-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, IiVsHFq5TeJ2P/E8clpnbj0+krjJa34eJ5wfpOLmpLPrUG69OJQ62Sw4zgdz7kFr ECjSuTG/eiP1cO4XPZWsQA== 0000004904-09-000065.txt : 20090409 0000004904-09-000065.hdr.sgml : 20090409 20090409131647 ACCESSION NUMBER: 0000004904-09-000065 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 20081231 ITEM INFORMATION: Financial Statements and Exhibits FILED AS OF DATE: 20090409 DATE AS OF CHANGE: 20090409 FILER: COMPANY DATA: COMPANY CONFORMED NAME: AMERICAN ELECTRIC POWER CO INC CENTRAL INDEX KEY: 0000004904 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 134922640 STATE OF INCORPORATION: NY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03525 FILM NUMBER: 09742007 BUSINESS ADDRESS: STREET 1: 1 RIVERSIDE PLAZA CITY: COLUMBUS STATE: OH ZIP: 43215 BUSINESS PHONE: 614-716-1000 MAIL ADDRESS: STREET 1: 1 RIVERSIDE PLAZA CITY: COLUMBUS STATE: OH ZIP: 43215 FORMER COMPANY: FORMER CONFORMED NAME: KINGSPORT UTILITIES INC DATE OF NAME CHANGE: 19660906 8-K 1 aep8kxbrl123108.htm FORM 8-K aep8kxbrl123108.htm
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549


FORM 8-K


CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934


Date of report (Date of earliest event reported)
April 9, 2009

AMERICAN ELECTRIC POWER COMPANY, INC.
(Exact Name of Registrant as Specified in Its Charter)

1-3525
New York
13-4922640
(Commission File Number)
(State or Other Jurisdiction of Incorporation)
(IRS Employer Identification No.)

1 Riverside Plaza, Columbus, OH
43215
(Address of Principal Executive Offices)
(Zip Code)

614-716-1000
(Registrant’s Telephone Number, Including Area Code)

None
(Former Name or Former Address, if Changed Since Last Report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

[ ]           Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[ ]           Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[ ]
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

[ ]
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 
 
 

Item 8.01                      Other Events.

Exhibits 100 to this Current Report on Form 8-K consists of documents formatted in Extensible Business Reporting Language (XBRL) containing certain financial information from the Annual Report on Form 10-K of American Electric Power Company, Inc. (AEP) for the year ended December 31, 2008, filed with the Securities and Exchange Commission (SEC) on February 27, 2009.  The information includes the (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Changes in Common Shareholders’ Equity and Comprehensive Income (Loss), (iv) Consolidated Statements of Cash Flows and (v) Notes to Consolidated Financial Statements.

Users of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited and these are not the financial statements of AEP as filed with the SEC.  The purpose of submitting these XBRL-related documents is to test the related format and technology and, as a result, investors should not rely on the information in this Current Report on Form 8-K, including Exhibit 100, in making investment decisions.

In accordance with Rule 402 of Regulation S-T, the information in this Current Report on Form 8-K, including Exhibit 100, shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

Item 9.01                      Financial Statements and Exhibits.

(d) Exhibits

The following exhibit is furnished herewith:

Exhibit 100
The following materials from the Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2008, filed on February 27, 2009 formatted in XBRL:  the (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Changes in Common Shareholders’ Equity and Comprehensive Income (Loss), (iv) Consolidated Statements of Cash Flows and (v) Notes to Consolidated Financial Statements.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


 
AMERICAN ELECTRIC POWER COMPANY, INC.
 
By:
/s/ Joseph M. Buonaiuto                     
 
Name:
Joseph M. Buonaiuto
 
Title
Senior Vice President, Controller and
Chief Accounting Officer
April 9, 2009

