant Unit 2		-			-			17,411
Accrued Nuclear Decommissioning Expense		-			-			(275,615	)
Deferred Fuel and Purchased Power		(57,102	)		-			9,585
Accrued Pensions		54,564			10,206			42,894
Nuclear Fuel		-			-			(8,738	)
Regulatory Assets		(182,831	)		(75,520	)		(94,181	)
All Other, Net		94,314			24,972			66,007
Net Deferred Tax Liabilities	$	(1,118,462	)	$	(430,011	)	$	(396,091	)

	OPCo			PSO			SWEPCo
December 31, 2008	(in thousands)
Deferred Tax Assets	$	322,089		$	82,852		$	49,950
Deferred Tax Liabilities		(1,240,032	)		(588,449	)		(454,352	)
Net Deferred Tax Liabilities	$	(917,943	)	$	(505,597	)	$	(404,402	)

Property Related Temporary Differences	$	(881,967	)	$	(426,221	)	$	(345,145	)
Amounts Due from Customers for Future Federal Income Taxes		(55,181	)		2,477			(7,739	)
Deferred State Income Taxes		(49,199	)		(53,258	)		(22,221	)
Transition Regulatory Assets		-			-			-
Deferred Income Taxes on Other Comprehensive Loss		72,014			379			17,296
Deferred Fuel and Purchased Power		-			(50	)		(29,641	)
Accrued Pensions		720			19,914			11,223
Regulatory Assets		(82,044	)		(79,869	)		(45,059	)
All Other, Net		77,714			31,031			16,884
Net Deferred Tax Liabilities	$	(917,943	)	$	(505,597	)	$	(404,402	)

	APCo			CSPCo			I&M
	(in thousands)
December 31, 2007
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	)

The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2000. The Registrant Subsidiaries have completed the exam for the years 2001 through 2003 and have issues that are being 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 net income.

The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine their tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. Management believes that previously filed tax returns have positions that may be challenged by these tax authorities. However, management does not believe that the ultimate resolution of these audits will materially impact net income. With few exceptions, the Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 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 on January 1, 2007, 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 impact of this interpretation was an unfavorable (favorable) adjustment to the 2007 opening balance of retained earnings as follows:

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

The following table shows the amounts reported for interest expense, interest income and reversal of prior period interest expense.

	2008									2007
							Prior Period									Prior Period
	Expense			Refund			Reversal			Expense			Refund			Reversal
Company	(in thousands)
APCo		$	2,365		$	5,367		$	2,635		$	1,229		$	-		$	-
CSPCo			153			3,304			3,411			1,649			-			833
I&M			179			1,371			5,650			1,704			-			-
OPCo			4,093			5,755			295			1,144			-			3,625
PSO			2,008			-			-			-			1,651			599
SWEPCo			1,340			1,585			-			-			-			1,686

The following table shows the amount accrued for the receipt of interest as of December 31, 2008 and 2007:

	Years Ended December 31,
	2008		2007
Company	(in thousands)
APCo	$	5,271	$	-
CSPCo		3,905		-
I&M		2,119		-
OPCo		4,508		-
PSO		1,004		1,371
SWEPCo		1,913		-

The following table shows the amount accrued for the payment of interest and penalties as of December 31, 2008 and 2007:

	Years Ended December 31,
	2008		2007
Company	(in thousands)
APCo	$	4,966	$	6,701
CSPCo		920		155
I&M		873		2,162
OPCo		6,320		6,175
PSO		3,349		-
SWEPCo		2,658		843

The reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Balance at January 1, 2008	$	19,741		$	19,753		$	11,317		$	51,982		$	14,105		$	6,610
Increase - Tax Positions Taken During a Prior Period		1,617			1,198			100			3,133			1,322			2,233
Decrease - Tax Positions Taken During a Prior Period		(486	)		(1,207	)		(2,976	)		(2,692	)		(6,383	)		(2,271	)
Increase - Tax Positions Taken During the Current Year		2,891			1,575			3,335			2,446			4,806			4,193
Decrease - Tax Positions Taken During the Current Year		(1,931	)		(311	)		(436	)		(835	)		(540	)		(395	)
Increase - Settlements with Taxing Authorities		906			171			745			192			-			-
Decrease - Settlements with Taxing Authorities		-			-			-			-			-			(28	)
Decrease - Lapse of the Applicable Statute of Limitations		(2,165	)		-			(270	)		(1,888	)		-			(90	)

Balance at December 31, 2008	$	20,573		$	21,179		$	11,815		$	52,338		$	13,310		$	10,252

	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
Balance at January 1, 2007	$	21,729		$	24,978		$	18,232		$	49,839		$	8,941		$	7,051
Increase - Tax Positions Taken During a Prior Period		2,074			462			130			2,544			6,535			391
Decrease - Tax Positions Taken During a Prior Period		(7,323	)		(2,494	)		(8,455	)		(5,248	)		(5,526	)		(3,425	)
Increase - Tax Positions Taken During the Current Year		3,261			1,491			1,583			6,464			2,018			3,416
Decrease – Tax Positions Taken During the Current Year		-			-			-			-			-			-
Increase - Settlements with Taxing Authorities		-			-			-			-			2,137			-
Decrease - Settlements with Taxing Authorities		-			-			(173	)		-			-			(193	)
Decrease - Lapse of the Applicable Statute of Limitations		-			(4,684	)		-			(1,617	)		-			(630	)

Balance at December 31, 2007	$	19,741		$	19,753		$	11,317		$	51,982		$	14,105		$	6,610

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 thousands)
APCo	$	5,738
CSPCo		11,954
I&M		6,283
OPCo		27,307
PSO		2,974
SWEPCo		2,205

Federal Tax Legislation – Affecting APCo, CSPCo and OPCo

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 plant, 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 allocated credits during this round of credit awards. After one of the original credit recipients surrendered its credits in the Fall of 2007, the IRS announced a supplemental credit round for the Spring of 2008. AEP filed a new application in 2008 for the West Virginia IGCC project and in July 2008 the IRS allocated the project $134 million in credits. In September 2008, AEP entered into a memorandum of understanding with the IRS concerning the requirements of claiming the credits.

Federal Tax Legislation – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

Several tax bills and other legislation with tax-related sections were enacted in 2006 and 2007, including the Pension Protection Act of 2006, the Tax Relief and Health Care Act of 2006, 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 2006 and 2007 did not materially affect the Registrant Subsidiaries’ net income, cash flows or financial condition.

The Economic Stimulus Act of 2008 was signed into law by the President in February 2008. It provided enhanced expensing provisions for certain assets placed in service in 2008 and a 50% bonus depreciation provision similar to the one in effect in 2003 through 2004 for assets placed in service in 2008. The enacted provisions did not have a material impact on net income or financial condition, but provided a material favorable cash flow benefit for each Registrant Subsidiary as follows:

Company	(in thousands)
APCo	$	38,015
CSPCo		22,511
I&M		22,808
OPCo		26,029
PSO		12,118
SWEPCo		58,566

In October 2008, the Emergency Economic Stabilization Act of 2008 (the 2008 Act) was signed into law. The 2008 Act extended several expiring tax provisions and added new energy incentive provisions. The legislation impacted the availability of research credits, accelerated depreciation of smart meters, production tax credits and energy efficient commercial building deductions. Management has evaluated the impact of the law change and the application of the law change will not materially impact net income, cash flows or financial condition.

In February 2009, the American Recovery and Reinvestment Tax Act of 2009 (the 2009 Act) was signed into law. The 2009 Act extended the bonus depreciation deduction for one year and provides for a long-term extension of the renewable production tax credit for wind energy and other properties. The 2009 Act also establishes a new investment tax credit for the manufacture of advanced energy property as well as appropriations for advanced energy research projects, carbon capture and storage and gridSMART technology. Management has evaluated the impact of the law change and the application of the law change will not materially impact net income or financial condition, but is expected to have a positive material impact on cash flows.

State Tax Legislation – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

In June 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 $42 million and $15 million, respectively, to income as an offset to power supply contract losses incurred by OPCo and CSPCo for sales to Ormet. At December 31, 2008 both regulatory liabilities were fully amortized.

The Ohio legislation also imposed 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 $4 million, $3 million and $2 million each for CSPCo and OPCo were recorded in 2008, 2007 and 2006, respectively, in Taxes Other than Income Taxes.

State Tax Legislation – Affecting PSO and SWEPCo

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 law reduced Texas income tax rates and was effective January 1, 2007. The new gross margin tax is income-based for purposes of the application of SFAS 109. 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

State Tax Legislation – Affecting APCo, CSPCo, I&M and OPCo

In July 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.

In September 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. Management has evaluated the impact of the MBT Act and the application of the MBT Act will not materially affect net income, cash flows or financial condition.

In March 2008, the Governor of West Virginia signed legislation providing for, among other things, a reduction in the West Virginia corporate income tax rate from 8.75% to 8.5% beginning in 2009. The corporate income tax rate could also be reduced to 7.75% in 2012 and 7% in 2013 contingent upon the state government achieving certain minimum levels of shortfall reserve funds. Management has evaluated the impact of the law change and the application of the law change will not materially impact net income, cash flows or financial condition.

13.

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, 2008	(in thousands)
Net Lease Expense on Operating Leases	$	18,840	$	42,330	$	96,595	$	25,876	$	6,995	$	8,519
Amortization of Capital Leases		4,820		3,329		39,697		6,369		1,550		6,926
Interest on Capital Leases		525		482		5,311		1,606		140		3,855
Total Lease Rental Costs	$	24,185	$	46,141	$	141,603	$	33,851	$	8,685	$	19,300

	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Year Ended December 31, 2007	(in thousands)
Net Lease Expense on Operating Leases	$	14,955	$	28,316	$	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	$	31,850	$	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

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, 2008	(in thousands)
Property, Plant and Equipment Under Capital Leases:
Production	$	-	$	7,104	$	15,617	$	21,220	$	-	$	14,270
Distribution		-		-		14,589		-		-		-
Other		19,651		10,147		81,839		24,748		7,051		156,867
Construction Work in Progress		-		-		-		-		-		-
Total Property, Plant and Equipment		19,651		17,251		112,045		45,968		7,051		171,137
Accumulated Amortization		10,338		10,410		30,643		21,490		3,573		59,249
Net Property, Plant and Equipment Under Capital Leases	$	9,313	$	6,841	$	81,402	$	24,478	$	3,478	$	111,888

Obligations Under Capital Leases:
Noncurrent Liability	$	5,551	$	4,055	$	37,890	$	19,603	$	2,082	$	99,151
Liability Due Within One Year		3,762		2,804		43,512		6,863		1,396		13,574
Total Obligations Under Capital Leases	$	9,313	$	6,859	$	81,402	$	26,466	$	3,478	$	112,725

	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

Future minimum lease payments consisted of the following at December 31, 2008:

	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Capital Leases	(in thousands)
2009	$	3,888	$	2,929	$	31,351	$	6,062	$	1,451	$	17,892
2010		3,153		2,367		22,295		4,974		982		13,734
2011		1,975		1,280		7,113		3,692		775		22,301
2012		121		92		10,575		1,793		69		9,100
2013		121		92		4,800		2,333		69		9,008
Later Years		401		362		24,486		17,608		282		75,000
Total Future Minimum Lease Payments		9,659		7,122		100,620		36,462		3,628		147,035
Less Estimated Interest Element		346		263		19,218		9,996		150		34,310
Estimated Present Value of Future Minimum Lease Payments	$	9,313	$	6,859	$	81,402	$	26,466	$	3,478	$	112,725

	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Noncancelable Operating Leases	(in thousands)
2009	$	20,592	$	45,091	$	100,181	$	26,707	$	5,646	$	8,554
2010		19,233		39,246		96,596		24,961		5,192		6,444
2011		43,830		51,272		119,252		54,111		17,424		30,672
2012		7,777		33,190		88,878		15,096		351		1,835
2013		7,347		32,332		87,474		15,031		259		1,643
Later Years		61,236		121,100		709,434		74,915		564		15,233
Total Future Minimum Lease Payments	$	160,015	$	322,231	$	1,201,815	$	210,821	$	29,436	$	64,381

Master Lease Agreements

Certain Registrant Subsidiaries lease certain equipment under master lease agreements. GE Capital Commercial Inc. (GE) notified management in November 2008 that they elected to terminate the Master Leasing Agreements in accordance with the termination rights specified within the contract. In 2010 and 2011, the Registrant Subsidiaries will be required to purchase all equipment under the lease and pay GE an amount equal to the unamortized value of all equipment then leased. As a result, the following unamortized values for this equipment is reflected in the Registrant Subsidiaries’ future minimum lease payments for 2011:

Company	(in thousands)
APCo	$	29,461
CSPCo		14,916
I&M		25,422
OPCo		31,832
PSO		14,095
SWEPCo		25,462

In addition, an immaterial amount for the unamortized value of the equipment is included in the Registrant Subsidiaries’ future minimum lease payments for 2010. In December 2008, management signed new master lease agreements with one-year commitment periods that include lease terms of up to 10 years. Management expects to enter into additional replacement leasing arrangements for the equipment affected by this notification prior to the termination dates of 2010 and 2011.

For equipment under the GE master lease agreements that expire prior to 2011, the lessor is guaranteed receipt of 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 Registrant Subsidiaries are 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. Under the new master lease agreements, the lessor is guaranteed receipt of up to 68% of the unamortized balance at the end of the lease term. If the actual fair market value of the leased equipment is below the unamortized balance at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair market value and unamortized balance, with the total guarantee not to exceed 68% of the unamortized balance. At December 31, 2008, the maximum potential loss by Registrant 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 thousands)
APCo		$	2,634
CSPCo			885
I&M			1,383
OPCo			2,300
PSO			1,643
SWEPCo			1,277

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, 2008 are as follows:

	AEGCo		I&M
Future Minimum Lease Payments	(in millions)
2009	$	74	$	74
2010		74		74
2011		74		74
2012		74		74
2013		74		74
Later Years		665		665
Total Future Minimum Lease Payments	$	1,035	$	1,035

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as new operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years, via the renewal options. The future minimum lease obligations are $20 million for I&M and $23 million for SWEPCo for the remaining railcars as of December 31, 2008. These obligations are included in I&M’s and SWEPCo’s future minimum lease payments schedule earlier in this note.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 84% under the current five year lease term to 77% at the end of the 20 year term of the projected fair market value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. I&M’s maximum potential loss related to the guarantee is approximately $12 million ($8 million, net of tax) and SWEPCo’s is approximately $13 million ($9 million, net of tax) assuming the fair market value of the equipment is zero at the end of the current five-year lease term. However, management believes that the fair market value would produce a sufficient sales price to avoid any loss.