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N.M.1,203 3 N.M. N.M.Other 2,705 1,265 4.9 - 11.3% 5 -55 1,036 396 N.M. N.M.Total $ 37,879 $ 12,690 $11,831 $ 4,033 2007 Regulated Nonregulated Functional Class of Property Property,Plant andEquipment Accumulated Depreciation Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Property,Plant andEquipment Accumulated Depreciation Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in millions) (in years) (in millions)(in years)Production $ 11,278 $ 5,816 2.0 - 3.8%9 - 132 $ 8,955 $ 3,462 2.0 - 5.1%20 - 121Transmission 7,392 2,308 1.3 - 3.0%25 - 87 - - - - Distribution 12,056 3,116 3.0 - 3.9%11 - 75 - - - - CWIP 1,864 (57) N.M. N.M.1,155 2 N.M. N.M.Other 2,410 1,105 4.8 - 11.3% 5 -55 1,035 523 N.M. N.M.Total $ 35,000 $ 12,288 $11,145 $ 3,987 2006 Regulated Nonregulated Functional Class of Property Annual Composite Depreciation Rate RangesDepreciable Life Ranges Annual Composite Depreciation Rate RangesDepreciable Life Ranges (in years) (in years) Production 2.6 - 3.8% 30 - 121 2.57 - 9.15%20 - 121Transmission 1.6 - 2.9% 25 - 87 - -Distribution 3.0 - 4.0% 11 - 75 - -Other 6.7 - 11.5% 24 - 55 N.M. N.M. N.M. = Not Meaningful We provide for depreciation, depletion and amortization of coal-mining assetsover each asset's estimated useful life or the estimated life of each mine,whichever is shorter, using the straight-line method for mining structures andequipment. We use either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based onestimated recoverable tonnages. We include these costs in the cost of coalcharged to fuel expense. Prior to 2008, the lignite mine of DHLC was scheduledto be shut down in May 2011. In December 2007, the LPSC unanimously voted toextend the life of the lignite mine of DHLC through 2016. In December 2008, wereceived the final order. The average amortization rate for coal rights andmine development costs was $0.26 per ton in 2008 and $0.66 per ton in 2007 and2006. For cost-based rate-regulated operations, the composite depreciation rategenerally includes a component for non-asset retirement obligation (non-ARO)removal costs, which is credited to Accumulated Depreciation and Amortization.Actual removal costs incurred are charged to Accumulated Depreciation andAmortization. Any excess of accrued non-ARO removal costs over actual removalcosts incurred is reclassified from Accumulated Depreciation and Amortizationand reflected as a regulatory liability. For nonregulated operations, non-AROremoval costs are expensed as incurred. Asset Retirement Obligations (ARO) We record ARO in accordance with SFAS 143 "Accounting for Asset RetirementObligations" and FIN 47 "Accounting for Conditional Asset Retirement Obligations" for our legal obligations for asbestos removal and for theretirement of certain ash ponds, wind farms and certain coal mining facilities,as well as for nuclear decommissioning of our Cook Plant. We have identified,but not recognized, ARO liabilities related to electric transmission anddistribution assets, as a result of certain easements on property on which wehave assets. Generally, such easements are perpetual and require only theretirement and removal of our assets upon the cessation of the property's use.We do not estimate the retirement for such easements because we plan to use ourfacilities indefinitely. The retirement obligation would only be recognized ifand when we abandon or cease the use of specific easements, which is notexpected. The following is a reconciliation of the 2008 and 2007 aggregate carryingamounts of ARO: Carrying Amount of ARO (in millions) ARO at December 31, 2006 $ 1,028Accretion Expense 58Liabilities Incurred 4Liabilities Settled (17)Revisions in Cash Flow Estimates 5ARO at December 31, 2007 (a) 1,078Accretion Expense 60Liabilities Incurred 22Liabilities Settled (34)Revisions in Cash Flow Estimates 32ARO at December 31, 2008 (b) $ 1,158 (a) The current portion of our ARO, totaling $3 million, is included inOther in the Current Liabilities section of our 2007 Consolidated Balance Sheet.(b) The current portion of our ARO, totaling $4 million, is included inOther in the Current Liabilities section of our 2008 Consolidated Balance Sheet. As of December 31, 2008 and 2007, our ARO liability was $1.2 billion and $1.1billion, respectively, and included $891 million and $846 million, respectively,for nuclear decommissioning of the Cook Plant. As of December 31, 2008 and2007, the fair value of assets that are legally restricted for purposes ofsettling the nuclear decommissioning liabilities totaled $1 billion and $1.1billion, respectively, relating to the Cook Plant and are recorded in SpentNuclear Fuel and Decommissioning Trusts on our Consolidated Balance Sheets. Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization Our amounts of allowance for borrowed and equity funds used during constructionis summarized in the following table: Years Ended December 31, 2008 20072006 (in millions)Allowance for Equity Funds Used During Construction $ 45 $33 $ 30Allowance for Borrowed Funds Used During Construction 7579 82 Jointly-owned Electric Utility Plants We have generating units that are jointly-owned with nonaffiliated companies.We are obligated to pay a share of the costs of these jointly-owned facilitiesin the same proportion as our ownership interest. Our proportionate share ofthe operating costs associated with such facilities is included in ourConsolidated Statements of Income and the investments and accumulated depreciation are reflected in our Consolidated Balance Sheets under Property,Plant and Equipment as follows: Company's Share at December 31, 2008 FuelType Percent of Ownership Utility Plant in ServiceConstruction Work in Progress (i) AccumulatedDepreciation (in millions)W.C. Beckjord Generating Station (Unit No. 6) (a) Coal 12.5%$ 18 $ 2 $ 8Conesville Generating Station (Unit No. 4) (b) Coal 43.5%86 173 51J.M. Stuart Generating Station (c) Coal 26.0% 47824 144Wm. H. Zimmer Generating Station (a) Coal 25.4% 7624 344Dolet Hills Generating Station (Unit No. 1) (d) Lignite 40.2%255 1 182Flint Creek Generating Station (Unit No. 1) (e) Coal 50.0%103 10 62Pirkey Generating Station (Unit No. 1) (e) Lignite 85.9%491 8 336Oklaunion Generating Station (Unit No. 1) (f) Coal 70.3%383 7 192Turk Generating Plant (g) Coal 73.33% -510 -Transmission N/A (h) 70 -46 Company's Share at December 31, 2007 FuelType Percent of Ownership Utility Plant in ServiceConstruction Work in Progress (i) AccumulatedDepreciation (in millions)W.C. Beckjord Generating Station (Unit No. 6) (a) Coal 12.5%$ 16 $ 1 $ 8Conesville Generating Station (Unit No. 4) (b) Coal 43.5%84 84 50J.M. Stuart Generating Station (c) Coal 26.0% 296157 134Wm. H. Zimmer Generating Station (a) Coal 25.4% 7631 324Dolet Hills Generating Station (Unit No. 1) (d) Lignite 40.2%241 11 175Flint Creek Generating Station (Unit No. 1) (e) Coal 50.0%98 3 60Pirkey Generating Station (Unit No. 1) (e) Lignite 85.9%486 4 325Oklaunion Generating Station (Unit No. 1) (f) Coal 70.3%379 2 186Turk Generating Plant (g) Coal 73.33% -272 -Transmission N/A (h) 63 644 (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) Operated by Cleco Corporation, a nonaffiliated company. (e) Operated by SWEPCo.(f) Operated by PSO and also jointly-owned (54.7%) by TNC. (g) Turk Generating Plant is currently under construction with a projectedcommercial operation date of 2012. SWEPCo jointly owns the plant with ArkansasElectric 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.(h) Varying percentages of ownership.(i) Primarily relates to construction of Turk Generating Plant andenvironmental upgrades including the installation of flue gas desulfurizationprojects at Conesville Generating Station and J.M. Stuart Generating Station. N/A = Not Applicable BENEFIT PLANS We sponsor two qualified pension plans that we merged at December 31, 2008 andtwo unfunded nonqualified pension plans. A substantial majority of ouremployees are covered by either one qualified plan or both a qualified and anonqualified pension plan. We sponsor OPEB plans to provide medical and lifeinsurance benefits for retired employees. We adopted SFAS 158 in December 2006 and recognized the obligations associatedwith our defined benefit pension plans and OPEB plans in the balance sheets. Werecognize an asset for a plan's overfunded status or a liability for a plan'sunderfunded 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 arenot recognized as a component of net periodic benefit cost. We record a SFAS 71regulatory asset for qualifying SFAS 158 costs of our regulated operations thatfor ratemaking purposes are deferred for future recovery. The effect of SFAS158 on our 2006 financial statements was a pretax AOCI adjustment of $1,236million that was offset by a SFAS 71 regulatory asset of $875 million and adeferred income tax asset of $126 million resulting in a net of tax AOCI equityreduction of $235 million. SFAS 158 requires adjustment of pretax AOCI at the end of each year, for bothunderfunded and overfunded defined benefit pension and OPEB plans, to an amountequal to the remaining unrecognized deferrals for unamortized actuarial lossesor gains, prior service costs and transition obligations, such that remainingdeferred costs result in an AOCI equity reduction and deferred gains result inan AOCI equity addition. The year-end AOCI measure can be volatile based onfluctuating market conditions, investment returns and discount rates.The following tables provide a reconciliation of the changes in the plans'projected benefit obligations and fair value of assets over the two-year periodending at the plan's measurement date of December 31, 2008, and their fundedstatus as of December 31 of each year: Projected Plan Obligations, Plan Assets, Funded Status as of December 31, 2008and 2007 Pension Plans Other Postretirement Benefit Plans 2008 2007 2008 2007 Change in Projected Benefit Obligation (in millions) Projected Obligation at January 1 $ 4,109 $ 4,108$ 1,773 $ 1,818Service Cost 100 96 4242Interest Cost 249 235 113104Actuarial Loss (Gain) 139 (64) 2(91)Plan Amendments - 18 --Benefit Payments (296) (284)(120) (130)Participant Contributions - - 2422Medicare Subsidy - - 98Projected 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 $ 1,302Actual Gain (Loss) on Plan Assets (1,054) 435(368) 115Company Contributions 7 7 8291Participant Contributions - - 2422Benefit 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) We have significant investments in several trust funds to provide for futurepension and OPEB payments. All of our trust funds' investments are diversifiedand managed in compliance with all laws and regulations. The value of theinvestments in these trusts declined substantially in 2008 due to decreases indomestic and international equity markets. Although the asset values are lower,this decline has not affected the funds' ability to make their requiredpayments. Amounts Recognized on the 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 BenefitLiability (1,131) (79) (821)(369)Funded (Underfunded) Status $ (1,140) $ 395$ (825) $ (373) SFAS 158 Amounts Recognized in Accumulated Other Comprehensive Income (AOCI) asof December 31, 2008, 2007 and 2006 Other Postretirement Pension Plans Benefit Plans 2008 2007 2006 2008 20072006Components (in millions)Net Actuarial Loss $ 2,024 $ 534 $ 759$ 715 $ 231 $ 354Prior Service Cost (Credit) 13 14 (5)3 4 4Transition Obligation - - -70 97 124Pretax AOCI $ 2,037 $ 548 $ 754$ 788 $ 332 $ 482 Recorded as Regulatory Assets $ 1,660 $ 453 $ 582$ 502 $ 204 $ 293Deferred Income Taxes 132 33 60100 45 66Net of Tax AOCI 245 62 112186 83 123Pretax AOCI $ 2,037 $ 548 $ 754$ 788 $ 332 $ 482 Components of the Change in Plan Assets and Benefit Obligations Recognized inPretax AOCI during the years ended December 31, 2008 and 2007 are as follows: Other Postretirement Pensions Plans Benefit Plans 2008 2007 2008 2007Components (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 our pension plans at the end of 2008 and 2007, and thetarget allocation for 2009, by asset category, are as follows: Target Allocation Percentage of Plan Assets at YearEnd 2009 2008 2007Asset CategoryEquity 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 our OPEB plans at the end of 2008 and 2007, and targetallocation for 2009, by asset category, are as follows: Target Allocation Percentage of Plan Assets at YearEnd 2009 2008 2007Asset CategoryEquity Securities 65% 53% 62%Debt Securities 34% 43% 35%Cash and Cash Equivalents 1% 4%3%Total 100% 100% 100% Our investment strategy for our employee benefit trust funds is to use adiversified portfolio of investments to achieve an acceptable rate of returnwhile managing the interest rate sensitivity of the plans' assets relative tothe plans' liabilities. To minimize investment risk, our employee benefit trustfunds are broadly diversified among classes of assets, investment strategies andinvestment managers. We regularly review the actual asset allocation andperiodically rebalance the investments to our targeted allocation whenconsidered appropriate. Our investment policies and guidelines allow investmentmanagers in approved strategies to use financial derivatives to obtain or managemarket exposures and to hedge assets and liabilities. Our investment policiesprohibit the benefit trust funds from purchasing AEP securities (with theexception of proportionate and immaterial holdings of AEP securities in passiveindex strategies). However, our investment policies do not preclude the benefittrust funds from receivin g contributions in the form of AEP securities, providedthat the AEP securities acquired by each plan may not exceed the limitationsimposed by law, including ERISA. The value of our pension plans' assets decreased substantially to $3.2 billionat December 31, 2008 from $4.5 billion at December 31, 2007. The qualifiedplans paid $289 million in benefits to plan participants during 2008(nonqualified plans paid $7 million in benefits). The value of our OPEB plans'assets decreased substantially to $1 billion at December 31, 2008 from $1.4billion at December 31, 2007. The OPEB plans paid $120 million in benefits toplan participants during 2008. We base our determination of pension expense or income on a market-relatedvaluation of assets which reduces year-to-year volatility. This market-relatedvaluation recognizes investment gains or losses over a five-year period from theyear in which they occur. Investment gains or losses for this purpose are thedifference between the expected return calculated using the market-related valueof 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 afive-year period, the future value of assets will be impacted as previouslydeferred 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 our underfunded pension plans that had an accumulated benefit obligation inexcess of plan assets, the projected benefit obligation, accumulated benefitobligation, and fair value of plan assets of these plans at December 31, 2008and 2007 were as follows: Underfunded Pension Plans December 31, 2008 2007 (in millions)Projected Benefit Obligation $ 4,301 $ 81 Accumulated Benefit Obligation $ 4,199 $ 77Fair 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 ofour benefit obligations are shown in the following tables: Pension Plans Other Postretirement Benefit Plans December 31, December 31, 2008 2007 2008 2007AssumptionDiscount Rate 6.00% 6.00% 6.10% 6.20%Rate of Compensation Increase 5.90% (a) 5.90% (a) N/AN/A (a) Rates are for base pay only. In addition, an amount is added to reflecttarget incentive compensation for exempt employees and overtime and incentivepay for nonexempt employees. N/A = Not Applicable To determine a discount rate, we use a duration-based method by constructing ahypothetical portfolio of high quality corporate bonds similar to those includedin the Moody's Aa bond index with a duration matching the benefit planliability. The composite yield on the hypothetical bond portfolio is used asthe discount rate for the plan. For 2008, the rate of compensation increase assumed varies with the age of theemployee, ranging from 5% per year to 11.5% per year, with an average increaseof 5.9%. Estimated Future Benefit Payments and Contributions Information about the 2009 expected cash flows for the pension (qualified andnonqualified) and OPEB plans is as follows: Other Postretirement Pension Plans Benefit PlansEmployer Contribution (in millions)Required Contributions (a) $ 9 $ 4 Additional Discretionary Contributions - 158 (a) Contribution required to meet minimum funding requirement under ERISAplus direct payments for unfunded benefits. The contribution to the pension plans is based on the minimum amount required byERISA plus the amount to pay unfunded nonqualified benefits. The contributionto the OPEB plans is generally based on the amount of the OPEB plans' periodicbenefit cost for accounting purposes as provided for in agreements with stateregulatory authorities, plus the additional discretionary contribution of ourMedicare subsidy receipts. The table below reflects the total benefits expected to be paid from the plan orfrom our assets, including both our share of the benefit cost and theparticipants' share of the cost, which is funded by participant contributions tothe plan. Medicare subsidy receipts are shown in the year of the correspondingbenefit payments, even though actual cash receipts are expected early in thefollowing year. Future benefit payments are dependent on the number ofemployees retiring, whether the retiring employees elect to receive pensionbenefits as annuities or as lump sum distributions, future integration of thebenefit plans with changes to Medicare and other legislation, future levels ofinterest rates, and variances in actuarial results. The estimated payments forpension 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 our 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 20072006 (in millions)Service Cost $ 100 $ 96 $ 97 $42 $ 42 $ 39Interest Cost 249 235 231113 104 102Expected Return on Plan Assets (336) (340)(335) (111) (104) (94) Amortization of Transition Obligation - -- 27 27 27Amortization of Prior Service Cost (Credit) 1 -(1) - - -Amortization of Net Actuarial Loss 37 5979 9 12 22Net Periodic Benefit Cost 51 50 7180 81 96Capitalized 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 ourplans during 2009 are shown in the following table: Other Postretirement Pension Plans Benefit PlansComponents (in millions)Net Actuarial Loss $ 56 $ 46Prior Service Cost 1 1Transition Obligation - 27Total Estimated 2009 Pretax AOCI Amortization $ 57 $74 Expected to be Recorded as Regulatory Asset $ 46 $ 48Deferred Income Taxes 4 9Net of Tax AOCI 7 17Total $ 57 $ 74 Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions as of January 1, used in the measurement of ourbenefit costs are shown in the following tables: Other Postretirement Pension Plans Benefit Plans 2008 2007 2006 2008 20072006Discount 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 evaluatinghistorical returns, the current investment climate (yield on fixed incomesecurities 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 