The Registrant Subsidiaries have other railcar lease 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 46R, entered into a capital lease agreement with a nonaffiliated company to finance the purchase of a $53 million electric dragline for Sabine’s mining operations. In 2006, the initial capital outlay for the dragline was $26 million. Sabine incurred an additional $14 million and $13 million of transportation, assembly and upgrade costs in 2008 and 2007, respectively. The dragline was completed in August 2008. For the years ended December 31, 2008 and 2007, Sabine paid $1 million and $2 million, respectively, of interim rent prior to the completion in August 2008. Sabine began quarterly principal and interest payments on the outstanding lease obligation in November 2008. The capital lease asset was included in Property, Plant and Equipment – Other and Construction Work in Progress on SWEPCo’s December 31, 2008 and 2007 Consolidated Balance Sheets, respectively. The short-term and long-term capital lease obligations are included in Current Liabilities – Other and Noncurrent Liabilities – Deferred Credits and Other on SWEPCo’s December 31, 2008 and 2007 Consolidated Balance Sheets. The future payment obligations are included in SWEPCo’s future minimum lease payments schedule earlier in this note.

I&M Nuclear Fuel Lease

In December 2007, I&M entered into a sale-and-leaseback transaction with Citicorp Leasing, Inc. (CLI), an unrelated, unconsolidated, wholly-owned subsidiary of Citibank, N.A. to lease nuclear fuel for I&M’s Cook Plant. In December 2007, I&M sold a portion of its unamortized nuclear fuel inventory to CLI at cost for $85 million. The lease 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 $57 million are included in I&M’s future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Property, Plant and Equipment – Other and the short-term and long-term capital lease obligations are included in Current Liabilities – Other and Noncurrent Liabilities – Deferred Credits and Other, respectively, on I&M’s December 31, 2008 and 2007 Consolidated Balance Sheets. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2008 are as follows, based on estimated fuel burn:

Future Minimum Lease Payments	(in millions)
2009	$	25
2010		18
2011		4
2012		7
2013		3
Later Years		-
Total Future Minimum Lease Payments	$	57

14. FINANCING ACTIVITIES

Preferred Stock

	Par Value			Authorized Shares	Shares Outstanding at December 31, 2008	Call Price at December 31, 2008 (a)		Series	Redemption
										December 31,
										2008		2007
Company										(in thousands)
APCo	$	0	(b)	8,000,000	177,520	$	110.00	4.50%	Any time	$	17,752		$	17,752
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			5,533
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			3,148
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	2008	2007	2006
APCo	4.50%	-	114	202
I&M	4.12%	-	22	12
I&M	5.90%	-	-	-
I&M	6.25%	-	-	-
I&M	6.30%	-	-	-
I&M	6.875%	-	-	-
OPCo	4.50%	-	-	89
OPCo	5.90%	-	-	-
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, 2008 and 2007:

		Weighted Average Interest Rate at December 31,		Interest Rate Ranges at December 31,				Outstanding at December 31,
Company	Maturity	2008		2008		2007		2008			2007
Senior Unsecured Notes								(in thousands)
APCo	2008-2038		5.96%	4.40%-7.00%			3.60%-6.70%	$		2,677,461	$	2,382,747
CSPCo	2008-2035		5.81%	4.40%-6.60%			4.40%-6.60%			1,243,242		1,005,632
I&M	2008-2037		5.84%	5.05%-6.375%			5.05%-6.45%			947,350		997,061
OPCo	2008-2033		5.54%	4.3875%-6.60%			4.85%-6.60%			2,145,296		1,932,005
PSO	2009-2037		5.82%	4.70%-6.625%			4.70%-6.625%			872,199		871,956
SWEPCo	2015-2019		5.84%	4.90%-6.45%			4.90%-5.875%			1,196,534		796,647

Pollution Control Bonds (a)
APCo	2010-2037 (b)		4.26%	1.05%-7.125%			4.40%-6.05%			394,585		362,072
CSPCo	2012-2042 (b)		4.99%	4.85%-5.10%			3.80%-4.75%			100,352		192,592
I&M	2008-2025		3.06%	0.75%-5.25%			4.10%-5.00%			166,381		311,343
OPCo	2010-2037 (b)		6.54%	0.85%-13.00%			3.70%-5.80%			616,580		622,130
PSO	2014-2020		4.45%	4.45%			3.75%-4.45%			12,660		46,360
SWEPCo	2011-2019		3.96%	2.034%-4.95%			4.25%-5.50%			176,335		176,335

Notes Payable – Affiliated
APCo	2010		4.708%		4.708%	4.708%			100,000			100,000
CSPCo	2010		4.64%		4.64%	4.64%			100,000			100,000
OPCo	2015		5.25%		5.25%	5.25%			200,000			200,000
SWEPCo	2010		4.45%		4.45%	4.45%			50,000			50,000


Notes Payable – Nonaffiliated
OPCo	2008-2009	7.45%	6.27%-7.49%	6.27%-7.49%	77,500		95,463
SWEPCo	2008-2024	6.26%	4.47%-7.03%	4.47%-7.03%	55,280		61,186

Notes Payable to Trust
SWEPCo	2043	-	-	5.25%	-		113,049

Spent Nuclear Fuel Liability (c)
I&M					264,183		259,023

Other Long-term Debt
APCo	2026	13.718%	13.718%	13.718%		2,466	2,480

(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)	Certain pollution control bonds are subject to mandatory redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity and repayment purposes based on the mandatory redemption date.
(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 $301 million and $285 million related to this obligation are included in Spent Nuclear Fuel and Decommissioning Trusts on its Consolidated Balance Sheets at December 31, 2008 and 2007, respectively.

At December 31, 2008 future annual long-term debt payments are as follows:

	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
	(in thousands)
2009	$	150,017		$	-		$	-		$	77,500		$	50,000		$	4,406
2010		300,019			250,000			-			679,450			150,000			54,406
2011		250,022			-			-			-			75,000			42,604
2012		250,025			44,500			100,000			-			-			20,000
2013		70,028			306,000			-			500,000			-			-
After 2013		2,177,130			850,000			1,281,183			1,787,130			612,660			1,360,199
Total Principal Amount		3,197,241			1,450,500			1,381,183			3,044,080			887,660			1,481,615
Unamortized Discount		(22,729	)		(6,906	)		(3,269	)		(4,704	)		(2,801	)		(3,466	)
Total	$	3,174,512		$	1,443,594		$	1,377,914		$	3,039,376		$	884,859		$	1,478,149

In January 2009, I&M issued $475 million of 7.00% Senior Unsecured Notes due in 2019.

In January 2009, AEP Parent loaned I&M $25 million of 5.375% Notes Payable due in 2010.

In February 2009, PSO reissued $33.7 million of 5.25% Pollution Control Bonds due in 2014.

In the first quarter of 2008, bond insurers’ exposure in connection with developments in the subprime credit market resulted in increasing occurrences of failed auctions for tax-exempt long-term debt sold at auction rates. Consequently, the Registrant Subsidiaries chose to exit the auction-rate debt market and reduced auction-rate securities from the December 2007 balance by $1.1 billion. As of December 31, 2008, OPCo had $218 million of tax-exempt long-term debt sold at auction rates (rates range between 6.388% and 13%) that reset every 35 days. OPCo’s debt relates to a lease structure with JMG that OPCo is unable to refinance without their consent. The initial term for the JMG lease structure matures on March 31, 2010 and management is evaluating whether to terminate this facility prior to maturity. Termination of this facility requires approval from the PUCO. As of December 31, 2008, SWEPCo had $53.5 million of tax-exempt long-term debt sold at auction rates (rate of 2.034%) that reset every 35 days. 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.

The following table shows the current status of debt as of December 31, 2008 which was issued as auction-rate debt at December 31, 2007:

			Remarketed at Fixed Rates		Fixed Rate at			Remarketed at Variable Rates		Variable Rate at			Remains at Auction Rate at		Held by Trustee at
	Retired in		During		December 31,			During		December 31,			December 31,		December 31,
	2008		2008		2008			2008		2008			2008		2008
Company	(in thousands)							(in thousands)					(in thousands)
APCo	$	-	$	30,000		4.85	%	$	75,000		0.90	%	$	-	$	17,500
APCo		-		40,000		4.85	%		50,275		1.52	%		-		-
CSPCo		-		56,000		5.10	%		-		-			-		92,245
CSPCo		-		44,500		4.85	%		-		-			-		-
I&M		45,000		40,000		5.25	%		52,000		0.75	%		-		100,000
I&M		-		-		-			25,000		0.90	%		-		-
OPCo		-		-		-			65,000		0.65	%		218,000		85,000
OPCo		-		-		-			50,000		0.75	%		-		-
OPCo		-		-		-			50,000		1.00	%		-		-
PSO		-		-		-			-		-			-		33,700
SWEPCo		-		81,700		4.95	%		-		-			53,500		-
SWEPCo		-		41,135		4.50	%		-		-			-		-

Total	$	45,000	$	333,335				$	367,275				$	271,500	$	328,445

Dividend Restrictions

Under the Federal Power Act, the Registrant Subsidiaries are restricted from paying dividends out of stated capital.

Trust Preferred Securities

SWEPCo had a wholly-owned business trust that issued trust preferred securities. Effective July 1, 2003, the trust was deconsolidated due to the implementation of FIN 46R. The SWEPCo trust, which held 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, 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, are reported as Notes Payable to Trust within Long-term Debt – Nonaffiliated. Both the investment in the trust and the Junior Subordinated Debentures were retired in 2008.

Utility Money Pool – 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, 2008 and 2007 are included in Advances to/from Affiliates on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the years ended December 31, 2008 and 2007 are described in the following tables:

Year Ended December 31, 2008:

													Loans
													(Borrowings)
	Maximum			Maximum			Average			Average			to/from Utility				Authorized
	Borrowings			Loans to			Borrowings			Loans to			Money Pool as				Short-Term
	from Utility			Utility			from Utility			Utility			of December 31,				Borrowing
	Money Pool			Money Pool			Money Pool			Money Pool			2008				Limit
Company	(in thousands)
APCo		$	307,226		$	269,987		$	187,455		$	187,192		$	(194,888	)		$	600,000
CSPCo			238,172			150,358			132,219			49,899			(74,865	)			350,000
I&M			479,661			-			232,649			-			(476,036	)			500,000
OPCo			415,951			82,486			160,127			28,573			(133,887	)			600,000
PSO			149,278			59,384			69,603			29,811			(70,308	)			300,000
SWEPCo			168,495			300,525			78,074			155,598			(2,526	)			350,000

Year Ended December 31, 2007:

													Loans
													(Borrowings)
	Maximum			Maximum			Average			Average			to/from Utility				Authorized
	Borrowings			Loans to			Borrowings			Loans to			Money Pool as				Short-Term
	from Utility			Utility			from Utility			Utility			of December 31,				Borrowing
	Money Pool			Money Pool			Money Pool			Money Pool			2007				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

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:

	Years Ended December 31,
	2008		2007		2006
Maximum Interest Rate		5.47%		5.94%		5.41%
Minimum Interest Rate		2.28%		5.16%		3.32%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the years ended December 31, 2008, 2007 and 2006 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,
	2008		2007		2006		2008		2007		2006
Company
APCo		3.66%		5.38%		4.63%		3.25%		5.75%		4.93%
CSPCo		3.59%		5.46%		4.76%		3.29%		5.39%		4.37%
I&M		3.35%		5.37%		4.80%		-%		5.80%		3.84%
OPCo		3.24%		5.39%		4.74%		3.82%		5.43%		5.12%
PSO		3.32%		5.48%		5.02%		4.53%		5.31%		4.35%
SWEPCo		3.38%		5.47%		4.79%		3.12%		5.34%		4.45%

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,
	2008		2007		2006
Company	(in thousands)
APCo	$	6,076	$	6,897	$	2,656
CSPCo		2,287		2,561		284
I&M		7,903		2,399		2,772
OPCo		4,912		7,958		4,473
PSO		1,856		6,398		3,037
SWEPCo		1,480		4,414		3,234

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,
	2008		2007		2006
Company	(in thousands)
APCo	$	872	$	470	$	5,007
CSPCo		880		142		1,231
I&M		-		171		967
OPCo		79		-		63
PSO		293		881		941
SWEPCo		2,540		542		216

Short-term Debt

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

		December 31,
		2008			2007
	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%
SWEPCo	Line of Credit – Sabine (c)		7,172	1.54%		285	5.25%

(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.
(c)	Sabine Mining Company is consolidated under FIN 46R.

Credit Facilities

In April 2008, the Registrant Subsidiaries and certain other companies in the AEP System entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12 million, respectively, following its bankruptcy. Under the facilities, letters of credit may be issued. As of December 31, 2008, $372 million of letters of credit were issued by Registrant Subsidiaries under the 3-year credit agreement to support variable rate Pollution Control Bonds as follows:

	Letters of Credit Amount
	Outstanding Against
	$650 million 3-year Agreement
Company	(in millions)
APCo		$	126.7
I&M			77.9
OPCo			166.9

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 2008, AEP renewed AEP Credit’s sale of receivables agreement. The sale of receivables agreement provides a commitment of $700 million from banks and commercial paper conduits to purchase receivables from AEP Credit. This agreement will expire in October 2009. AEP intends to extend or replace the sale of receivables agreement. The previous sale of receivables agreement, which expired in October 2008 and was extended until October 2009, provided a commitment of $650 million from banks and commercial paper conduits to purchase receivables from AEP Credit. Under the previous sale of receivable agreement, the commitment increased to $700 million for the months of August and September to accommodate seasonal demand. At December 31, 2008, $650 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,
	2008			2007			2006
	($ in millions)
Proceeds from Sale of Accounts Receivable		$	7,717		$	6,970		$	6,849
Loss on Sale of Accounts Receivable		$	20		$	33		$	31
Average Variable Discount Rate			3.19%			5.39%			5.02%

	December 31,
	2008			2007
	(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts		$	118		$	71
Deferred Revenue from Servicing Accounts Receivable			1			1
Retained Interest if 10% Adverse Change in Uncollectible Accounts			116			68
Retained Interest if 20% Adverse Change in Uncollectible Accounts			114			66

Historical loss and delinquency amounts for the AEP System’s customer accounts receivable managed portfolio is as follows:

	December 31,
	2008			2007
	(in millions)
Customer Accounts Receivable Retained	$	569		$	730
Accrued Unbilled Revenues Retained		449			379
Miscellaneous Accounts Receivable Retained		90			60
Allowance for Uncollectible Accounts Retained		(42	)		(52	)
Total Net Balance Sheet Accounts Receivable		1,066			1,117
Customer Accounts Receivable Securitized		650			507
Total Accounts Receivable Managed	$	1,716		$	1,624

Net Uncollectible Accounts Written Off	$	37		$	24

Customer accounts receivable retained and securitized for the 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 $22 million and $30 million at December 31, 2008 and 2007, 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,
	2008		2007
Company	(in millions)
APCo	$	131.1	$	83.8
CSPCo		144.9		133.1
I&M		110.2		101.0
OPCo		138.1		118.5
PSO		135.9		109.3
SWEPCo		105.3		94.3

The fees paid by the Registrant Subsidiaries to AEP Credit for factoring customer accounts receivable were:

	Years Ended December 31,
	2008		2007		2006
Company	(in millions)
APCo	$	6.1	$	6.9	$	6.3
CSPCo		12.7		15.2		13.7
I&M		7.2		9.3		9.2
OPCo		10.0		12.6		11.1
PSO		10.9		14.1		16.3
SWEPCo		8.0		10.7		10.5

15. RELATED PARTY TRANSACTIONS

For other related party transactions, also see “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 14.