plansmeasurement purposes are shown below:Health Care Trend Rates 2008 2007Initial 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 amountsreported for the OPEB health care plans. A 1% change in assumed health carecost trend rates would have the following effects: 1% Increase 1% Decrease (in millions) Effect on Total Service and Interest Cost Components of Net PeriodicPostretirement Health Care Benefit Cost $ 20 $ (16) Effect on the Health Care Component of the Accumulated Postretirement BenefitObligation 196 (163) American Electric Power System Retirement Savings Plan We sponsor the American Electric Power System Retirement Savings Plan, a definedcontribution retirement savings plan for substantially all employees who are notmembers of the United Mine Workers of America (UMWA). It is a qualified planoffering participants an opportunity to contribute a portion of their pay withfeatures under Section 401(k) of the Internal Revenue Code. We providedmatching contributions of 75% of the first 6% of eligible compensation contributed by an employee in 2008. Effective January 1, 2009, we match thefirst 1% of eligible employee contributions at 100% and the next 5% ofcontributions at 70%. The cost for company matching contributions totaled $71million in 2008, $66 million in 2007 and $62 million in 2006. UMWA Benefits We provide UMWA pension, health and welfare benefits for certain unionizedmining employees, retirees, and their survivors who meet eligibility requirements. UMWA trustees make final interpretive determinations with regardto all benefits. The pension benefits are administered by UMWA trustees andcontributions are made to their trust funds. The health and welfare benefits are administered by us and benefits are paidfrom our general assets. Contributions were not material in 2008, 2007 and 2006. 97000000 67000000 63000000 0 85000000 0 -94000000 -21000000 56000000 -34000000 66000000 -1000000 0 0 209000000 2011000000 1657000000 1477000000 1483000000 1513000000 1467000000 3847000000 3138000000 1297000000 1324000000 1066000000 1117000000 90000000 60000000 411000000 178000000 301000000 401000000 FINANCING ACTIVITIES Common Stock We issued 68 thousand, 2.4 million and 2.3 million shares of common stock inconnection with our stock option plan during 2008, 2007 and 2006, respectively. Set forth below is a reconciliation of common stock share activity for the yearsended December 31, 2008, 2007 and 2006:Shares of Common Stock Issued Held in Treasury Balance, January 1, 2006 415,218,830 21,499,992Issued 2,955,898 -Balance, December 31, 2006 418,174,728 21,499,992Issued 3,751,968 -Balance, December 31, 2007 421,926,696 21,499,992Issued 4,394,552 -Treasury Stock Contributed to AEP Foundation - (1,250,000)Balance, December 31, 2008 426,321,248 20,249,992 Preferred Stock Information about the components of preferred stock of our subsidiaries is asfollows: December 31, 2008 Call Price Per Share (a) Shares Authorized (b) Shares Outstanding (c) Amount(in millions)Not Subject to Mandatory Redemption:4.00% - 5.00% $102-$110 1,525,903 606,878 $61 December 31, 2007 Call Price Per Share (a) Shares Authorized (b) Shares Outstanding (c) Amount(in millions)Not Subject to Mandatory Redemption:4.00% - 5.00% $102-$110 1,525,903 606,878 $61 (a) At the option of the subsidiary, the shares may be redeemed at the callprice plus accrued dividends. The involuntary liquidation preference is $100per share for all outstanding shares.(b) As of December 31, 2008 and 2007, our subsidiaries had 14,488,045 sharesof $100 par value preferred stock, 22,200,000 shares of $25 par value preferredstock and 7,822,480 shares of no par value preferred stock that were authorizedbut unissued.(c) There were no shares of preferred stock redeemed in 2008. The number ofshares of preferred stock redeemed was 166 shares in 2007 and 598 shares in2006. Long-term Debt Weighted Average Interest Rate December 31, Interest Rate Ranges at December 31,Outstanding atDecember 31, 2008 2008 2007 2008 2007Type of Debt and Maturity (in millions)Senior Unsecured Notes (a)2008-2011 5.07% 4.3875%-6.60% 3.60%-6.60% $2,065 $ 2,4942012-2018 5.58% 4.85%-6.375% 4.85%-6.375% 4,548 3,9182019-2038 6.38% 5.625%-7.00% 5.625%-6.70% 4,456 3,493 Pollution Control Bonds (b) 2008-2011 (c) 5.69% 4.15%-7.125% 4.15%-4.50%336 1312012-2024 (c) 4.03% 0.75%-6.05% 3.70%-6.05% 775 8112025-2042 5.67% 0.85%-13.00% 3.80%-6.00% 835 1,248 Notes Payable (d) 2008-2024 6.66% 4.47%-7.49% 4.47%-9.60%233 311 Securitization Bonds (e) 2008-2020 5.34% 4.98%-6.25% 4.98%-6.25%2,132 2,257 Junior Subordinated Debentures (f) 2063 8.75% 8.75% - 315 - First Mortgage Bonds (g) 2008 - - 7.125% - 19 Notes Payable to Trust 2043 - - 5.25% - 113 Spent Nuclear Fuel Obligation (h) 264 259 Other Long-term Debt (i)2011-2026 3.50% 3.20125%-13.718% 13.718% 88 2 Unamortized Discount (net) (64)(62)Total Long-term Debt Outstanding15,983 14,994Less Portion Due Within One Year 447792Long-term Portion $ 15,536 $14,202 (a) Certain senior unsecured notes have been adjusted for MTM of Fair ValueHedges associated with the debt.(b) For certain series of pollution control bonds, interest rates aresubject to periodic adjustment. Certain series may be purchased on demand atperiodic interest adjustment dates. Letters of credit from banks, standby bondpurchase agreements and insurance policies support certain series. (c) Certain pollution control bonds are subject to mandatory redemptionearlier than the maturity date. Consequently, these bonds have been classifiedfor maturity and repayment purposes based on the mandatory redemption date.(d) Notes payable represent outstanding promissory notes issued under termloan agreements and revolving credit agreements with a number of banks and otherfinancial institutions. At expiration, all notes then issued and outstandingare due and payable. Interest rates are both fixed and variable. Variablerates generally relate to specified short-term interest rates. (e) In October 2006, AEP Texas Central Transition Funding II LLC (TFII), asubsidiary of TCC, issued $1.7 billion in securitization bonds with interestrates ranging from 4.98% to 5.3063% and final maturity dates ranging fromJanuary 2012 to July 2021. Scheduled final payment dates range from January2010 to July 2020. TFII is the sole owner of the transition charges and theoriginal transition property. The holders of the securitization bonds do nothave recourse to any assets or revenues of TCC. The creditors of TCC do nothave recourse to any assets or revenues of TFII, including, without limitation,the original transition property.(f) The net proceeds from the sale of junior subordinated debentures wereused for general corporate purposes including the payment of short-termindebtedness.(g) In May 2004, cash and treasury securities were deposited with a trusteeto defease all of TCC's outstanding first mortgage bonds. The defeased TCCfirst mortgage bonds had a balance of $19 million in 2007. The defeased TCCfirst mortgage bonds were retired in February 2008. Trust fund assets relatedto this obligation of $22 million are included in Other Temporary Investments onour Consolidated Balance Sheets at December 31, 2007.(h) Spent nuclear fuel obligation consists of a liability along with accruedinterest for disposal of spent nuclear fuel (see Note 9).(i) Other long-term debt in 2007 and 2008 consists of a financing obligationunder a sale and leaseback agreement. In 2008, AEGCo issued an $85 million3-year credit facility to be used for working capital and other generalcorporate purposes. LONG-TERM DEBT OUTSTANDING AT DECEMBER 31, 2008 IS PAYABLE AS FOLLOWS: 2009 2010 2011 2012 2013After 2013 Total (in millions)Principal Amount $ 447 $ 1,851 $ 809$ 601 $ 1,297 $ 11,042 $ 16,047Unamortized Discount(64)Total Long-term Debt Outstanding at December 31, 2008$ 15,983 In January 2009, I&M issued $475 million of 7.00% Senior Unsecured Notes due in2019. In January 2009, TCC retired $50 million of 4.98% and $31 million of 5.56%Securitization Bonds due in 2010. In February 2009, PSO reissued $34 million of 5.25% Pollution Control Bonds duein 2014. In the first quarter of 2008, bond insurers' exposure in connection withdevelopments in the subprime credit market resulted in increasing occurrences offailed auctions for tax-exempt long-term debt sold at auction rates.Consequently, we chose to exit the auction-rate debt market and reduced ouroutstanding auction-rate securities from the December 2007 balance by $1.2billion. As of December 31, 2008, $272 million of our auction-rate tax-exemptlong-term debt, with rates ranging between 2.034% and 13%, remained outstandingwith rates reset every 35 days. The instruments under which the bonds areissued allow us to convert to other short-term variable-rate structures,term-put structures and fixed-rate structures. As of December 31, 2008, $367million of the prior auction-rate debt was issued in a weekly variable rate modesupported by letters of credit at variable rates ranging from 0.85% to 1.52%,$495 million was issued at fixed rates ranging from 4.5% to 5.625% and trusteesheld, on our behalf, approximately $33 0 million of our reacquired auction-ratetax-exempt long-term debt which we plan to reissue to the public as marketconditions permit. As of December 31, 2008, approximately $218 million of the $272 million ofoutstanding auction-rate debt relates to a lease structure with JMG that we areunable to refinance without their consent. The rates for this debt range from6.388% to 13%. The initial term for the JMG lease structure matures on March31, 2010. We are evaluating whether to terminate this facility prior tomaturity. Termination of this facility requires approval from the PUCO. Dividend Restrictions Under the Federal Power Act, AEP's public utility subsidiaries are restrictedfrom 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 implementationof FIN 46R. The SWEPCo trust, which held mandatorily redeemable trust preferredsecurities, is reported as two components on our Consolidated Balance Sheets.The investment in the trust, which was $3 million as of December 31, 2007, isincluded in Deferred Charges and Other within Other Noncurrent Assets. TheJunior Subordinated Debentures, in the amount of $113 million as of December 31,2007, are reported as Notes Payable to Trust within Long-term Debt. Both theinvestment in the trust and the Junior Subordinated Debentures were retired in2008. Lines of Credit and Short-term Debt We use our corporate borrowing program to meet the short-term borrowing needs ofour subsidiaries. The corporate borrowing program includes a Utility MoneyPool, which funds the utility subsidiaries, and a Nonutility Money Pool, whichfunds the majority of the nonutility subsidiaries. In addition, we also fund,as direct borrowers, the short-term debt requirements of other subsidiaries thatare not participants in either money pool for regulatory or operational reasons.As of December 31, 2008, we had credit facilities totaling $3 billion to supportour commercial paper program (see "Credit Facilities" section below). For thecorporate borrowing program, the maximum amount of commercial paper outstandingduring 2008 was $1.2 billion and the weighted average interest rate ofcommercial paper outstanding during the year was 3.32%. No commercial paper wasoutstanding at December 31, 2008 due to market conditions. In 2008, we borrowed$2 billion under these credit facilities. Our outstanding short-term debt wasas foll ows: December 31, 2008 2007 Outstanding Interest Outstanding Interest Amount Rate (a) Amount Rate (a)Type of Debt (in thousands) (in thousands)Commercial Paper - AEP $ - - $ 659,1355.54%Commercial Paper - JMG (b) - - 7015.35%Line of Credit - Sabine Mining Company (c) 7,172 1.54% 285 5.25%Lines of Credit - AEP 1,969,000 2.28% (d)- -Total $ 1,976,172 $ 660,121 (a) Weighted average rate. (b) This commercial paper is specifically associated with the Gavin Scrubberand is backed by a separate credit facility. This commercial paper does notreduce available liquidity under AEP's credit facilities.(c) Sabine Mining Company is consolidated under FIN 46R. This line ofcredit does not reduce available liquidity under AEP's credit facilities.(d) Rate based on LIBOR. Credit Facilities As of December 31, 2008, in support of our commercial paper program, we had two$1.5 billion credit facilities which were reduced by Lehman Brothers HoldingsInc.'s commitment amount of $46 million following its bankruptcy. In March2008, the credit facilities were amended so that $750 million may be issuedunder each credit facility as letters of credit. In April 2008, we entered into a $650 million 3-year credit agreement and a $350million 364-day credit agreement which were reduced by Lehman Brothers HoldingsInc.'s commitment amount of $23 million and $12 million, respectively, followingits bankruptcy. Under the facilities, we may issue letters of credit. As ofDecember 31, 2008, $372 million of letters of credit were issued by subsidiariesunder the 3-year credit agreement to support variable rate Pollution ControlBonds. Sale of Receivables - AEP Credit AEP Credit has a sale of receivables agreement with banks and commercial paperconduits. Under the sale of receivables agreement, AEP Credit sells an interestin the receivables it acquires from affiliated utility subsidiaries to thecommercial paper conduits and banks and receives cash. This transactionconstitutes a sale of receivables in accordance with SFAS 140, "Accounting forTransfers and Servicing of Financial Assets and Extinguishments of Liabilities,"allowing the receivables to be taken off of AEP Credit's balance sheet and ourConsolidated Balance Sheets and allowing AEP Credit to repay any debtobligations to the affiliated utility subsidiaries. We have no ownershipinterest in the commercial paper conduits and are not required to consolidatethese entities in accordance with GAAP. AEP Credit continues to service thereceivables. We entered into this off-balance sheet transaction to allow AEPCredit to repay its outstanding debt obligations, continue to purchase ouroperating companies' receivables, and accelerate AEP Credit's cash collections. In October 2008, we renewed AEP Credit's sale of receivables agreement. Thesale of receivables agreement provides a commitment of $700 million from banksand commercial paper conduits to purchase receivables from AEP Credit. Thisagreement will expire in October 2009. We intend to extend or replace the saleof receivables agreement. The previous sale of receivables agreement, whichexpired in October 2008 and was extended until October 2009, provided acommitment of $650 million from banks and commercial paper conduits to purchasereceivables from AEP Credit. Under the previous sale of receivable agreement,the commitment increased to $700 million for the months of August and Septemberto accommodate seasonal demand. At December 31, 2008, $650 million ofcommitments to purchase accounts receivable were outstanding under thereceivables agreement. AEP Credit maintains a retained interest in thereceivables sold and this interest is pledged as collateral for the collectionof receivables sold. The fair value of th e retained interest is based on bookvalue due to the short-term nature of the accounts receivable less an allowancefor anticipated uncollectible accounts. AEP Credit purchases accounts receivable through purchase agreements with CSPCo,I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does nothave regulatory authority to sell accounts receivable in all of its regulatoryjurisdictions, only a portion of APCo's accounts receivable are sold to AEPCredit. Comparative accounts receivable information for AEP Credit is as follows: Years Ended December 31, 2008 2007 2006 ($ in millions)Proceeds from Sale of Accounts Receivable $ 7,717 $6,970 $ 6,849Loss on Sale of Accounts Receivable 20 3331Average Variable Discount Rate 3.19% 5.39%5.02% December 31, 2008 2007 (in millions)Accounts Receivable Retained Interest and Pledged as Collateral LessUncollectible Accounts $ 118 $ 71Deferred Revenue from Servicing Accounts Receivable 11Retained Interest if 10% Adverse Change in Uncollectible Accounts 116 68Retained Interest if 20% Adverse Change in Uncollectible Accounts 114 66 Historical loss and delinquency amounts for the AEP System's customer accountsreceivable managed portfolio is as follows: December 31, 2008 2007 (in millions)Customer Accounts Receivable Retained $ 569 $ 730Accrued Unbilled Revenues Retained 449 379Miscellaneous Accounts Receivable Retained 90 60Allowance for Uncollectible Accounts Retained (42) (52)Total Net Balance Sheet Accounts Receivable 1,066 1,117Customer Accounts Receivable Securitized 650 507Total Accounts Receivable Managed $ 1,716 $ 1,624 Net Uncollectible Accounts Written Off $ 37 $ 24 Customer accounts receivable retained and securitized for the electric operatingcompanies are managed by AEP Credit. Miscellaneous accounts receivable havebeen fully retained and not securitized. Delinquent customer accounts receivable for the electric utility affiliates thatAEP Credit currently factors were $22 million and $30 million at December 31,2008 and 2007, respectively. AEP Credit's delinquent customer accountsreceivable represents accounts greater than 30 days past due. NUCLEAR I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted bythe NRC. We have a significant future financial commitment to dispose of SNFand to safely decommission and decontaminate the plant. The licenses to operatethe two nuclear units at the Cook Plant expire in 2034 and 2037. The operationof a nuclear facility also involves special risks, potential liabilities andspecific regulatory and safety requirements. Should a nuclear incident occur atany nuclear power plant in the U.S., the resultant liability could besubstantial. By agreement, I&M is partially liable, together with all otherelectric utility companies that own nuclear generating units, for a nuclearpower 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 theSNF disposal program. Decommissioning costs are accrued over the service lifeof the Cook Plant. The most recent decommissioning cost study was performed in2006. According to that study, the estimated cost of decommissioning anddisposal of low-level radioactive waste ranges from $733 million to $1.3 billionin 2006 nondiscounted dollars. The wide range in estimated costs is caused byvariables in assumptions. I&M recovers estimated decommissioning costs for theCook 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 recoveredfrom customers are deposited in external trusts. The settlement agreement inI&M's base rate case will reduce the annual decommissioning cost recovery amounteffective in 2009 to reflect the extension of the units' operating licensesgranted by the NRC. I&M deposited an additional $4 million in 2008, 2007 and 2006 in itsdecommissioning trust under funding provisions approved by regulatory commissions. At December 31, 2008 and 2007, the total decommissioning trustfund balance was $959 million and $1.1 billion, respectively. Trust fundearnings increase the fund assets and decrease the amount remaining to berecovered from ratepayers. The