AEP 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 MLR, 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 AEPSC and profits/losses are allocated under the SIA to AEP Power Pool members, PSO and SWEPCo. Risk management activities involve the purchase and sale of electricity and gas under physical forward contracts at fixed and variable prices. In addition, the risk management of electricity, and to a lesser extent gas contracts, includes exchange traded futures and options and OTC options and swaps. The majority of these transactions represent physical forward contracts in the AEP System’s traditional marketing area and are typically settled by entering into offsetting contracts. In addition, AEPSC enters into transactions for the purchase and sale of electricity and gas options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System’s traditional marketing area.

CSW Operating Agreement

PSO, SWEPCo and AEPSC are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement), which was approved by the FERC. 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 SIA. 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)

The SIA provides for the integration and coordination of AEP East companies and AEP West companies zones. This includes joint dispatch of generation within the AEP System, and the distribution, between the two zones, of costs and benefits associated with the transfers of power between the two zones (including sales to third parties and risk management and trading activities). 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 a 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, allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any Registrant Subsidiary is primarily sold to customers by such Registrant Subsidiary at rates approved (other than in Ohio) by the public utility commission in the jurisdiction of sale. In Ohio, such rates are based on a statutory formula as those jurisdictions transition to the use of market rates for generation (see Note 4).

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, 2008, 2007 and 2006:

	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Related Party Revenues	(in thousands)
Year Ended December 31, 2008
Sales to AEP Power Pool	$	219,305	$	101,743	$	292,183	$	849,574	$	N/A	$	N/A
Direct Sales to East Affiliates		92,225		-		-		74,465		4,246		3,438
Direct Sales to West Affiliates		16,558		9,849		9,483		11,505		90,545		33,493
Natural Gas Contracts with AEPES		(2,029)		(1,203)		(1,085)		(689)		(467)		(552)
Other		2,676		12,560		2.160		5,613		7,278		14,463
Total Revenues	$	328,735	$	122,949	$	302,741	$	940,468	$	101,602	$	50,842

	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Related Party Revenues	(in thousands)
Year Ended December 31, 2007
Sales to AEP Power 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 AEP Power 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

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, 2008, 2007 and 2006:

	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Related Party Purchases	(in thousands)
Year Ended December 31, 2008
Purchases from AEP Power Pool	$	783,048	$	334,983	$	135,056	$	135,514	$	N/A	$	N/A
Purchases from West System Pool		N/A		N/A		N/A		N/A		-		2,867
Purchases from AEPEP		N/A		N/A		N/A		N/A		-		28
Direct Purchases from East Affiliates		-		77,296		247,931		-		25,851		25,333
Direct Purchases from West Affiliates		2,143		1,239		1,195		1,483		33,493		90,545
Gas Purchases from AEPES		-		-		-		3,689		-		-
Total Purchases	$	785,191	$	413,518	$	384,182	$	140,686	$	59,344	$	118,773

	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Related Party Purchases	(in thousands)
Year Ended December 31, 2007
Purchases from AEP Power 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		-		-
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 AEP Power 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		-		-
Total Purchases	$	492,756	$	365,510	$	343,156	$	113,651	$	69,406	$	74,458

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 East companies and AEP West companies zones. Similar to the SIA, the System Transmission Integration Agreement functions as an umbrella agreement in addition to the Transmission 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 MLR.

The following table shows the net charges (credits) allocated among the Registrant Subsidiaries, party to the TEA, during the years ended December 31, 2008, 2007 and 2006:

	Years Ended December 31,
	2008				2007				2006
Company	(in thousands)
APCo		$	(29,146	)		$	(24,900	)		$	(16,000	)
CSPCo			55,273				51,900				46,200
I&M			(37,398	)			(34,600	)			(37,300	)
OPCo			13,294				8,500				9,100

The net charges (credits) shown above are recorded in Other Operation on the respective 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. The allocations have been governed by the FERC-approved OATT for the SPP (with respect to PSO and SWEPCo).

The following table shows the net charges (credits) allocated among parties to the TCA pursuant to the SPP OATT protocols as described above during the years ended December 31, 2008, 2007 and 2006:

	Years Ended December 31,
	2008				2007				2006
Company	(in thousands)
PSO		$	8,200			$	500			$	1,800
SWEPCo			(8,200	)			(500	)			(1,900	)

The net charges (credits) shown above are recorded in the Other Operation on PSO’s and SWEPCo’s respective income statements.

Assignment from SWEPCo, TCC and TNC to AEPEP

On March 1, 2008, SWEPCo, TCC and TNC assigned a 20-year Purchase Power Agreement (PPA) to AEPEP. In addition to the PPA assignment, an intercompany agreement was executed between AEPEP and SWEPCo to provide SWEPCo with future margins related to its share. The PPA and intercompany agreements are effective through 2019. SWEPCo recorded revenue of $903 thousand from AEPEP in Sales to AEP Affiliates on its 2008 Consolidated Statement of Income.

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 in December 2009.

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’s and SWEPCo’s balance sheets and will be presented on a net basis in Sales to AEP Affiliates on PSO’s and SWEPCo’s respective income statements.

The following tables indicate the sales to AEPEP and the amounts reclassified from third party to affiliate:

	Year Ended December 31, 2008
				Third Party Amounts				Net Amount
	Net Settlement			Reclassified to				Included in Sales
	with AEPEP			Affiliate				to AEP Affiliates
Company	(in thousands)
PSO		$	79,445		$	(76,000	)		$	3,445
SWEPCo			84,095			(80,032	)			4,063

	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 respective balance sheets associated with these contracts:

	December 31, 2008				December 31, 2007
	PSO		SWEPCo		PSO		SWEPCo
Current	(in thousands)
Risk Management Assets	$	-	$	-	$	21,174	$	24,973
Risk Management Liabilities		1,631		1,923		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.

Equipment Transferred from AEP Pro Serv, Inc. to SWEPCo

During the fourth quarter of 2008, AEP Pro Serv, Inc. transferred $37 million of refurbished turbines and related equipment to SWEPCo for installation at its Stall Unit at its Arsenal Hill Plant. SWEPCo recorded the transfer in CWIP on its 2008 Consolidated Balance Sheet.

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. The following table represents the Registrant Subsidiaries’ risk management liabilities related to DETM at December 31:

	December 31,
	2008		2007
Company	(in thousands)
APCo	$	(5,230)	$	(9,439)
CSPCo		(2,937)		(5,470)
I&M		(2,842)		(5,255)
OPCo		(3,637)		(6,373)
PSO		(149)		(331)
SWEPCo		(175)		(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,
	2008			2007			2006
Company	(in thousands)
APCo		$	1,204		$	4,377		$	1,660
CSPCo			707			2,483			1,016
I&M			681			2,553			1,065
OPCo			840			3,106			1,257

These purchases are reflected in Purchased Electricity for Resale on the respective 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 Generating Station 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.

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) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances.

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 the Amos Plant and the 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 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 statements. 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 2008, 2007 and 2006, 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,
	2008			2007			2006
Company	(in thousands)
APCo		$	1,000		$	53		$	899
I&M			15,368			18,364			15,869

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 2008, 2007 and 2006. OPCo recorded revenue as Other – Nonaffiliated on its Consolidated Statements of Income in the amounts of $59 thousand, $290 thousand and $172 thousand in 2008, 2007 and 2006, respectively. OVEC is 43.47% owned by AEP (includes CSPCo’s 4.3% ownership of OVEC).

In 2008, 2007 and 2006, 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,
	2008			2007			2006
Company	(in thousands)
APCo		$	39		$	8		$	278
I&M			2,720			2,490			2,491
PSO			1,160			307			905
SWEPCo			434			1,479			433

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 $2.5 million and $2.2 million for railcar services provided in 2008 and 2007, respectively, and billed PSO $553 thousand and $755 thousand in 2008 and 2007, respectively. These billings, for SWEPCo, and costs, for I&M and PSO, are recorded in Fuel on the 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 affiliated companies 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,
	2008		2007		2006
Company	(in millions)
I&M – Revenues	$	103.4	$	49.1	$	47.9
AEGCo – Expense		17.0		9.2		14.9
APCo – Expense		27.1		16.6		14.5
KPCo – Expense		-		0.1		0.1
OPCo – Expense		40.9		7.1		2.1
AEP River Operations LLC – Expense (Nonutility Subsidiary of AEP)		18.4		16.1		16.3

In addition, I&M provided transloading services to OVEC. I&M recorded revenue of $3 thousand, $89 thousand and $121 thousand for 2008, 2007 and 2006, respectively, in Other – Nonaffiliated on its Consolidated Statements of Income.

Services Provided by AEP River Operations LLC (formerly known as MEMCO)

AEP River Operations LLC provides services for barge towing, chartering and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation expense. For the years ended December 31, 2008, 2007 and 2006, I&M recorded expenses of $37 million, $18 million and $16 million, respectively, for these activities.

Central Machine Shop

APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers on its balance sheet the cost of performing the services, then transfers the cost to the affiliate for reimbursement. The AEP 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,
	2008		2007		2006
Company	(in thousands)
AEGCo	$	138	$	-	$	-
CSPCo		682		505		617
I&M		2,714		2,464		1,826
KPCo		1,183		167		181
OPCo		1,944		1,999		2,831
PSO		1,225		317		801
SWEPCo		288		44		2

In addition, APCo billed OVEC and IKEC a total of $303 thousand, $898 thousand and $951 thousand for 2008, 2007 and 2006, respectively.

Affiliate Railcar Agreement

Certain AEP subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available. The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar. The AEP subsidiaries 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 tables show the net effect of the railcar agreement on the AEP subsidiaries’ respective balance sheets:

	Year Ended December 31, 2008
	Billing Company
	AEP Transportation (a)			APCo		I&M		OPCo		PSO		SWEPCo		Total
Billed Company	(in thousands)
APCo	$	2		$	-	$	110	$	1,754	$	12	$	30	$	1,908
CSPCo		-			-		-		-		-		1		1
I&M		6			523		-		1,105		328		1,155		3,117
KPCo		-			274		-		332		-		-		606
OPCo		1			1,176		376		-		13		60		1,626
PSO		10			5		1,316		177		-		476		1,984
SWEPCo		(5	)		-		2,543		874		212		-		3,624
Total	$	14		$	1,978	$	4,345	$	4,242	$	565	$	1,722	$	12,866

	Year Ended December 31, 2007
	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.

OPCo Indemnification Agreement with AEP Resources

OPCo had an indemnification agreement with AEP Resources, Inc. (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, AEPR paid OPCo $14.9 million which is reported in OPCo’s Other Operation on its Consolidated Statement 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 2008 or 2007.

Purchased Power from OVEC

The amounts of power purchased by the Registrant Subsidiaries from OVEC, which is 43.47% owned by AEP (includes CSPCo’s 4.3% ownership of OVEC), for the years ended December 31, 2008, 2007 and 2006 were:

	Years Ended December 31,
	2008			2007			2006
Company	(in thousands)
APCo		$	94,874		$	81,612		$	82,422
CSPCo			26,853			23,102			22,821
I&M			47,465			40,827			38,961
OPCo			93,661			80,561			78,579

The amounts shown above are recoverable from customers and are included in Purchased Electricity for Resale on the respective income statements.

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 on the respective income statements. The agreement expired in May 2008 and subsequently ended in December 2008. The following table shows the amounts recorded for the years ended December 31, 2008, 2007 and 2006:

	Years Ended December 31,
	2008			2007			2006
Company	(in thousands)
APCo		$	17,795		$	9,830		$	11,284
CSPCo			10,381			5,553			6,915
I&M			9,999			5,530			7,189
OPCo			12,359			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 was 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
Company	(in thousands)
PSO		$	13,955		$	53,354
SWEPCo			16,443			62,794

The amounts shown above are recorded in Purchased Electricity for Resale on PSO’s and SWEPCo’s respective income statements.

Sales and Purchases of Property

Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more for the years ended December 31, 2008, 2007 and 2006 as shown in the following table:

	Year Ended December 31,
	2008
Companies	(in thousands)
APCo to CSPCo	$	858
APCo to I&M		2,720
APCo to OPCo		615
CSPCo to PSO		180
I&M to APCo		653
I&M to KPCo		444
I&M to OPCo		1,992
I&M to PSO		666
OPCo to I&M		1,800
OPCo to PSO		259
PSO to I&M		646
TCC to APCo		220

	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

In addition, certain AEP subsidiaries had aggregate affiliated sales and purchases of meters and transformers for the years ended December 31, 2008, 2007 and 2006 as shown in the following table:

Year Ended December 31, 2008

	Purchaser
	APCo		CSPCo		I&M		KGPCo		KPCo		OPCo		PSO		SWEPCo		TCC		TNC		WPCo		TOTAL
Seller	(in thousands)
APCo	$	-	$	27	$	24	$	386	$	112	$	206	$	9	$	164	$	73	$	-	$	-	$	1,001
CSPCo		18		-		15		-		-		580		2		-		-		-		5		620
I&M		2		86		-		-		15		270		25		2		5		-		22		427
KGPCo		253		-		-		-		-		-		-		-		-		-		-		253
KPCo		354		11		16		6		-		121		-		2		33		-		-		543
OPCo		249		3,446		613		-		95		-		2		16		14		11		562		5,008
PSO		1		98		-		-		-		4		-		124		-		25		-		252
SWEPCo		-		-		-		-		-		3		655		-		13		9		-		680
TCC		1		-		-		-		-		1		9		535		-		494		-		1,040
TNC		-		-		-		-		-		9		28		26		334		-		-		397
WPCo		-		6		1		-		-		152		-		-		-		-		-		159
Total	$	878	$	3,674	$	669	$	392	$	222	$	1,346	$	730	$	869	$	472	$	539	$	589	$	10,380

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

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.

Intercompany Billings

The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable 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.

Variable Interest Entities

FIN 46R is a consolidation model that considers risk absorption of a variable interest entity (VIE), also referred to as variability. Entities are required to consolidate a VIE when it is determined that they are the primary beneficiary of that VIE, as defined by FIN 46R. In determining whether they are the primary beneficiary of a VIE, each Registrant Subsidiary considers factors such as equity at risk, the amount of variability of the VIE the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE and other factors. Management believes that significant assumptions and judgments were applied consistently and that there are no other reasonable judgments or assumptions that would result in a different conclusion. In addition, the Registrant Subsidiaries have not provided financial or other support that was not previously contractually required to any VIE.