decommissioning costs (including interest,unrealized gains and losses and expenses of the trust funds) increase ordecrease the recorded liability. I&M continues to work with regulators and customers to recover the remainingestimated costs of decommissioning the Cook Plant. However, future net income,cash flows and possibly financial condition would be adversely affected if thecost of SNF disposal and decommissioning continues to increase and cannot berecovered. SNF Disposal The Federal government is responsible for permanent SNF disposal and assessesfees to nuclear plant owners for SNF disposal. A fee of one mill per KWH forfuel consumed after April 6, 1983 at the Cook Plant is being collected fromcustomers and remitted to the U.S. Treasury. At December 31, 2008 and 2007,fees and related interest of $264 million and $259 million, respectively, forfuel consumed prior to April 7, 1983 have been recorded as Long-term Debt andfunds collected from customers along with related earnings totaling $301 millionand $285 million, respectively, to pay the fee are recorded as part of SpentNuclear Fuel and Decommissioning Trusts. I&M has not paid the government thepre-April 1983 fees due to continued delays and uncertainties related to thefederal disposal program. Trust Assets for Decommissioning and SNF Disposal We record securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at market value. We classify securities in thetrust funds as available-for-sale due to their long-term purpose. As discussedin the "Nuclear Trust Funds" section of Note 1, we record unrealized gains andother-than-temporary impairments from securities in these trust funds asadjustments to the regulatory liability account for the nuclear decommissioningtrust funds and to regulatory assets or liabilities for the SNF disposal trustfunds in accordance with their treatment in rates. The gains, losses orother-than-temporary impairments shown below did not affect earnings or AOCI.The trust assets are recorded by jurisdiction and may not be used for anotherjurisdictions' liabilities. Regulatory approval is required to withdrawdecommissioning funds. See "SFAS 157 Fair Value Measurements" section of Note 11 for disclosure of thefair value of assets within the trusts. The following is a summary of nuclear trust fund investments at December 31: December 31, 2008 2007 EstimatedFairValue GrossUnrealizedGains Other-Than-TemporaryImpairments EstimatedFairValue GrossUnrealizedGains Other-Than-TemporaryImpairments (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, $696million and $631 million in 2008, 2007 and 2006, respectively. Purchases ofnuclear trust fund investments were $804 million, $777 million and $692 millionin 2008, 2007 and 2006, respectively. Gross realized gains from the sales of nuclear trust fund investments were $33million, $15 million and $7 million in 2008, 2007 and 2006, respectively. Grossrealized losses from the sales of nuclear trust fund investments were $7million, $5 million and $7 million in 2008, 2007 and 2006, respectively. The fair value of debt securities held in the nuclear trust funds, summarized bycontractual maturities, at December 31, 2008 was as follows: Fair Value of DebtSecurities (in millions)Within 1 year $ 511 year - 5 years 1725 years - 10 years 209After 10 years 341Total $ 773 Nuclear Incident Liability I&M carries insurance coverage for property damage, decommissioning anddecontamination at the Cook Plant in the amount of $1.8 billion. I&M purchases$1 billion of excess coverage for property damage, decommissioning anddecontamination. Additional insurance provides coverage for a weekly indemnitypayment resulting from an insured accidental outage. I&M utilizes an industrymutual insurer for the placement of this insurance coverage. Participation inthis mutual insurance requires a contingent financial obligation of up to $37million for I&M which is assessable if the insurer's financial resources wouldbe inadequate to pay for losses. The Price-Anderson Act, extended through December 31, 2025, establishesinsurance 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 licensedreactor, provides $300 million of coverage. In the event of a nuclear incidentat any nuclear plant in the U.S., the remainder of the liability would beprovided by a deferred premium assessment of $117.5 million on each licensedreactor in the U.S. payable in annual installments of $17.5 million. As aresult, I&M could be assessed $235 million per nuclear incident payable inannual installments of $35 million. The number of incidents for which paymentscould be required is not limited. In the event of an incident of a catastrophic nature, we are initially coveredfor the first $300 million through commercially available insurance. The nextlevel of liability coverage of up to $12.2 billion would be covered by claimsmade under the Price-Anderson Act. If the liability were in excess of amountsrecoverable from insurance and retrospective claim payments made under thePrice-Anderson Act, we would seek to recover those amounts from customersthrough rate increases. In the event nuclear losses or liabilities areunderinsured or exceed accumulated funds and recovery from customers is notpossible, net income, cash flows and financial condition could be adversely affected. 40000000 0 0 40000000 0 0 2576000000 2388000000 2732000000 30000000 11000000 4000000 -17000000 -88000000 -72000000 -45000000 -33000000 -30000000 149000000 0 0 3.42 2.72 2.53 3000000 3000000 3000000 45000000 33000000 30000000 1154000000 1075000000 No UNAUDITED QUARTERLY FINANCIAL INFORMATION In our opinion, the unaudited quarterly information reflects all normal andrecurring accruals and adjustments necessary for a fair presentation of our netincome for interim periods. Quarterly results are not necessarily indicative ofa full year's operations because of various factors. Our unaudited quarterlyfinancial information is as follows: 2008 Quarterly Periods Ended March 31 June 30 September 30 December 31 (in millions - except per share amounts)Revenues $ 3,467 $ 3,546 $ 4,191$ 3,236 (c)Operating Income 1,043 (a)(b) 586 737421 (c)Income Before Discontinued Operations and Extraordinary Loss 573(a)(b) 280 374 141 (c) Discontinued Operations, Net of Tax - 1- 11Net Income 573 (a)(b) 281 374152 (c) Basic Earnings per Share: Earnings per Share Before Discontinued Operations and Extraordinary Loss1.43 0.70 0.93 0.34 Discontinued Operations per Share - -- 0.03Earnings per Share 1.43 0.70 0.930.37 Diluted Earnings per Share: Earnings per Share Before Discontinued Operations and Extraordinary Loss (d)1.43 0.70 0.93 0.34 Discontinued Operations per Share - -- 0.03Earnings per Share (e) 1.43 0.70 0.930.37 (a) See "TEM Litigation" section of Note 6 for discussion of the settlementreached with TEM in January 2008.(b) See "Oklahoma 2007 Ice Storms" section of Note 4 for discussion of thefirst quarter 2008 reversal of expenses incurred from ice storms in January andDecember 2007.(c) See "Allocation of Off-system Sales Margins" section of Note 4 fordiscussion of the financial statement impact of the FERC's November 2008 orderrelated to the SIA.(d) Amounts for 2008 do not add to $3.39 for Diluted Earnings per ShareBefore Discontinued Operations and Extraordinary Loss due to rounding.(e) Amounts for 2008 do not add to $3.42 for Diluted Earnings per Share dueto rounding. 2007 Quarterly Periods Ended March 31 June 30 September 30 December 31 (in millions - except per share amounts)Revenues $ 3,169 $ 3,146 $ 3,789$ 3,276Operating Income 545 (f) 549 798427 (f)Income Before Discontinued Operations and Extraordinary Loss 271(f) 257 407 209 (f) Discontinued Operations, Net of Tax - 2- 22Income Before Extraordinary Loss 271 (f) 259407 231 (f)Extraordinary Loss, Net of Tax - (79) (g)- -Net Income 271 (f) 180 407231 (f) Basic Earnings (Loss) per Share: Earnings per Share Before Discontinued Operations and Extraordinary Loss (h)0.68 0.64 1.02 0.52 Discontinued Operations per Share (i) - 0.01- 0.06Earnings per Share Before Extraordinary Loss 0.68 0.65 1.02 0.58Extraordinary Loss per Share - (0.20) - - -Earnings per Share 0.68 0.45 1.020.58 Diluted Earnings (Loss) per Share: Earnings per Share Before Discontinued Operations and Extraordinary Loss0.68 0.64 1.02 0.52 Discontinued Operations per Share - 0.01- 0.05Earnings per Share Before Extraordinary Loss 0.68 0.65 1.02 0.57Extraordinary Loss per Share - (0.20) - - -Earnings per Share 0.68 0.45 1.020.57 (f) See "Oklahoma 2007 Ice Storms" section of Note 4 for discussion ofexpenses incurred from ice storms in January and December 2007. (g) See "Virginia Restructuring" in "Extraordinary Item" section of Note 2for discussion of the extraordinary loss recorded in the second quarter of 2007.