SWEPCo is the primary beneficiary of Sabine and DHLC. OPCo is the primary beneficiary of JMG. APCo, CSPCo, I&M, OPCo, PSO and SWEPCo each hold a significant variable interest in AEPSC. I&M and CSPCo each hold a significant variable interest in AEGCo.

Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee which is included in Fuel and Other Consumables Used for Electric Generation on SWEPCo’s Consolidated Statements of Income. Based on these facts, management has concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2008 and 2007 were $110 million and $95 million, respectively. See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s Consolidated Balance Sheets.

DHLC is a wholly-owned subsidiary of SWEPCo. DHLC is a mining operator who sells 50% of the lignite produced to SWEPCo and 50% to Cleco Corporation, a nonaffiliated company. SWEPCo and Cleco Corporation share half of the executive board seats, with equal voting rights and each entity guarantees a 50% share of DHLC’s debt. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. Based on the structure and equity ownership, management has concluded that SWEPCo is the primary beneficiary and is required to consolidate DHLC. SWEPCo’s total billings from DHLC for the years ended December 31, 2008 and 2007 were $44 million and $35 million, respectively. These billings are included in Fuel and Other Consumables Used for Electric Generation on SWEPCo’s Consolidated Statements of Income. See the tables below for the classification of DHLC assets and liabilities on SWEPCo’s Consolidated Balance Sheets.

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

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

VARIABLE INTEREST ENTITIES

December 31, 2008

(in millions)

	Sabine		DHLC
ASSETS
Current Assets	$	33	$	22
Net Property, Plant and Equipment		117		33
Other Noncurrent Assets		24		11
Total Assets	$	174	$	66

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities	$	32	$	18
Noncurrent Liabilities		142		44
Common Shareholders’ Equity		-		4
Total Liabilities and Shareholder’s Equity	$	174	$	66

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

VARIABLE INTEREST ENTITIES

December 31, 2007

(in millions)

	Sabine		DHLC
ASSETS
Current Assets	$	24	$	29
Net Property, Plant and Equipment		97		41
Other Noncurrent Assets		25		13
Total Assets	$	146	$	83

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities	$	14	$	26
Noncurrent Liabilities		130		54
Common Shareholder’s Equity		2		3
Total Liabilities and Shareholders’ Equity	$	146	$	83

OPCo has a lease agreement with JMG to finance OPCo’s FGD system installed on OPCo’s Gavin Plant. The PUCO approved the original lease agreement between OPCo and JMG. JMG has a capital structure of substantially all debt from pollution control bonds and other debt. JMG owns and leases the FGD to OPCo. JMG is considered a single-lessee leasing arrangement with only one asset. OPCo’s lease payments are the only form of repayment associated with JMG’s debt obligations even though OPCo does not guarantee JMG’s debt. The creditors of JMG have no recourse to any AEP entity other than OPCo for the lease payment. OPCo does not have any ownership interest in JMG. Based on the structure of the entity, management has concluded that OPCo is the primary beneficiary and is required to consolidate JMG. OPCo’s total billings from JMG for the years ended December 31, 2008 and 2007 were $57 million and $46 million, respectively. See the tables below for the classification of JMG’s assets and liabilities on OPCo’s Consolidated Balance Sheets.

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

OHIO POWER COMPANY CONSOLIDATED

VARIABLE INTEREST ENTITY

December 31, 2008

(in millions)

	JMG
ASSETS
Current Assets	$	11
Net Property, Plant and Equipment		423
Other Noncurrent Assets		1
Total Assets	$	435

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities	$	161
Noncurrent Liabilities		257
Common Shareholder’s Equity		17
Total Liabilities and Shareholders’ Equity	$	435

OHIO POWER COMPANY CONSOLIDATED

VARIABLE INTEREST ENTITY

December 31, 2007

(in millions)

	JMG
ASSETS
Current Assets	$	5
Net Property, Plant and Equipment		443
Other Noncurrent Assets		1
Total Assets	$	449

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities	$	98
Noncurrent Liabilities		335
Common Shareholder’s Equity		16
Total Liabilities and Shareholders’ Equity	$	449

AEPSC provides certain managerial and professional services to AEP’s subsidiaries. AEP is the sole equity owner of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. No AEP subsidiary has provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations by cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP’s subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. All Registrant Subsidiaries are considered to have a significant interest in the variability in AEPSC due to their activity in AEPSC’s cost reimbursement structure. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

Total AEPSC billings to the Registrant Subsidiaries were as follows:

	Years Ended December 31,
	2008		2007
Company	(in millions)
APCo	$	250	$	232
CSPCo		136		114
I&M		148		138
OPCo		208		189
PSO		117		105
SWEPCo		139		119

The carrying amount and classification of variable interest in AEPSC’s accounts payable as of December 31, 2008 and 2007 are as follows:

	2008				2007
	As Reported in the Balance Sheet		Maximum Exposure		As Reported in the Balance Sheet		Maximum Exposure
	(in millions)
APCo	$	27	$	27	$	31	$	31
CSPCo		15		15		17		17
I&M		14		14		20		20
OPCo		21		21		24		24
PSO		10		10		16		16
SWEPCo		14		14		16		16

AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant Unit 1, leases a 50% interest in Rockport Plant Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. In May 2007, AEGCo began leasing the Lawrenceburg Generating Station to CSPCo. AEP guarantees all the debt obligations of AEGCo. I&M and CSPCo are considered to have a significant interest in AEGCo due to these transactions. I&M and CSPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations. Due to the nature of the AEP Power Pool, there is a sharing of the cost of Rockport and Lawrenceburg Plants such that no member of the AEP Power Pool is the primary beneficiary of AEGCo’s Rockport or Lawrenceburg Plants. In the event AEGCo would require financing or other support outside the billings to I&M, CSPCo and KPCo, this financing would be provided by AEP. See “Rockport Lease” section of Note 13 for additional information regarding AEGCo’s lease.

Total billings from AEGCo are as follows:

	Year Ended December 31,
	2008			2007
	(in millions)
CSPCo		$	114		$	84
I&M			248			207

The carrying amount and classification of variable interest in AEGCo’s accounts payable as of December 31, 2008 and 2007 are as follows:

	2008						2007
	As Reported in the Consolidated Balance Sheet			Maximum Exposure			As Reported in the Consolidated Balance Sheet			Maximum Exposure
	(in millions)
CSPCo		$	5		$	5		$	7		$	7
I&M			23			23			21			21

16.	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

2008	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		$	3,708,850		$	1,592,837			2.3	%		40-121		$	-		$	-		-		-
Transmission			1,754,192			420,213			1.6	%		25-87			-			-		-		-
Distribution			2,499,974			511,242			3.2	%		11-52			-			-		-		-
CWIP			1,106,032			(18,514	)	N.M.			N.M.				-			-		-		-
Other			325,147			157,491			7.5	%		24-55			33,726			12,515	N.M.		N.M.
Total		$	9,394,195		$	2,663,269								$	33,726		$	12,515

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		$	-		$	-		-		-
Transmission			1,675,081			408,126			1.3	%		25-87			-			-		-		-
Distribution			2,372,687			502,503			3.1	%		11-52			-			-		-		-
CWIP			713,063			(15,104	)	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	Annual Composite Depreciation Rate			Depreciable Life Ranges		Annual Composite Depreciation Rate			Depreciable Life Ranges
				(in years)					(in years)
Production		2.6	%		40-121		2.6	%		40-121
Transmission		1.8	%		25-87		-			-
Distribution		3.3	%		11-52		-			-
Other		7.7	%		24-55	N.M.			N.M.

N.M. = Not Meaningful

CSPCo

2008	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		$	-		$	-			-			-		$	2,326,056		$	900,101		2.7	%		40-59
Transmission			574,018			219,121			2.3	%		33-50			-			-		-			-
Distribution			1,625,000			561,828			3.5	%		12-56			-			-		-			-
CWIP			152,889			(5,706	)	N.M.			N.M.				242,029			97	N.M.			N.M.
Other			188,485			103,390			8.7	%	N.M.				22,603			3,035	N.M.			N.M.
Total		$	2,540,392		$	878,633								$	2,590,688		$	903,233

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		$	-		$	-			-			-		$	2,072,564		$	861,213		3.0	%		40-59
Transmission			510,107			209,369			2.3	%		33-50			-			-		-			-
Distribution			1,552,999			536,408			3.6	%		12-56			-			-		-			-
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	Annual Composite Depreciation Rate			Depreciable Life Ranges		Annual Composite Depreciation Rate			Depreciable Life Ranges
				(in years)					(in years)
Production	N.M.			N.M.			3.1	%		40-59
Transmission		2.3	%		33-50		-			-
Distribution		3.5	%		12-56		-			-
Other		8.7	%	N.M.		N.M.			N.M.

N.M. = Not Meaningful

OPCo

2008	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		$	-		$	-			-			-		$	6,025,277		$	2,125,239		2.7	%		35-61
Transmission			1,111,637			453,235			2.3	%		27-70			-			-		-			-
Distribution			1,472,906			392,468			3.9	%		12-55			-			-		-			-
CWIP			121,412			(4,213	)	N.M.			N.M.				665,768			2,276	N.M.			N.M.
Other			278,134			141,299			8.5	%	N.M.				113,728			12,685	N.M.			N.M
Total		$	2,984,089		$	982,789								$	6,804,773		$	2,140,200

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		$	-		$	-			-			-		$	5,641,537		$	2,008,046		2.6	%		35-61
Transmission			1,068,387			439,542			2.3	%		27-70			-			-		-			-
Distribution			1,394,988			374,421			3.9	%		12-55			-			-		-			-
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	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		-			-
Distribution		3.9	%		12-55		-			-
Other		9.2	%	N.M.		N.M.			N.M.

N.M. = Not Meaningful

SWEPCo

2008	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		$	1,187,449		$	684,712			2.9	%		19-68		$	621,033		$	358,103		2.9	%		30-37
Transmission			786,731			241,296			2.7	%		44-65			-			-		-			-
Distribution			1,400,952			385,906			3.5	%		19-56			-			-		-			-
CWIP			586,863			(7,321	)	N.M.			N.M.				282,240			-	N.M.			N.M.
Other			395,357			180,478			7.1	%		7-45			315,903			170,980	N.M.			N.M.
Total		$	4,357,352		$	1,485,071								$	1,219,176		$	529,083

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			-			-		-			-
Distribution			1,312,746			374,084			3.5	%		16-65			-			-		-			-
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	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		-			-
Distribution		3.1	%		16-65		-			-
Other		8.6	%	N.M.		N.M.			N.M.

N.M. = Not Meaningful

	I&M												PSO

2008	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		$	3,534,188		$	2,024,445			1.6	%		59-132		$	1,266,716		$	624,986			1.7	%		9-70
Transmission			1,115,762			401,198			1.4	%		46-75			622,665			157,397			1.9	%		40-75
Distribution			1,297,482			360,257			2.4	%		14-70			1,468,481			267,903			2.9	%		27-65
CWIP			249,020			(3,827	)	N.M.			N.M.				85,252			(5,743	)	N.M.			N.M.
Other			550,952			128,565			11.3	%	N.M.				244,436			147,587			6.8	%		5-35
Total		$	6,747,404		$	2,910,638								$	3,687,550		$	1,192,130

	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		$	152,335		$	108,568		N.M.			N.M.			$	4,461		$	-		N.M.			N.M.

	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.

N.M. = Not Meaningful

	I&M					PSO

2006	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		3.6	%		40-119		2.7	%		30-57
Transmission		1.9	%		30-65		2.0	%		40-75
Distribution		4.0	%		12-65		3.0	%		25-65
Other		10.2	%	N.M.			6.7	%	N.M.

	Nonregulated		Nonregulated

Functional Class of Property	Annual Composite Depreciation Rate	Depreciable Life Ranges	Annual Composite Depreciation Rate	Depreciable Life Ranges
		(in years)		(in years)
Other	N.M.	N.M.	N.M.	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 $0.26 per ton in 2008 and $0.66 per ton in 2007 and 2006.

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.

Asset Retirement Obligations (ARO)

The Registrant Subsidiaries record ARO in accordance with SFAS 143 “Accounting for Asset Retirement Obligations” and FIN 47 “Accounting for Conditional Asset Retirement Obligations” for the retirement of certain ash ponds and coal mining facilities as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets, as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected.

As of December 31, 2008 and 2007, I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $891 million and $846 million, respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s Consolidated Balance Sheets. As of December 31, 2008 and 2007, the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $959 million and $1.1 billion, respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s Consolidated Balance Sheets.

The following is a reconciliation of the 2008 and 2007 aggregate carrying amounts of ARO by Registrant Subsidiary:

	ARO at													Revisions in				ARO at
	December 31,			Accretion			Liabilities			Liabilities				Cash Flow				December 31,
	2007			Expense			Incurred			Settled				Estimates				2008
Company	(in thousands)
APCo (a)(d)		$	40,019		$	2,887		$	690		$	(3,434	)		$	11,717			$	51,879
CSPCo (a)(d)			21,658			1,472			-			(2,762	)			(2,940	)			17,428
I&M (a)(b)(d)			852,646			45,587			6,120			(548	)			(885	)			902,920
OPCo (a)(d)			77,354			5,786			212			(4,148	)			10,112				89,316
PSO (d)			6,521			408			4,264			(369	)			4,002				14,826
SWEPCo (a)(c)(d)(e)			50,262			2,695			9,522			(14,416	)			7,023				55,086

	ARO at													Revisions in			ARO at
	December 31,			Accretion			Liabilities			Liabilities				Cash Flow			December 31,
	2006			Expense			Incurred			Settled				Estimates			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

(a)	Includes ARO related to ash ponds.
(b)	Includes ARO related to nuclear decommissioning costs for the Cook Plant ($891 million and $846 million at December 31, 2008 and 2007, 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 $1.7 million and $434 thousand, at December 31, 2008 and 2007, 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’ income statements for 2008, 2007 and 2006 were as follows:

	Years Ended December 31,
	2008		2007		2006
Company	(in thousands)
APCo	$	8,938	$	7,337	$	12,014
CSPCo		3,364		3,036		1,865
I&M		965		4,522		7,937
OPCo		3,073		2,311		2,556
PSO		1,822		1,367		715
SWEPCo		14,908		10,243		1,302

The amounts of allowance for borrowed funds used during construction or interest capitalized included in Interest Expense on the Registrant Subsidiaries’ income statements for 2008, 2007 and 2006 were as follows:

	Years Ended December 31,
	2008		2007		2006
Company	(in thousands)
APCo	$	9,040	$	6,962	$	17,668
CSPCo		2,677		7,275		5,955
I&M		4,609		5,315		7,465
OPCo		25,269		36,641		42,733
PSO		2,174		5,156		1,491
SWEPCo		19,800		9,795		2,208