(h) Amounts for 2007 do not add to $2.87 for Basic Earnings per Share BeforeDiscontinued Operations and Extraordinary Loss due to rounding. (i) Amounts for 2007 do not add to $0.06 for Basic Earnings per Share for Discontinued Operations due to rounding. Large Accelerated Filer 233000000 -123000000 -100000000 -140000000 3000000 -191000000 402083847 398784745 394219523 961000000 844000000 735000000 1281000000 1138000000 856000000 1114000000 1279000000 556000000 34401000000 30179000000 1976000000 660000000 3775000000 3026000000 539000000 531000000 0 6000000 0 0 0 -235000000 0 0 -235000000 0 0 2000000 0 0 2000000 -40000000 50000000 -13000000 0 -79000000 0 2787000000 2319000000 1966000000 761000000 755000000 737000000 13326000000 12101000000 12066000000 2771000000 2743000000 426321248 421926696 270000000 235000000 DISCONTINUED OPERATIONS Management periodically assesses our overall business model and makes decisions regarding our continued support and funding of our various businesses and operations. When it is determined that we will seek to exit a particular business or activity and we have met the accounting requirements for reclassification, we will reclassify those businesses or activities as discontinued operations. The assets and liabilities of these discontinued operations are classified in Assets Held for Sale and Liabilities Held for Sale until the time that they are sold. Certain of our operations were determined to be discontinued operations and are classified as such in 2008, 2007 and 2006. Results of operations of these businesses are classified as shown in the following table: SEE-BOARD (a) U.K. Generation (b) Total (in millions) 2008 Revenue $ - $ 2 $ 2 2008 Pretax Income - 2 2 2008 Earnings, Net of Tax - 12 12 2007 Revenue $ - $ - $ - 2007 Pretax Income - 7 7 2007 Earnings, Net of Tax 4 20 24 2006 Revenue $ - $ - $ - 2006 Pretax Income - 9 9 2006 Earnings, Net of Tax 5 5 10 (a) Relates to purchase price true-up adjustments and tax adjustments from the sale of SEEBOARD, a former U.K. utility subsidiary of AEP that was sold in 2002.(b) The 2008 amounts relate primarily to favorable income tax reserve adjustments. The 2007 amounts relate to tax adjustments from the sale. The 2006 amounts relate to a release of accrued liabilities for the London office sublease and tax adjustments from the sale. GUARANTEES We record certain immaterial liabilities for guarantees in accordance with FIN45 "Guarantor's Accounting and Disclosure Requirements for Guarantees, IncludingIndirect Guarantees of Indebtedness of Others." In addition, we adopted FSPSFAS 133-1 and FIN 45-4 "Disclosures about Credit Derivatives and CertainGuarantees: An amendment of FASB Statement No. 133 and FASB Interpretation No.45; and Clarification of the Effective Date of FASB Statement No. 161" effectiveDecember 31, 2008. There is no collateral held in relation to any guarantees inexcess of our ownership percentages. In the event any guarantee is drawn, thereis no recourse to third parties unless specified below. Letters of Credit We enter into standby letters of credit (LOCs) with third parties. These LOCscover items such as gas and electricity risk management contracts, constructioncontracts, insurance programs, security deposits and debt service reserves. Asthe Parent, we issued all of these LOCs in our ordinary course of business onbehalf of our subsidiaries. At December 31, 2008, the maximum future paymentsfor LOCs issued under the two $1.5 billion credit facilities are $62 millionwith maturities ranging from March 2009 to March 2010. The two $1.5 billioncredit facilities were reduced by Lehman Brothers Holding Inc.'s commitmentamount of $46 million following its bankruptcy. In April 2008, we entered into a $650 million 3-year credit agreement and a $350million 364-day credit agreement which were reduced by Lehman Brothers HoldingsInc.'s commitment amount of $23 million and $12 million, respectively, followingits bankruptcy. As of December 31, 2008, $372 million of letters of credit wereissued by subsidiaries under the 3-year credit agreement to support variablerate Pollution Control Bonds. Guarantees of Third-Party Obligations SWEPCo As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation in theamount of approximately $65 million. Since SWEPCo uses self-bonding, theguarantee provides for SWEPCo to commit to use its resources to complete thereclamation in the event the work is not completed by Sabine Mining Company(Sabine), an entity consolidated under FIN 46R. This guarantee ends upondepletion of reserves and completion of final reclamation. Based on the lateststudy, we estimate the reserves will be depleted in 2029 with final reclamationcompleted by 2036, at an estimated cost of approximately $39 million. As ofDecember 31, 2008, SWEPCo has collected approximately $38 million through arider for final mine closure costs, of which approximately $700 thousand isrecorded in Other Current Liabilities, $20 million is recorded in DeferredCredits and Other and $18 million is recorded in Asset Retirement Obligations onour Consolidated Balance Sheets. Sabine charges SWEPCo, its only customer, all its costs. SWEPCo passes thesecosts through its fuel clause. Indemnifications and Other Guarantees Contracts We enter into several types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements,lease agreements, purchase agreements and financing agreements. Generally,these agreements may include, but are not limited to, indemnifications aroundcertain tax, contractual and environmental matters. With respect to saleagreements, our exposure generally does not exceed the sale price. The statusof certain sales agreements is discussed in the "Dispositions" section of Note7. These sale agreements include indemnifications with a maximum exposurerelated to the collective purchase price, which is approximately $1.2 billion.Approximately $1 billion of the maximum exposure relates to the Bank of America(BOA) litigation (see "Enron Bankruptcy" section of this note), of which theprobable payment/performance risk is $433 million and is recorded in DeferredCredits and Other on our Consolidated Balance Sheets as of December 31, 2008.The remaining exposure is remote. There are no material liabilities recordedfor any indemnifications othe r than amounts recorded related to the BOAlitigation. Lease Obligations We lease certain equipment under master lease agreements. See "Master LeaseAgreements" and "Railcar Lease" sections of Note 13 for disclosure of lease residual value guarantees. EFFECTS OF REGULATION Regulatory assets and liabilities are comprised of the following items: December 31,Regulatory Assets: 2008 2007 Notes (in millions)Current Regulatory AssetUnder-recovered Fuel Costs $ 284 $ 11 (c) (h) Noncurrent Regulatory Assets SFAS 158 Regulatory Asset (See Note 8) $ 2,162 $ 659(a) (g)SFAS 109 Regulatory Asset, Net (See Note 12) 888 815(c) (g)Virginia E&R Costs Recovery (See Note 4) 123 82(c) (i)Unamortized Loss on Reacquired Debt 104 108(b) (l)Oklahoma 2007 Ice Storms (See Note 4) 62 -(b) (j)Customer Choice Deferrals - Ohio (See Note 4) 55 52(b) (o)Restructuring Transition Costs - Texas, Ohio and Virginia 38108 (a) (k)Line Extension Carrying Costs - Ohio (See Note 4) 3123 (b) (o)Mountaineer Carbon Capture Project - Virginia (See Note 4) 29- (c) (o)Hurricane Ike - Ohio (See Note 4) 27 - (b)(o)Cook Nuclear Plant Refueling Outage Levelization 2534 (a) (d)Hurricanes Dolly and Ike - Texas (See Note 4) 23 -(b) (o)L awton Settlement - Oklahoma 21 32 (b) (i)Red Rock Generating Facility - Oklahoma (See Note 4) 1121 (b) (m)Unrealized Loss on Forward Commitments - 39(a) (g)Other 184 226 (c) (g)Total Noncurrent Regulatory Assets $ 3,783 $ 2,199 Regulatory Liabilities: Current Regulatory Liability Over-recovered Fuel Costs (p) $ 66 $ 64 (c) (h) Noncurrent Regulatory Liabilities and Deferred Investment Tax CreditsAsset Removal Costs $ 2,017 $ 1,927 (e)Deferred Investment Tax Credits 294 311 (c)(n)Excess ARO for Nuclear Decommissioning Liability (See Note 9) 208362 (f)Unrealized Gain on Forward Commitments 91 103(a) (g)Deferred State Income Taxes Due to the Phase Out of the Ohio Franchise Tax- 43 (a) (h)Other 179 206 (c) (g)Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits$ 2,789 $ 2,952 (a) Amount does not earn a return. (b) Amount earns a return.(c) A portion of this amount earns a return.(d) Amortized and recovered over the period beginning with the commencementof an outage and ending with the beginning of the next outage. (e) The liability for removal costs, which reduces rate base and theresultant return, will be discharged as removal costs are incurred. (f) This is the difference in the cumulative amount of removal costsrecovered through rates and the cumulative amount of ARO as measured by applyingSFAS 143 "Accounting for Asset Retirement Obligations." This amount earns areturn, accrues monthly and will be paid when the nuclear plant isdecommissioned.(g) Recovery/refund period - various periods.(h) Recovery/refund period - 1 year.(i) Recovery/refund period - 2 years.(j) Recovery/refund period - 5 years(k) Recovery/refund period - up to 7 years.(l) Recovery/refund period - up to 35 years.(m) Recovery/refund period - 48 years.(n) Recovery/refund period - up to 78 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 our Consolidated Balance Sheets. 