Jointly-owned Electric Utility Plants

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, 2008
	Fuel Type	Percent of Ownership	Utility Plant in Service		Construction Work in Progress (i)		Accumulated Depreciation
Company			(in thousands)
CSPCo
W.C. Beckjord Generating Station (Unit No. 6) (a)	Coal	12.5%	$	18,173	$	1,780	$	8,129
Conesville Generating Station (Unit No. 4) (b)	Coal	43.5%		85,587		172,619		51,110
J.M. Stuart Generating Station (c)	Coal	26.0%		477,677		23,782		143,548
Wm. H. Zimmer Generating Station (a)	Coal	25.4%		762,353		3,987		344,259
Transmission	N/A	(d)		69,789		6		45,613
Total			$	1,413,579	$	202,174	$	592,659

PSO
Oklaunion Generating Station (Unit No. 1) (e)	Coal	15.6%	$	88,034	$	1,739	$	56,337

SWEPCo
Dolet Hills Generating Station (Unit No. 1) (f)	Lignite	40.2%	$	255,149	$	676	$	182,317
Flint Creek Generating Station (Unit No. 1) (g)	Coal	50.0%		102,777		9,778		62,046
Pirkey Generating Station (Unit No. 1) (g)	Lignite	85.9%		491,071		8,578		336,052
Turk Generating Plant (h)	Coal	73.33%		-		510,279		-
Total			$	848,997	$	529,311	$	580,415

			Company’s Share at December 31, 2007
	Fuel Type	Percent of Ownership	Utility Plant in Service		Construction Work in Progress (i)		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
Turk Generating Plant (h)	Coal	73.33%		-		272,089		-
Total			$	825,299	$	290,157	$	559,819

(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 and also jointly-owned (54.7%) by TNC.
(f)	Operated by Cleco Corporation, a nonaffiliated company.
(g)	Operated by SWEPCo.
(h)	Turk Generating Plant is currently under construction with a projected commercial operation date of 2012. SWEPCo jointly owns the plant with Arkansas Electric Cooperative Corporation (11.67%), East Texas Electric Cooperative (8.33%) and Oklahoma Municipal Power Authority (6.67%). Through December 2008, construction costs totaling $34.8 million have been billed to the other owners.
(i)	Primarily relates to construction of Turk Generating Plant and environmental upgrades, including the installation of flue gas desulfurization projects at Conesville Generating Station and J. M. Stuart Generating Station.
N/A	= Not Applicable

17.	UNAUDITED QUARTERLY FINANCIAL INFORMATION

In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant Subsidiary is as follows:

Quarterly Periods Ended:	APCo		CSPCo		I&M			OPCo			PSO			SWEPCo
	(in thousands)
March 31, 2008
Revenues	$	735,027	$	541,649	$	537,149		$	802,188		$	336,000		$	339,793
Operating Income		108,465		130,777		98,573			237,438			69,141	(a)		16,820
Net Income		55,313		76,153		55,258			137,827			37,399	(a)		4,610

June 30, 2008
Revenues	$	667,397	$	548,947	$	542,647		$	782,361		$	400,334		$	423,617
Operating Income		62,640		99,034		86,458			109,572			17,017			31,109
Net Income		26,282		56,393		50,144			52,894			4,127			14,081

September 30, 2008
Revenues	$	798,833	$	663,783	$	621,023		$	857,014		$	551,249		$	512,463
Operating Income		82,917		143,456		86,711			121,021			56,157			81,834
Net Income		39,015		81,662		45,636			56,199			27,744			47,415

December 31, 2008
Revenues (b)	$	687,899	$	453,722	$	465,540		$	655,371		$	368,362		$	278,889
Operating Income (b)		58,954		50,421		4,356			27,019			18,148			42,882
Net Income (Loss) (b)		2,253		22,922		(19,163	)		(15,797	)		9,214			26,648

(a)	See “Oklahoma 2007 Ice Storms” section of Note 4 for discussion of the first quarter 2008 reversal of expenses incurred from ice storms in January and December 2007.
(b)	See “Allocation of Off-system Sales Margins” section of Note 4 for discussion of the financial statement impact of the FERC’s November 2008 order related to the SIA.

Quarterly Periods Ended:	APCo				CSPCo		I&M		OPCo		PSO				SWEPCo
	(in thousands)
March 31, 2007
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	)	(c)		26,462
Net Income (Loss)		70,227				46,981		29,463		79,261		(20,426	)	(c)		9,605

June 30, 2007
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		(78,763	)	(d)		-		-		-		-				-
Net Income (Loss)		(75,482	)			80,022		30,035		74,340		6,295				1,624

September 30, 2007
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
Revenues	$	677,555			$	482,237	$	505,110	$	706,095	$	310,562			$	344,831
Operating Income (Loss)		81,975				80,459		60,053		98,837		(71,796	)	(c)		16,683
Net Income (Loss)		35,933				45,631		28,273		39,701		(46,564	)	(c)		10,915

(c)	See “Oklahoma 2007 Ice Storms” section of Note 4 for discussion of expenses incurred from ice storms in January and December 2007.
(d)	See “Virginia Restructuring” in “Extraordinary Item” section of Note 2 for discussion of the extraordinary loss booked in the second quarter of 2007.

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 net income 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.

OUTLOOK FOR 2009

Market Impacts

In 2008, the domestic and world economies experienced significant slowdowns. Concurrently, the financial markets have become increasingly unstable and constrained at both a global and domestic level. This systemic marketplace distress is impacting the Registrant Subsidiaries’ access to capital, liquidity and cost of capital. The uncertainties in the capital markets could have significant implications since the Registrant Subsidiaries rely on continuing access to capital to fund operations and capital expenditures.

The current credit markets are constraining the Registrant Subsidiaries’ ability to issue new debt and refinance existing debt. APCo, OPCo and PSO have $150 million, $78 million and $50 million, respectively, maturing in 2009. Management intends to refinance these maturities. To support operations, AEP has $3.9 billion in aggregate credit facility commitments. These commitments include 27 different banks with no one bank having more than 10% of the total bank commitments. Short-term funding for the Registrant Subsidiaries comes from AEP’s credit facilities which support the Utility Money Pool. In 2008, AEP borrowed $2 billion under the credit facilities to enhance its position during this period of market disruptions. This money can be loaned to the Registrant Subsidiaries through the Utility Money Pool.

Management cannot predict the length of time the current credit situation will continue or its impact on future operations and the Registrant Subsidiaries’ ability to issue debt at reasonable interest rates. When market conditions improve, management plans to repay the amounts drawn under the credit facilities and issue commercial paper and long-term debt. If there is not an improvement in access to capital, management believes that the Registrant Subsidiaries have adequate liquidity, through the Utility Money Pool and cash flows from their operations to support planned business operations and capital expenditures through 2009.

AEP has significant investments in several trust funds to provide for future payments of pensions and OPEB. I&M has significant investments in several trust funds to provide for future payments of nuclear decommissioning and spent nuclear fuel disposal. Although all of the trust funds’ investments are well-diversified and managed in compliance with all laws and regulations, the value of the investments in these trusts declined substantially in 2008 due to decreases in domestic and international equity markets. Although the asset values are currently lower, this has not affected the funds’ ability to make their required payments.

On behalf of the Registrant Subsidiaries, AEPSC enters into risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. AEP’s risk management organization monitors these exposures on a daily basis to limit the Registrant Subsidiaries’ economic and financial statement impact on a counterparty basis.

Economic Slowdown

Following the indications of a slowing economy in 2007, the U.S. economy experienced what some have labeled a financial crisis in 2008. These economic troubles impacted and will continue to impact residential, commercial and industrial sales as well as sales opportunities in the wholesale market. Most sections of the Registrant Subsidiaries’ service territories are experiencing slowdowns in new construction, resulting in residential and commercial customer base growing at a decreased rate. Starting in the fourth quarter of 2008, various sections of the Registrant Subsidiaries’ service territories also experienced decreases in industrial sales due to temporary shutdowns and reduced shifts by some of the large industrial customers. Management expects these trends to continue throughout 2009.

In February 2009, Century Aluminum, a major industrial customer (325 MW load) of APCo, announced the curtailment of operations at its Ravenswood, WV facility.

Budgeted Construction Expenditures

Budgeted construction expenditures for the Registrant Subsidiaries for 2009 are:

	Budgeted
	Construction
	Expenditures
Company	(in millions)
APCo	$	367.5
CSPCo		269.6
I&M		361.6
OPCo		439.4
PSO		187.7
SWEPCo		457.4

LIQUIDITY

Sources of Funding

Short-term funding for the Registrant Subsidiaries comes from AEP’s commercial paper program and revolving credit facilities through the Utility Money Pool. 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. The credit facilities that support the Utility Money Pool were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $46 million following its bankruptcy. In March 2008, these credit facilities were amended so that $750 million may be issued under each credit facility as letters of credit (LOC). The Registrant Subsidiaries generally use short-term funding sources (the Utility 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-leasebacks, leasing arrangements and additional capital contributions from AEP.

In April 2008, the Registrant Subsidiaries and certain other companies in the AEP System entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12 million, respectively, following its bankruptcy. The Registrant Subsidiaries may issue LOCs under the credit facilities. Each subsidiary has a borrowing/LOC limit under the credit facilities. As of December 31, 2008, a total of $372 million of LOCs were issued under the 3-year credit agreement to support variable rate demand notes. The following table shows each Registrant Subsidiaries’ borrowing/LOC limit under each credit facility and the outstanding amount of LOCs for the $650 million facility.

							LOC Amount
							Outstanding
	$650 million			$350 million			Against
	Credit Facility			Credit Facility			$650 million
	Borrowing/LOC			Borrowing/LOC			Agreement at
	Limit			Limit			December 31, 2008
Company	(in millions)
APCo		$	300		$	150		$	127
CSPCo			230			120			-
I&M			230			120			78
OPCo			400			200			167
PSO			65			35			-
SWEPCo			230			120			-

At December 31, 2008, there were no outstanding amounts under the $350 million facility.

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 2008, AEP Credit renewed its sale of receivables agreement through October 2009. The sale of receivables agreement provides a commitment of $700 million from banks and commercial paper conduits to purchase receivables from AEP Credit. Management intends to extend or replace the sale of receivables agreement. At December 31, 2008, $650 million of commitments to purchase accounts receivable were outstanding under the receivables agreement. AEP Credit purchases accounts receivable from the Registrant Subsidiaries.

SIGNIFICANT FACTORS

Ohio Electric Security Plan Filings

Cook Plant Unit 1 Fire and Shutdown

I&M maintains property insurance through NEIL with a $1 million deductible. I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12-week deductible period, I&M is entitled to weekly payments of $3.5 million for the first 52 weeks following the deductible period. After the initial 52 weeks of indemnity, the policy pays $2.8 million per week for up to an additional 110 weeks. In January 2009, I&M filed to provide to customers a portion of the accidental outage insurance proceeds expected during the fuel cost forecast period of April through September 2009. If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if the unit is not returned to service in a reasonable period of time, it could have an adverse impact on net income, cash flows and financial condition.

New Generation

In 2008, AEP completed or is in various stages of construction of the following generation facilities:

Commercial

Total

Nominal

Operation

Operating

Project

Projected

Date

Company

Name

Location

Cost (a)

CWIP (b)

Fuel Type

Plant Type

Capacity

(Projected)

(in millions)

PSO

Southwestern

(c)

Oklahoma

Gas

Simple-cycle

150

2008

PSO

Riverside

(d)

Oklahoma

Gas

Simple-cycle

150

2008

AEGCo

Dresden

(e)

Ohio

310

(e)

179

Gas

Combined-cycle

580

2013

SWEPCo

Stall

Louisiana

384

252

Gas

Combined-cycle

500

2010

SWEPCo

Turk

(f)

Arkansas

1,628

(f)

510

Coal

Ultra-supercritical

600

(f)

2012

APCo

Mountaineer

(g)

West Virginia

(g)

Coal

IGCC

629

(g)

CSPCo/OPCo

Great Bend

(g)

Ohio

(g)

Coal

IGCC

629

(g)

(a)	Amount excludes AFUDC.
(b)	Amount includes AFUDC.
(c)	Southwestern Units were placed in service on February 29, 2008.
(d)	The final Riverside Unit was placed in service on June 15, 2008.
(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 440 MW, totaling $1.2 billion in capital investment. The increase in the cost estimate disclosed in the 2007 Annual Report relates to cost escalations due to the delay in receipt of permits and approvals. See “Turk Plant” section below.
(g)	Construction of IGCC plants are pending regulatory approvals. See “IGCC Plants” section below.

Turk Plant

IGCC Plant

The construction of the West Virginia and Ohio IGCC plants are pending regulatory approvals. In April 2008, the Virginia SCC issued an order denying APCo’s request to recover initial costs associated with a proposed IGCC plant in West Virginia. In July 2008, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed regarding its earlier approval of the IGCC plant. Comments were filed by various parties, including APCo, but the WVPSC has not taken any action. In July 2008, the IRS allocated $134 million in future tax credits to APCo for the planned IGCC plant contingent upon the commencement of construction, qualifying expenses being incurred and certification of the IGCC plant prior to July 2010. Through December 31, 2008, APCo deferred for future recovery preconstruction IGCC costs of $20 million. If the West Virginia IGCC plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs. If the plant is cancelled and if the deferred costs are not recoverable, it would have an adverse effect on future net income and cash flows.

In Ohio, neither CSPCo nor OPCo are engaged in a continuous course of construction on the IGCC plant. However, CSPCo and OPCo continue to pursue the ultimate construction of the IGCC plant. In September 2008, the Ohio Consumers’ Counsel filed a motion with the PUCO requesting all Phase 1 cost recoveries be refunded to Ohio ratepayers with interest. CSPCo and OPCo filed a response with the PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit and contrary to past precedent. If CSPCo and OPCo were required to refund some or all of the $24 million collected for IGCC pre-construction costs and those costs were not recoverable in another jurisdiction in connection with the construction of an IGCC plant, it would have an adverse effect on future net income and cash flows.

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). AEP merged the Qualified Plans at December 31, 2008. 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 the Plans’ assets:

	Years Ended December 31,
	2008				2007				2006
Net Periodic Benefit Cost	(in millions)
Pension Plans		$	51			$	50			$	71
Postretirement Plans			80				81				96
Assumed Rate of Return
Pension Plans			8.00	%			8.50	%			8.50	%
Postretirement Plans			8.00	%			8.00	%			8.00	%

The net periodic benefit 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 2009, 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 2008, of approximately 3%. AEP anticipates that the investment managers employed for the Plans will generate future returns averaging 8.00% for the Pension Plan and 7.75% for the Postretirement Plans.

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 Plans									Other Postretirement Benefit Plans
							Assumed/									Assumed/
	2008			2009			Expected			2008			2009			Expected
	Actual			Target			Long-term			Actual			Target			Long-term
	Asset			Asset			Rate of			Asset			Asset			Rate of
	Allocation			Allocation			Return			Allocation			Allocation			Return

Equity		47	%		55	%		9.5	%		53	%		65	%		8.8	%
Real Estate		6	%		5	%		7.5	%		-	%		-	%		-	%
Debt Securities		42	%		39	%		6.0	%		43	%		34	%		5.8	%
Cash and Cash Equivalents		5	%		1	%		3.5	%		4	%		1	%		2.7	%
Total		100	%		100	%					100	%		100	%

	2009 Pension		2009 Other Postretirement Benefit Plans
Overall Expected Return (weighted average)	8.00%		7.75%

Global capital markets experienced extreme volatility in 2008. The value of investments in AEP’s pension and OPEB trusts declined substantially due to decreases in domestic and international equity markets. Although the asset values are currently lower, this decline has not affected the funds’ ability to make their required payments.

AEP regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation. AEP believes that 8% for the Pension Plans and 7.75% for the Postretirement Plans are reasonable long-term rate of return on the Plans’ assets despite the recent market volatility. The Pension Plans’ assets had an actual (loss) gain of (24.1)% and 9.2% for the years ended December 31, 2008 and 2007, respectively. The Postretirement Plans’ assets had an actual (loss) gain of (24.7)% and 8.6% for the years ended December 31, 2008 and 2007, respectively. Management will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary.

AEP bases the determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of December 31, 2008, AEP had cumulative losses of approximately $1 billion that remain to be recognized in the calculation of the market-related value of assets. These unrecognized net actuarial losses result in increases in the future pension costs depending on several factors, including whether such losses at each measurement date exceed the corridor in accordance with 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, 2008 under this method was 6.00% for the Pension Plans and 6.10% 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 $92 million, $145 million and $152 million in 2009, 2010 and 2011, respectively. Based on an expected rate of return on the OPEB plans’ assets of 7.75%, a discount rate of 6.10% and various other assumptions, AEP estimates Postretirement Plan costs will approximate $148 million, $140 million and $121 million in 2009, 2010 and 2011, 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 included 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 decreased substantially to $3.2 billion at December 31, 2008 from $4.5 billion at December 31, 2007 primarily due to investment losses. The Qualified Plans paid $289 million in benefits to plan participants during 2008 (nonqualified plans paid $7 million in benefits). The value of AEP’s Postretirement Plans’ assets decreased substantially to $1 billion at December 31, 2008 from $1.4 billion at December 31, 2007 primarily due to investment losses. The Postretirement Plans paid $120 million in benefits to plan participants during 2008.

Investments in trusts are stated at fair market value. AEP utilizes the trustee’s external pricing service to measure the market value of the underlying investments. AEP’s investment managers review and validate the prices utilized to determine fair market value. AEP also performs valuation testing to validate the market values of the actively traded securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. Where possible, quoted prices on actively traded exchanges are used to determine value. Debt holdings that are not actively traded may be valued based on the observable pricing of comparable securities. Investments in commingled funds are generally not actively traded and are priced at a Net Asset Value (NAV) which is based on the underlying holdings of the funds. These holdings are typically actively traded equities or debt securities that may be valued in a manner similar to direct debt investments. Trust assets as of December 31, 2008 include approximately $244 million of real estate and private equity investments in the pension fund that are valued based on methods requiring judgment.

AEP’s Qualified Plans were underfunded as of December 31, 2008. No contribution to the Qualified Plans is required under ERISA in 2009. Minimum contributions to the Qualified Plans of $365 million in 2010 and $258 million in 2011 are currently projected under ERISA and may vary significantly based on future market returns, changes in actuarial assumptions and other factors. AEP’s nonqualified pension plans are unfunded, and are therefore considered underfunded for accounting purposes. For the nonqualified pension plans, the accumulated benefit obligation exceeded plan assets by $80 million and $77 million at December 31, 2008 and 2007, respectively.

Certain pension plans AEP sponsors contain a cash balance benefit feature. In 2008, the IRS issued Determination Letters confirming the tax exempt status of these plans including the cash balance benefit feature.

The Worker, Retiree and Employer Recovery Act of 2008 did not materially impact the 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 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, AEP’s management agreed to annual SO2 and NOx emission caps for sixteen coal-fired power plants located in Indiana, Kentucky, Ohio, Virginia and West Virginia. AEP’s management agreed to install FGD 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 SCR and FGD emissions control equipment on their jointly-owned Rockport Plant no later than the end of 2017 for Unit 1 and no later than the end of 2019 for Unit 2. APCo agreed to install selective non-catalytic reduction, a NOx-reduction technology, no later than the end of 2009 at Clinch River Plant.

CSPCo jointly-owns Beckjord and Stuart Stations with Duke Energy Ohio, Inc. and Dayton Power and Light Company. A jury trial returned a verdict of no liability at the jointly-owned Beckjord unit. In December 2008, however, the court ordered a new trial in the Beckjord case. In October 2008, the court approved a settlement in a citizen suit action filed by Sierra Club against the jointly-owned units at Stuart Station. Under the settlement, the joint-owners of Stuart Station agreed to certain emission targets related to NOx, SO2 and PM. The joint-owners also agreed to make energy efficiency and renewable energy commitments that are conditioned on PUCO approval for recovery of costs. The joint-owners also agreed to forfeit 5,500 SO2 allowances and provide $300 thousand to a third party organization to establish a solar water heater rebate program.

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 net income, 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 and PM 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 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. In 2008, the Federal EPA issued revised NAAQS for both ozone and PM 2.5. These new standards could increase the levels of SO2 and NOx reductions required from the Registrant Subsidiaries’ facilities. The Federal EPA also established a lower standard for lead, and conducts periodic reviews for additional criteria pollutants including SO2 and NOx.

In 2005, the Federal EPA issued a final rule, the Clean Air Interstate Rule (CAIR). It requires specific reductions in SO2 and NOx emissions from power plants and assists states developing new SIPs to meet the 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% by 2010, and by 65% by 2015. NOx emissions will be subject to additional limits beginning in 2009, and will be reduced by a total of 70% from current levels by 2015. Reductions of both SO2 and NOx would be achieved through a cap-and-trade program. In July 2008, the D.C. Circuit Court of Appeals issued a decision that would vacate CAIR and remanded the rule to the Federal EPA. In September 2008, the Federal EPA and other parties petitioned for rehearing. In December 2008, the D.C. Circuit Court of Appeals granted the Federal EPA’S petition and remanded the rule to the Federal EPA without vacatur, allowing CAIR to remain in effect while a new rulemaking is conducted. Management is unable to predict how the Federal EPA will respond to the remand. 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 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. The Federal EPA filed a petition for review by the U.S. Supreme Court, but the new Federal EPA Administrator asked that the petition be withdrawn. Management is unable to predict the outcome of this appeal or 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 currently uses the SO2 allowances originally allocated through the Acid Rain Program as the basis for its SO2 cap-and-trade system. Management is unable to predict if or how any replacement for CAIR will utilize the SO2 allowances from the Acid Rain Program.

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 (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.

In January 2009, the Federal EPA issued a determination that 37 states (including Indiana, Ohio, Oklahoma, Texas and Virginia) failed to submit SIP’s fulfilling the Regional Haze program requirements by the deadline, and commencing a 2-year period for the development of a Federal Implementation Plan (FIP) in these states. Management is unable to predict if or how the remand of CAIR or the development of a FIP for certain states may affect compliance obligations for the Regional Haze programs.

Estimated Air Quality Environmental Investments

The CAIR 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 2008, APCo, CSPCo and OPCo installed SCR technology on a total of 10,580 MW at their power plants to comply with NOx requirements. The Registrant Subsidiaries comply with SO2 requirements by installing scrubbers and using alternate fuels and SO2 allowances. The Registrant Subsidiaries receive allowances through allocation and purchase at either the annual Federal EPA auction or in the market. Decreasing allowance allocations, diminishing SO2 allowance banks, increasing allowance costs, CAIR 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 8,200 MW for SO2 control. This amount includes the installation of scrubbers on the Rockport Plant which is 50% owned by I&M and 50% owned by AEGCo. From 2009 to 2013, 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	$	386.4	$	172.9
CSPCo		367.5		103.5
I&M		48.4		1.0
OPCo		610.7		271.0
PSO		807.4		787.5
SWEPCo		672.6		666.4

These estimates may be revised as a result of the court’s decision remanding the CAIR and 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 and the NSR settlement discussed above, the Registrant Subsidiaries expect to incur additional costs for pollution control technology retrofits between 2014 and 2020 totaling approximately $3.3 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 and FIPs that impose standards more stringent than CAIR; (2) additional rulemaking activities in response to the court decisions remanding the CAIR and CAMR; (3) the actual performance of the pollution control technologies installed on each unit; (4) changes in costs for new pollution controls; (5) new generating technology developments; and (6) 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 net income, 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

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.

In April 2008, the U.S. Supreme Court agreed to review decisions from the Second Circuit Court of Appeals that limit the Federal EPA’s ability to weigh the retrofitting costs against environmental benefits. Management is unable to predict the outcome of this appeal.

Potential Regulation of CO2 and Other GHG Emissions

The scientific community, led largely by the Intergovernmental Panel on Climate Change, has provided scientific evidence that human activity, and particularly the combustion of fossil fuels, has increased the levels of GHG in the atmosphere and contributed to observed changes in the global climate system. These findings have led to proposals for substantial transformation of the world’s energy production and transportation systems in order to slow, and ultimately reduce, the production of CO2 and other GHG emissions sufficiently to reduce atmospheric concentrations. Because approximately 90% of the electricity generated by the AEP System is produced by the combustion of fossil fuels, AEP’s management is helping to lead the discussion nationally and internationally to find a reasonable, achievable approach and enact federal energy policy that is realistic in time frame and does not seriously harm the U.S. economy. The AEP System is also developing advanced coal technologies so that coal can continue to be the important energy resource it is today. The AEP System supports the adoption of an economy-wide, cap-and-trade GHG reduction program that allows electric companies to provide reliable, reasonably priced electricity to customers and that fosters the international participation that is necessary to make meaningful progress.

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 GHG emissions. The U.S. signed the Kyoto Protocol in 1998, but the treaty was not submitted 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. Negotiations designed to lead to a global agreement on limiting GHG emissions after the Kyoto Protocol expires have commenced, and are focused on flexible mechanisms that can address the concerns expressed by the U.S. and others regarding the global impacts of increasing emissions in developing economies, including China, Brazil, and India, and mitigating the economic impacts of GHG reductions in developed countries given current economic conditions.

Since 2005, several members of Congress have introduced bills that would regulate GHG emissions, including emissions from power plants. Congress has passed no legislation, but recent bills have received more serious consideration and some form of national legislation impacting the electric utility industry is likely to pass within the next few years. Such legislation is likely to take the form of direct regulation of GHG emissions through cap-and-trade provisions. In addition and related to climate change legislation, a national renewable portfolio standard, energy efficiency requirements for electric utilities and other measures may pass Congress in the next few years.

Several states have adopted programs that directly regulate GHG emissions from power plants, but none of these programs are currently in effect in states where the AEP System has generating facilities. Certain of the states where the Registrant Subsidiaries operate have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements (including Ohio, Michigan, Texas and Virginia). The Registrant Subsidiaries are taking steps to comply with these requirements. Through recent purchases of wind power and the existing wind assets that the AEP System has developed and future plans, the integrated resource plan contains a 10% renewable energy target by 2020, which is nearly double the level of renewable energy requirements in effect in those states. Management’s plans are based on the reasonable expectation that additional federal or state requirements may be enacted that will affect the AEP System.

AEP’s 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 AEP System has taken measurable, voluntary actions to reduce and offset its GHG emissions. The AEP System participates in a number of voluntary programs to monitor, mitigate and reduce GHG emissions, including the Federal EPA’s Climate Leaders program, the DOE’s GHG reporting program and the Chicago Climate Exchange. Through the end of 2007, the AEP System reduced emissions by a cumulative 46 million metric tons from adjusted baseline levels in 1998-2001 as a result of these voluntary actions. The AEP System’s total GHG emissions in 2007 were 155.8 million metric tons. AEP’s management estimates that 2008 emission will be approximately 155 million metric tons and the cumulative reductions will be in excess of 51 metric million tons.

AEP’s management believes that climate change 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. AEP’s management, along with the International Brotherhood of Electrical Workers (IBEW), proposed that a consistent national policy for reasonable GHG 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, AEP, 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. AEP’s management endorses this legislation because it sets reasonable and achievable reduction targets and includes key elements of the AEP-IBEW principles. AEP’s management also supports the Edison Electric Institute (EEI) principles for federal climate change legislation, including the consensus approach developed by EEI for the allocation of emission allowances.

President Obama has stated that he favors climate legislation that would reduce GHG emissions by 80% by 2050 and require the auctioning of all allowances. AEP’s management opposes a 100% auction of GHG emission allowances, as it would substantially increase the costs of compliance on the AEP System and increase customer rates. AEP’s management supports reasonable emission reduction targets that allow sufficient time for technology development and recognize that commercial scale technologies to provide substantial GHG emission reductions at new or existing electric generating units are not currently available.

While comprehensive economy-wide regulation of GHG emissions might be achieved through new legislation, several states and interest groups petitioned the Federal EPA to establish GHG emission standards under the existing requirements of the CAA. In April 2007, the U.S. Supreme Court reversed and remanded the Federal EPA’s determination that it lacked the authority to regulate GHG emissions from motor vehicles for purposes of climate change under the CAA. In response to the Supreme Court’s decision, the Federal EPA issued an Advance Notice of Proposed Rulemaking in July 2008 seeking comment on its analysis of the applicability of various provisions of the CAA, and the suitability of different provisions of the mobile source, stationary source, and permitting programs under the CAA to effectively regulate GHG emissions. AEP’s management agrees with the assessment of the previous EPA Administrator that the existing authorities under the CAA are not well-suited to achieving economy-wide cost-effective reductions of GHG emissions. Shortly after taking office, President Obama directed the Federal EPA to re-examine a decision denying the request by the State of California for a waiver that would allow states to establish higher fuel efficiency standards as a means of reducing GHG emissions from mobile sources. Thirteen states have taken action that would implement the California standards if the Federal EPA issues such a waiver. While this waiver, if issued, would have no immediate impact on stationary sources, should the Federal EPA choose to take other actions to regulate GHG emissions under the CAA, they could have a material impact upon the costs of operating fossil-fueled generating plants.

In addition, certain groups have filed lawsuits alleging that emissions of CO2 and other GHGs are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others. AEP and certain of its subsidiaries have been named in two pending lawsuits, which AEP’s management is vigorously defending. It is not possible to predict the outcome of these lawsuits or their impact on operations or financial condition. See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 6.

AEP’s 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. While the AEP System is 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 that controls the emissions of GHG from fossil-fueled generating plants. The AEP System is advancing more efficient technologies for power generation, including ultra-super-critical technology and IGCC, as authorized by the regulatory commissions. 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 AEP System is also pursuing renewable sources of energy generation, energy efficiency measures, gridSMART load management investments and other improved transmission, distribution and energy storage methods to reduce overall GHG emissions from its operations. The Registrant Subsidiaries will seek recovery of the costs 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 net income, 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 net income or financial condition.

Management discusses the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the 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 incurred costs are probable of recovery through regulated rates, the Registrant Subsidiaries record them as regulatory assets on the balance sheet. Regulatory assets are reviewed for probability of recovery at each balance sheet date and whenever new events occur. Examples of new events include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, 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 net income. 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 accordance with the applicable state commission regulatory treatment in Arkansas, Louisiana, Oklahoma and Texas, PSO and SWEPCo do not record the fuel portion of unbilled revenue.

The change in unbilled electric utility revenues included in Revenue for the years ended December 31, 2008, 2007 and 2006 were as follows:

	Years Ended December 31,
	2008			2007			2006
Company	(in thousands)
APCo	$	32,815		$	(11,059	)	$	711
CSPCo		7,614			5,432			4,545
I&M		12,934			12,363			1,166
OPCo		4,048			11,717			(3,312	)
PSO		(211	)		7,523			157
SWEPCo		5,008			2,186			(4,875	)

Assumptions and Approach Used: For each Registrant Subsidiary, the monthly estimate for unbilled revenues is computed as net generation less the current month’s billed KWH plus the prior month’s unbilled KWH. However, due to meter reading issues, meter drift and other anomalies, a separate monthly calculation limits the unbilled estimate within a range of values. This limiter calculation is derived from an allocation of billed KWH to the current month and previous month, on a cycle-by-cycle basis, and dividing the current month aggregated result by the billed KWH. The limits are statistically set at one standard deviation from this percentage to determine the upper and lower limits of the range. The unbilled estimate is compared to the limiter calculation and adjusted for variances exceeding the upper and lower limits.

Effect if Different Assumptions Used: Significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. A 1% change in the limiter calculation when it is outside the range would increase or decrease unbilled revenues by 1% of the Accrued Unbilled Revenues 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: The Registrant Subsidiaries 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.

The Registrant Subsidiaries reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality. Liquidity adjustments are calculated by utilizing 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. Management evaluates the probability of the occurrence of the forecasted transaction within the specified time period as provided 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 not occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified into operating income.

For additional information regarding derivatives, hedging and fair value measurements, see Note 11 of the Notes to Financial Statements of Registrant Subsidiaries.

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” (SFAS 144), 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 Registrant 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 against earnings.

Assumptions and Approach Used: The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, the 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, 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: The Registrant Subsidiaries participate in AEP sponsored pension and other retirement and postretirement benefit plans in various forms covering all employees who meet eligibility requirements. These benefits are accounted for under SFAS 87, “Employers’ Accounting For Pensions”, SFAS 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” and SFAS 158. See Note 8 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, 2008 Benefit Obligations:
Discount Rate	$	(182	)	$	198		$	(105	)	$	111
Compensation Increase Rate		14			(13	)		3			(3	)
Cash Balance Crediting Rate		50			(46	)		N/A			N/A
Health Care Cost Trend Rate		N/A			N/A			96			(83	)

Effect on 2008 Periodic Cost:
Discount Rate		(15	)		16			(11	)		12
Compensation Increase Rate		4			(4	)		1			(1	)
Cash Balance Crediting Rate		11			(10	)		N/A			N/A
Health Care Cost Trend Rate		N/A			N/A			16			(14	)
Expected Return on Plan Assets		(21	)		21			(7	)		7

N/A = Not Applicable

New Accounting Pronouncements

Adoption of New Accounting Pronouncements in 2008

The Registrant Subsidiaries partially adopted SFAS 157 in 2008 and completed the adoption of SFAS 157 effective January 1, 2009. The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures. The adoption of SFAS 157 had an immaterial impact on the Registrant Subsidiaries’ financial statements. See “SFAS 157 Fair Value Measurements” section of Note 11 for further information.

The Registrant Subsidiaries adopted SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities” effective January 1, 2008. The statement permitted entities to choose to measure many financial instruments and certain other items at fair value. The standard also established presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities. At adoption, the Registrant Subsidiaries did not elect the fair value option for any assets or liabilities.

The FASB issued SFAS 162 “The Hierarchy of Generally Accepted Accounting Principles” (SFAS 162), clarifying the sources of generally accepted accounting principles in descending order of authority. The statement specifies that the reporting entity, not its auditors, is responsible for its compliance with GAAP. The Registrant Subsidiaries adopted SFAS 162 with no impact on their financial statements.

The FASB ratified EITF 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements” 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 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. The Registrant Subsidiaries adopted EITF 06-10 effective January 1, 2008 with a cumulative effect reduction to beginning retained earnings. See “Pronouncements Adopted in 2008” section of Note 2.

The Registrant Subsidiaries adopted EITF 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11) effective January 1, 2008. The rule addressed the recognition of income tax benefits of dividends on employee share-based compensation. The adoption of this standard had an immaterial impact on their financial statements.

The FASB issued FSP SFAS 133-1 and FIN 45-4 “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161.” Under the SFAS 133 requirements, the seller of a credit derivative shall disclose additional information for each derivative, including credit derivatives embedded in a hybrid instrument, even if the likelihood of payment is remote. Further, the standard requires the disclosure of current payment status/performance risk of all FIN 45 guarantees. In the event an entity uses internal groupings, the entity shall disclose how those groupings are determined and used for managing risk. The Registrant Subsidiaries adopted the standard effective December 31, 2008. The adoption of this standard had no impact on the financial statements but increased the guarantees disclosures in Note 6.

The FASB issued FSP SFAS 140-4 and FIN 46R-8 “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities” amending SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” and FIN 46R “Consolidation of Variable Interest Entities.” The amendments required additional disclosure regarding transfers of financial assets and variable interest entities. The Registrant Subsidiaries adopted the standards effective December 31, 2008. The adoption of these standards had no impact on the financial statements but increased the footnote disclosures for variable interest entities. See “Variable Interest Entities” section of Note 15.

FSP FIN 39-1 amends FIN 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 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. The Registrant Subsidiaries adopted FIN 39-1 effective January 1, 2008. See “Pronouncements Adopted in 2008” section of Note 2.

New Accounting Pronouncements Adopted During the First Quarter of 2009

The FASB issued SFAS 141R (revised “Business Combinations” 2007) improving financial reporting about business combinations and their effects. SFAS 141R can affect tax positions on previous acquisitions. The Registrant Subsidiaries do not have any such tax positions that result in adjustments. The Registrant Subsidiaries adopted SFAS 141R effective January 1, 2009. The Registrant Subsidiaries will apply it to any future business combinations.

The FASB issued SFAS 160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS 160), modifying reporting for noncontrolling interest (minority interest) in consolidated financial statements. The statement 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. The Registrant Subsidiaries adopted SFAS 160 retrospectively effective January 1, 2009. The adoption of this standard had an immaterial impact on the financial statements. Prior period financial statements in future filings will be comparable.

The FASB issued SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161), enhancing disclosure requirements for derivative instruments and hedging activities. The standard requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This standard will increase disclosure requirements related to derivative instruments and hedging activities in future reports. The Registrant Subsidiaries adopted SFAS 161 effective January 1, 2009.

The FASB ratified EITF Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5) a consensus on liabilities with third-party credit enhancements when the liability is measured and disclosed at fair value. The consensus treats the liability and the credit enhancement as two units of accounting. The Registrant Subsidiaries adopted EITF 08-5 effective January 1, 2009. It will be applied prospectively with the effect of initial application included as a change in fair value of the liability in the period of adoption. The adoption of this standard will impact the financial statements in the 2009 Annual Report as the Registrant Subsidiaries report fair value of long-term debt annually.

The FASB ratified EITF Issue No. 08-6 “Equity Method Investment Accounting Considerations” (EITF 08-6), a consensus on equity method investment accounting including initial and allocated carrying values and subsequent measurements. The Registrant Subsidiaries prospectively adopted EITF 08-6 effective January 1, 2009 with no impact on their financial statements.

The FASB issued FSP SFAS 142-3 “Determination of the Useful Life of Intangible Assets” amending factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. The Registrant Subsidiaries adopted the rule effective January 1, 2009. The guidance is prospectively applied to intangible assets acquired after the effective date. The standard’s disclosure requirements are applied prospectively to all intangible assets as of January 1, 2009. The adoption of this standard had no impact on the financial statements.

Pronouncements Effective in the Future

The FASB issued FSP SFAS 132R-1 “Employers’ Disclosures about Postretirement Benefit Plan Assets” providing additional disclosure guidance for pension and OPEB plan assets. The standard adds disclosure requirements including hierarchical classes for fair value and concentration of risk. This standard is effective for fiscal years ending after December 15, 2009. Management expects this standard to increase the disclosure requirements related to AEP’s benefit plans. The Registrant Subsidiaries will adopt the standard effective for the 2009 Annual Report.


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:
	Selected Financial Data
	Management’s 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 electric utility companies.
AEP East companies		APCo, CSPCo, I&M, KPCo and OPCo.
AEP Foundation		AEP charitable organization created in 2005 for charitable contributions in the communities in which AEP’s subsidiaries operate.
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 System or the System		American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP West companies		PSO, SWEPCo, TCC and TNC.
AEPEP		AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, asset management and commercial and industrial sales in the deregulated Texas market.
AEPES		AEP Energy Services, Inc., a subsidiary of AEP Resources, Inc.
AEPSC		American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
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.
DHLC		Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo that is consolidated under FIN 46R.
DOE		United States Department of Energy.
DOJ		United States Department of Justice.
DSM		Demand-side Management.
E&R		Environmental compliance and transmission and distribution system reliability.

EaR		Earnings at Risk, a method to quantify risk exposure.
EIS		Energy Insurance Services, Inc., a protected cell insurance company that AEP consolidates under FIN 46R.
EITF		Financial Accounting Standards Board’s Emerging Issues Task Force.
EITF 06-10		EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements.”
EPS		Earnings Per Share.
ERCOT		Electric Reliability Council of Texas.
ERISA		Employee Retirement Income Security Act of 1974, as amended.
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.
FGD		Flue Gas Desulfurization or Scrubbers
FIN		FASB Interpretation No.
FIN 46R		FIN 46R, “Consolidation of Variable Interest Entities.”
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.”
FSP		FASB Staff Position.
FSP FIN 39-1		FSP FIN 39-1, “Amendment of FASB Interpretation No. 39.”
FTR		Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP		Accounting Principles Generally Accepted in the United States of America.
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.
Interconnection Agreement		Agreement, dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
IRS		Internal Revenue Service.
IURC		Indiana Utility Regulatory Commission.
I&M		Indiana Michigan Power Company, an AEP electric utility subsidiary.
JMG		JMG Funding LP, a financing company that OPCo consolidates under FIN 46R.
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.
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.
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.
PM		Particulate Matter.
PSO		Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO		Public Utilities Commission of Ohio.
PUCT		Public Utility Commission of Texas.
Registrant Subsidiaries		AEP subsidiaries which are SEC registrants; APCo, 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.
Sabine		Sabine Mining Company, a lignite mining company that SWEPCo consolidates under FIN 46R.
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 107		Statement of Financial Accounting Standards No. 107, “Disclosures about Fair Value of Financial Investments.”
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 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.”
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.
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.
TCRR		Transmission Cost Recovery Rider.
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.

·	The economic climate and growth in, or contraction within, our service territory and changes in market demand and demographic patterns.
·	Inflationary or deflationary interest rate trends.
·	Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·	The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
·	Electric load 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 including our ability to restore Cook Plant Unit 1 in a timely manner.
·	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 and transmission line facilities (including our ability to obtain any necessary regulatory or siting approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.
·	New legislation, litigation and government regulation including 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.
·	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 markets.
·	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 implementation of the recently passed utility law in Ohio and the allocation of costs within RTOs, including PJM and SPP.
·	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 and the impact on future funding requirements.
·	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, 2008	$	37.28	$	25.54	$	33.28	$	0.41
September 30, 2008		41.60		34.86		37.03		0.41
June 30, 2008		45.95		39.46		40.23		0.41
March 31, 2008		49.11		39.35		41.63		0.41

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

(a)	Extraordinary Loss, Net of Tax for 2005 reflects TCC’s stranded cost.
(b)	Includes reclassification of assets due to FSP FIN 39-1 adoption effective in 2008. See “FSP FIN 39-1” section of Note 2.
(c)	Includes portion due within one year.

·	Almost 39,000 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 commodity transportation assets (more than 9,000 railcars, 2,978 barges, 58 towboats, 25 harbor boats and a coal handling terminal with 20 million tons of annual capacity).

·	Hold operation and maintenance expense relatively flat as compared to 2008.
·	Significantly reduce our capital expenditures while continuing construction of additional new generation.
·	Aggressively seek rate relief by developing rate plans that obtain favorable and timely resolutions to our rate proceedings.
·	Continue developing strong regulatory relationships through operating company interaction with the various regulatory bodies.

·	Domestic and international economic slowdowns.
·	Access to capital markets to support our proposed capital expenditures.
·	Intervention by consumer advocates in current and future state and FERC regulatory proceedings who try to keep rates down at the expense of a fair return.
·	Wholesale market volatility.
·	The return to service of Cook Plant Unit 1 and overall plant availability.
·	Managing our overall generating fleet to maximize our off-system sales opportunities despite the loss of production from Cook Plant Unit 1.
·	Fuel cost volatility and timely fuel cost recovery, including related transportation costs.
·	Managing the effects of potential environmental legislation and regulation regarding carbon dioxide and other emissions on our existing generating fleet.
·	Expanding our generating fleet while complying with potential new emission restrictions on the construction of future plants.
·	Weather-related system reliability and utilization.

·	Achieving favorable regulatory results in Ohio under Senate Bill 221.
·	Maintaining adequate returns in AEP’s retail jurisdictions by filing for rate increases, where necessary.
·	Continuing progress on major transmission projects by:
	·	Securing favorable regulatory treatment for transmission projects.
	·	Obtaining successful outcomes in siting and right of way filings.
	·	Seeking proper cost recovery within and across RTOs.

·	We have $1.9 billion in aggregate available credit facility commitments as of December 31, 2008. These commitments include 27 different banks with no one bank having more than 10% of our total bank commitments. In April 2009, $338 million of our $1.9 billion in available credit facility commitments will expire. As of December 31, 2008, our total cash and cash equivalents were $411 million.
·	Of our $16 billion of long-term debt as of December 31, 2008, approximately $300 million will mature in 2009 (approximately 1.9% of our outstanding long-term debt as of December 31, 2008). We intend to refinance these maturities. The $300 million of 2009 maturities exclude payments due for securitization bonds which we recover directly from ratepayers.
·	We will receive a favorable impact in 2009 due to base rate increases in Oklahoma and Virginia and an expected base rate increase in Indiana. We are currently awaiting a decision on the Ohio ESP filings.
·	We believe that our projected cash flows from operating activities are sufficient to support our ongoing operations.

	Original 2009					Revised 2009
	Capital Expenditure		$750 Million Budget			Capital Expenditure
	Projection		Reduction			Budget
	(in millions)
New Generation	$	469	$	(234	)	$	235
Environmental		668		(232	)		436
Other Generation		643		(37	)		606
Transmission		476		56			532
Distribution		949		(263	)		686
Corporate		129		(40	)		89

Total	$	3,334	$	(750	)	$	2,584

	2008		2007			2006			2005			2004
	(in millions)
STATEMENTS OF INCOME DATA
Total Revenues	$	14,440	$	13,380		$	12,622		$	12,111		$	14,245

Operating Income	$	2,787	$	2,319		$	1,966		$	1,927		$	1,983

Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change	$	1,368	$	1,144		$	992		$	1,029		$	1,127
Discontinued Operations, Net of Tax		12		24			10			27			83
Income Before Extraordinary Loss and Cumulative Effect of Accounting Change		1,380		1,168			1,002			1,056			1,210
Extraordinary Loss, Net of Tax		-		(79	)		-			(225	)(a)		(121	)
Cumulative Effect of Accounting Change, Net of Tax		-		-			-			(17	)		-
Net Income	$	1,380	$	1,089		$	1,002		$	814		$	1,089

BALANCE SHEETS DATA	(in millions)
Property, Plant and Equipment	$	49,710	$	46,145		$	42,021		$	39,121		$	37,294
Accumulated Depreciation and Amortization		16,723		16,275			15,240			14,837			14,493
Net Property, Plant and Equipment	$	32,987	$	29,870		$	26,781		$	24,284		$	22,801

Total Assets	$	45,155	$	40,319	(b)	$	37,877	(b)	$	35,662	(b)	$	34,388	(b)

Common Shareholders’ Equity	$	10,693	$	10,079		$	9,412		$	9,088		$	8,515

Cumulative Preferred Stocks of Subsidiaries	$	61	$	61		$	61		$	61		$	127

Long-term Debt (c)	$	15,983	$	14,994		$	13,698		$	12,226		$	12,287

Obligations Under Capital Leases (c)	$	325	$	371		$	291		$	251		$	243

COMMON STOCK DATA
Basic Earnings (Loss) per Common Share:
Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change	$	3.40	$	2.87		$	2.52		$	2.64		$	2.85
Discontinued Operations, Net of Tax		0.03		0.06			0.02			0.07			0.21
Income Before Extraordinary Loss and Cumulative Effect of Accounting Change		3.43		2.93			2.54			2.71			3.06
Extraordinary Loss, Net of Tax		-		(0.20	)		-			(0.58	)		(0.31	)
Cumulative Effect of Accounting Change, Net of Tax		-		-			-			(0.04	)		-

Basic Earnings Per Share	$	3.43	$	2.73		$	2.54		$	2.09		$	2.75

Weighted Average Number of Basic Shares Outstanding (in millions)		402		399			394			390			396

	2008	2007	2006
	(in millions of KWH)
Retail:
Residential	49,011	49,176	47,222
Commercial	40,078	40,545	38,579
Industrial	58,170	57,566	53,914
Miscellaneous	2,501	2,565	2,653
Total Retail	149,760	149,852	142,368

Wholesale	42,830	42,917	44,564

Texas Wires – Energy delivered to customers served by TNC and TCC in ERCOT	27,075	26,682	26,382
Total KWHs	219,665	219,451	213,314

·	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’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
	·	Tax and interest expense adjustments related to our UK operations which were sold in 2004 and 2002.
	·	Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005. These contracts are financial derivatives which will gradually settle and completely expire in 2011.
	·	Other energy supply related businesses, including the Plaquemine Cogeneration Facility, which was sold in 2006. See “Plaquemine Cogeneration Facility” section of Note 7.
	·	The 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006. The cash settlement of $255 million ($164 million, net of tax) is included in Net Income.
	·	Revenue sharing related to the Plaquemine Cogeneration Facility.

(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, 2007			$	1,031

Changes in Gross Margin:
Retail Margins	114
Off-system Sales	(45	)
Transmission Revenues	33
Other	25
Total Change in Gross Margin				127

Changes in Operating Expenses and Other:
Other Operation and Maintenance	35
Gain on Dispositions of Assets, Net	(19	)
Depreciation and Amortization	33
Taxes Other Than Income Taxes	(1	)
Interest Income	21
Carrying Costs Income	32
Other Income, Net	14
Interest Expense	(129	)
Total Change in Operating Expenses and Other				(14	)

Income Tax Expense				(29	)

Year Ended December 31, 2008			$	1,115

·	Retail Margins increased $114 million primarily due to the following:
	·	A $206 million increase related to net rate increases implemented in our Ohio jurisdictions, a $53 million increase related to recovery of E&R costs in Virginia and construction financing costs in West Virginia, a $25 million net increase in rates in Oklahoma, a $21 million increase in base rates in Texas and an $18 million increase in base rates in Virginia.
	·	A $99 million net increase due to adjustments recorded in 2007 related to the 2007 Virginia base rate case which included a second quarter 2007 provision for revenue refund.
	·	A $50 million increase related to increased usage by Ormet, an industrial customer in Ohio. See “Ormet” section of Note 4.
	·	A $40 million net increase due to coal contract amendments in 2008.
	·	An $18 million decrease in the sharing of off-system sales margins with customers due to a decrease in total off-system sales.
	·	A $17 million increase due to a 2007 provision related to a SWEPCo Texas fuel reconciliation proceeding.
	These increases were partially offset by:
	·	A $213 million increase in fuel and consumable expenses in Ohio. CSPCo and OPCo have applied for an active fuel clause in their Ohio Electric Security Plan filings to be effective January 1, 2009.
	·	A $102 million decrease due to the December 2008 provision for refund of off-system sales margins as ordered by the FERC related to the SIA. See “Allocation of Off-system Sales Margins” section of Note 4.
	·	A $65 million decrease in usage primarily due to a 26% decrease in cooling degree days in our eastern region and a 10% decrease in cooling degree days in our western region.

	·	A $40 million net decrease in retail sales primarily due to lower industrial sales in Indiana, Ohio and Virginia as a result of the economic slowdown in the second half of 2008.
·	Margins from Off-system Sales decreased $45 million primarily due to higher trading margins realized in 2007 and the favorable effects of a fuel reconciliation in our western service territory in 2007. This decrease was partially offset by higher physical off-system sales in our eastern territory as the result of higher realized prices and higher PJM capacity revenues.
·	Transmission Revenues increased $33 million primarily due to increased rates.
·	Other Revenues increased $25 million primarily due to increased third-party engineering and construction work, an increase in pole attachment revenue and an unfavorable provision for TCC for the refund of bonded rates recorded in 2007.

·	Other Operation and Maintenance expenses decreased $35 million primarily due to the following:
	·	An $84 million decrease due to distribution expense recorded in 2007 for ice storm costs incurred in January and December 2007 and a $74 million decrease related to the deferral of these costs in the first quarter of 2008. See “Oklahoma 2007 Ice Storms” section of Note 4.
	·	A $77 million decrease related to the recording of NSR settlement costs in September 2007. We are pursuing recovery of these expenses in certain of our affected jurisdictions.
	·	A $9 million decrease related to the establishment of a regulatory asset in the third quarter of 2008 for Virginia’s share of previously expensed NSR settlement costs.
	These decreases were partially offset by:
	·	A $60 million increase in recoverable PJM expenses in Ohio.
	·	A $38 million increase in tree trimming, reliability and other transmission and distribution expenses.
	·	A $28 million increase in generation plant operations and maintenance expense.
	·	A $28 million increase in recoverable customer account expenses related to the Universal Service Fund for Ohio customers who qualify for payment assistance.
	·	A $22 million increase due to storm costs incurred in 2008 by SWEPCo and I&M.
	·	A $13 million increase in maintenance expense at the Cook Plant.
	·	A $12 million increase due to the amortization of deferred 2007 Oklahoma ice storm costs in 2008.
	·	A $10 million increase related to the write-off of the unrecoverable pre-construction costs for PSO’s cancelled Red Rock Generating Facility in the first quarter of 2008.
·	Gain on Disposition of Assets, Net decreased $19 million primarily due to the expiration of the earnings sharing agreement with Centrica from the sale of our Texas REPs in 2002. In 2007, we received the final earnings sharing payment of $20 million.
·	Depreciation and Amortization expense decreased $33 million primarily due to lower commission-approved depreciation rates in Indiana, Michigan, Oklahoma and Texas and lower Ohio regulatory asset amortization, partially offset by higher depreciable property balances and prior year adjustments related to the Virginia base rate case.
·	Interest Income increased $21 million primarily due to the favorable effect of claims for refund filed with the IRS.
·	Carrying Costs Income increased $32 million primarily due to increased carrying cost income on cost deferrals in Virginia and Oklahoma.
·	Other Income, Net increased $14 million primarily due to an increase in the equity component of AFUDC as a result of generation projects under construction.
·	Interest Expense increased $129 million primarily due to additional debt issued and higher interest rates on variable rate debt and interest expense of $47 million on off-system sales margins in accordance with the FERC’s order related to the SIA. See “Allocation of Off-system Sales Margins” section of Note 4.
·	Income Tax Expense increased $29 million due to an increase in pretax income.

Year Ended December 31, 2006			$	1,028

Changes in Gross Margin:
Retail Margins	372
Off-system Sales	69
Transmission Revenues	25
Other	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	)
Interest Income	(14	)
Carrying Costs Income	(63	)
Other Income, Net	2
Interest Expense	(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.
	·	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.

·	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 our eastern region.
·	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 $63 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 Expense increased $120 million primarily due to additional debt issued in 2006 and 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.

·	Placed AEP on negative outlook due to concern about overall credit worthiness, pending rate cases and recessionary pressures.
·	Placed OPCo, SWEPCo, TCC and TNC on review for possible downgrade due to concerns about financial metrics and pending cost and construction recoveries.
·	Affirmed the stable rating outlooks for CSPCo, I&M, KPCo and PSO.
·	Changed the rating outlook for APCo from negative to stable due to recent rate recoveries in Virginia and West Virginia.

·	During 2008, we issued 4,394,552 shares of common stock under our incentive compensation, employee savings and dividend reinvestment plans and received net proceeds of $159 million.
·	During 2008, we contributed 1,250,000 shares of common stock held in the treasury to the AEP Foundation.

·	During 2008, we issued approximately $2.8 billion of long-term debt, including $1.6 billion of senior notes at a weighted average interest rate of 6.43%, $809 million of pollution control revenue bonds ($367 million at variable rates and $442 million at a weighted average fixed interest rate of 5.67%), a variable rate $85 million 3-year term loan (3.2% at December 31, 2008) and $315 million of junior subordinated debentures at 8.75%. The proceeds from these issuances were used to fund long-term debt maturities and optional redemptions and construction programs. We also remarketed $182 million of pollution control revenue bonds with new weighted average interest rates of 4.97% under the terms of their original issuance documents.
·	During 2008, we entered into $150 million of interest rate derivatives and settled $420 million of such transactions. The settlements resulted in a net cash expenditure of $11 million. As of December 31, 2008, we had in place interest rate derivatives designated as cash flow hedges with a notional amount of $100 million in order to hedge risk exposure of variable interest rate debt.
·	At December 31, 2008, we had credit facilities totaling $3 billion to support our commercial paper program and short-term borrowing. As of December 31, 2008, we had $2 billion borrowed under the credit facilities and no commercial paper outstanding due to the current credit market. For the corporate borrowing program, the maximum amount of commercial paper outstanding during the year was $1.2 billion in May 2008 and the weighted average interest rate of commercial paper outstanding during the year was 3.32%.

·	We issued the following debt:
	·	In January 2009, I&M issued $475 million of 7% Senior Notes due 2019.
	·	In February 2009, PSO issued $34 million of 5.25% Pollution Control Bonds due 2014.
·	We retired the following debt:
	·	In January 2009, TCC retired $81 million of its outstanding Securitization Bonds.
·	Our capital investment plans for 2009 will require additional funding from the capital markets.

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Short-term Debt (a)	$	1,976	$	-	$	-	$	-	$	1,976
Interest on Fixed Rate Portion of Long-term Debt (b)		895		1,604		1,480		9,731		13,710
Fixed Rate Portion of Long-term Debt (c)		362		2,260		1,898		10,403		14,923
Variable Rate Portion of Long-term Debt (d)		85		400		-		639		1,124
Capital Lease Obligations (e)		94		119		46		149		408
Noncancelable Operating Leases (e)		336		771		437		1,671		3,215
Fuel Purchase Contracts (f)		3,788		4,832		2,590		7,362		18,572
Energy and Capacity Purchase Contracts (g)		51		73		40		268		432
Construction Contracts for Capital Assets (h)		661		993		613		-		2,267
Total	$	8,248	$	11,052	$	7,104	$	30,223	$	56,627

(a)	Represents principal only excluding interest.
(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2008 and do not reflect anticipated future refinancing, early redemptions or debt issuances.
(c)	See Note 14. Represents principal only excluding interest.
(d)	See Note 14. Represents principal only excluding interest. Variable rate debt had interest rates that ranged between 0.75% and 13.0% at December 31, 2008.
(e)	See Note 13.
(f)	Represents contractual obligations to purchase coal, natural gas and other consumables as fuel for electric generation along with related transportation of the fuel.
(g)	Represents contractual obligations for energy and capacity purchase contracts.
(h)	Represents only capital assets that are contractual obligations.

Other Commercial Commitments	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Standby Letters of Credit (a)	$	433	$	1	$	-	$	-	$	434
Guarantees of the Performance of Outside Parties (b)		-		-		-		65		65
Guarantees of Our Performance (c)		790		1,082		20		27		1,919
Total Commercial Commitments	$	1,223	$	1,083	$	20	$	92	$	2,418

(a)	We enter into standby letters of credit. These letters of credit cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. As the Parent, we issued all of these letters of credit in our ordinary course of business on behalf of our subsidiaries. The maximum future payments of these letters of credit are $434 million with maturities ranging from March 2009 to March 2010. 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. See “Letters of Credit” section of Note 6.
(b)	See “Guarantees of Third-Party Obligations” section of Note 6.
(c)	We issued performance guarantees and indemnifications for energy trading and various sale agreements.

Project Name	Location	Projected Completion Date	Owners (Ownership %)	Total Estimated Project Costs at Completion			AEP’s Equity Method Investment at December 31, 2008		Approved Return on Equity
				(in thousands)
ETT	Texas (ERCOT)	2017	MEHC (50%) AEP (50%)	$	1,300,000	(a)	$	15,445		9.96	%

PATH (b)	Ohio/West Virginia	2013	Allegheny Energy (50%) AEP (50%)		1,800,000	(c)		6,463		14.3	%

Tallgrass	Oklahoma	2013	OGE Energy (50%) ETA (50%) (d)		500,000			109		12.8	%

Prairie Wind	Kansas	2013	Westar Energy (50%) ETA (50%) (d)		600,000			31		12.8	%

Pioneer	Indiana	2015	Duke Energy (50%) AEP (50%)		1,000,000			-	(e)