6000000 0 0 0 0 9000000 4000000 4000000 3000000 -4027000000 -3921000000 -3743000000 45000000 -114000000 -33000000 -29000000 -11000000 17000000 3.43 2.73 2.54 57000000 51000000 99000000 15536000000 14202000000 6297000000 5161000000 254000000 301000000 134000000 240000000 8393000000 7423000000 172000000 70000000 EXTRAORDINARY ITEM Virginia Restructuring In April 2007, Virginia passed legislation to reestablish regulation for retail generation and supply of electricity. As a result, we recorded an extraordinary loss of $118 million ($79 million, net of tax) in 2007 for the reestablishment of regulatory assets and liabilities related to our Virginia retail generation and supply operations. In 2000, we discontinued SFAS 71 regulatory accounting in our Virginia jurisdiction for retail generation and supply operations due to the passage of legislation for customer choice and deregulation. INCOME TAXES The details of our consolidated income taxes before discontinued operations andextraordinary loss as reported are as follows: Years Ended December 31, 2008 2007 2006 (in millions)Federal:Current $ 164 $ 464 $ 429Deferred 456 35 5Total 620 499 434 State and Local: Current (1) 1 61Deferred 22 16 (10) Total 21 17 51 International: Current 1 - -Deferred - - -Total 1 - - Total Income Tax Expense Before Discontinued Operations and Extraordinary Loss$ 642 $ 516 $ 485 The following is a reconciliation of our consolidated difference between theamount of federal income taxes computed by multiplying book income before incometaxes by the federal statutory tax rate and the amount of income taxes reported. Years Ended December 31, 2008 2007 2006 (in millions)Net Income $ 1,380 $ 1,089 $ 1,002Discontinued Operations (Net of Income Tax of $(10) Million, $(18) Million and$(1) Million in 2008, 2007 and 2006, respectively) (12)(24) (10)Extraordinary Loss, (Net of Income Tax of $39 Million in 2007) -79 -Preferred Stock Dividends 3 3 3Income Before Preferred Stock Dividends of Subsidiaries 1,3711,147 995Income Tax Expense Before Discontinued Operations and Extraordinary Loss642 516 485Pretax Income $ 2,013 $ 1,663 $ 1,480 Income Taxes on Pretax Income at Statutory Rate (35%) $ 705$ 582 $ 518Increase (Decrease) in Income Taxes resulting from the following items:Depreciation 23 29 38Investment Tax Credits, Net (19) (24)(29)Energy Production Credits (20) (18) (19)State Income Taxes 13 11 33Removal Costs (21) (21) (15)AFUDC (24) (18) (18) Medicare Subsidy (12) (12) (12)Tax Reserve Adjustments 2 (8) 9Other (5) (5) (20) Total Income Tax Expense Before Discontinued Operations and Extraordinary Loss$ 642 $ 516 $ 485 Effective Income Tax Rate 31.9% 31.0%32.8% The following table shows elements of the net deferred tax liability andsignificant temporary differences: December 31, 2008 2007 (in millions)Deferred Tax Assets $ 2,632 $ 2,284 Deferred Tax Liabilities (7,750) (7,023)Net Deferred Tax Liabilities $ (5,118) $ (4,739) Property-Related Temporary Differences $ (3,718) $(3,300)Amounts Due from Customers for Future Federal Income Taxes (218)(202)Deferred State Income Taxes (362) (324)Securitized Transition Assets (776) (806)Regulatory Assets (871) (225)Accrued Pensions 284 (211)Deferred Income Taxes on Other Comprehensive Loss 24083Accrued Nuclear Decommissioning (277) (286)Deferred Fuel (76) (19)All Other, Net 656 551Net Deferred Tax Liabilities $ (5,118) $ (4,739) We, along with our subsidiaries, file a consolidated federal income tax return.The allocation of the AEP System's current consolidated federal income tax tothe AEP System companies allocates the benefit of current tax losses to the AEPSystem companies giving rise to such losses in determining their currentexpense. The tax benefit of the Parent is allocated to our subsidiaries withtaxable income. With the exception of the loss of the Parent, the method ofallocation reflects a separate return result for each company in theconsolidated group. We are no longer subject to U.S. federal examination for years before 2000. Wehave completed the exam for the years 2001 through 2003 and have issues that weare pursuing at the appeals level. The returns for the years 2004 through 2006are presently under audit by the IRS. Although the outcome of tax audits isuncertain, in management's opinion, adequate provisions for income taxes havebeen made for potential liabilities resulting from such matters. In addition,we accrue interest on these uncertain tax positions. We are not aware of anyissues for open tax years that upon final resolution are expected to have amaterial adverse effect on net income. We, along with our subsidiaries, file income tax returns in various state, localand foreign jurisdictions. These taxing authorities routinely examine our taxreturns and we are currently under examination in several state and localjurisdictions. We believe that we have filed tax returns with positions thatmay be challenged by these tax authorities. However, management does notbelieve that the ultimate resolution of these audits will materially impact netincome. With few exceptions, we are no longer subject to state, local ornon-U.S. income tax examinations by tax authorities for years before 2000. Prior to the adoption of FIN 48, we recorded interest and penalty expenserelated to uncertain tax positions in tax expense accounts. With the adoptionof FIN 48 on January 1, 2007, we began recognizing interest accruals related touncertain tax positions in interest income or expense as applicable, andpenalties in Other Operation and Maintenance. The impact of this interpretationwas an unfavorable adjustment to the 2007 opening balance of retained earningsof $17 million. We reported $10 million and $2 million of interest expense, $21million and $5 million of interest income and reversed $13 million and $17million of prior period interest expense in 2008 and 2007, respectively. We hadapproximately $33 million for the receipt of interest accrued at December 31,2008 and approximately $26 million and $16 million for the payment of interestand penalties accrued at December 31, 2008 and 2007, respectively. The reconciliation of the beginning and ending amount of unrecognized taxbenefits is as follows: 2008 2007 (in millions) Balance at January 1, $ 222 $ 175 Increase - Tax Positions Taken During a Prior Period 4175Decrease - Tax Positions Taken During a Prior Period (45)(43)Increase - Tax Positions Taken During the Current Year 2720Decrease - Tax Positions Taken During the Current Year (5)-Increase - Settlements with Taxing Authorities 3 2Decrease - Lapse of the Applicable Statute of Limitations (6)(7) Balance at December 31, $ 237 $ 222 The total amount of unrecognized tax benefits that, if recognized, would affectthe effective tax rate is $147 million. We believe there will be no significantnet increase or decrease in unrecognized tax benefits within 12 months of thereporting date. Federal Tax Legislation In 2005, the Energy Tax Incentives Act of 2005 was signed into law. This actcreated a limited amount of tax credits for the building of IGCC plants. Thecredit 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. Inthe case of a newly constructed IGCC plant, eligible property is defined as thecomponents necessary for the gasification of coal, including any coal handlingand gas separation equipment. We announced plans to construct two new IGCCplants that may be eligible for the allocation of these credits. We filedapplications for the Mountaineer and Great Bend projects with the DOE and theIRS. Both projects were certified by the DOE and qualified by the IRS.However, neither project was allocated credits during this round of creditawards. After one of the original credit recipients surrendered its credits inthe Fall of 2007, the IRS announced a supplemental credit round for the Springof 2008. We filed a new ap plication in 2008 for the West Virginia IGCC projectand in July 2008 the IRS allocated the project $134 million in credits. InSeptember 2008, we entered into a memorandum of understanding with the IRSconcerning the requirements of claiming the credits. Several tax bills and other legislation with tax-related sections were enactedin 2006 and 2007, including the Pension Protection Act of 2006, Tax Relief andHealth Care Act of 2006, the Tax Technical Corrections Act of 2007, the TaxIncrease Prevention Act of 2007 and the Energy Independence and Security Act of2007. The tax law changes enacted in 2006 and 2007 did not materially affectour net income, cash flows or financial condition. The Economic Stimulus Act of 2008 was signed into law by the President inFebruary 2008. It provided enhanced expensing provisions for certain assetsplaced in service in 2008 and a 50% bonus depreciation provision similar to theone in effect in 2003 through 2004 for assets placed in service in 2008. Theenacted provisions did not have a material impact on net income or financialcondition, but provided a material favorable cash flow benefit of approximately$200 million. 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 andadded new energy incentive provisions. The legislation impacted theavailability of research credits, accelerated depreciation of smart meters,production tax credits and energy efficient commercial building deductions. Wehave evaluated the impact of the law change and the application of the lawchange will not materially impact our net income, cash flows or financialcondition. In February 2009, the American Recovery and Reinvestment Tax Act of 2009 (the2009 Act) was signed into law. The 2009 Act extended the bonus depreciationdeduction for one year and provides for a long-term extension of the renewableproduction tax credit for wind energy and other properties. The 2009 Act alsoestablishes a new investment tax credit for the manufacture of advanced energyproperty as well as appropriations for advanced energy research projects, carboncapture and storage and gridSMART technology. We have evaluated the impact ofthe law change and the application of the law change will not materially impactour net income or financial condition, but is expected to have a positivematerial impact on cash flows. State Tax Legislation In June 2005, the Governor of Ohio signed Ohio House Bill 66 into law enactingsweeping tax changes impacting all companies doing business in Ohio. Most ofthe significant tax changes phase in over a five-year period, while some of theless significant changes became fully effective July 1, 2005. Changes to theOhio franchise tax, nonutility property taxes and the new commercial activitytax are subject to phase-in. The Ohio franchise tax will fully phase-out over afive-year period beginning with a 20% reduction in state franchise tax fortaxable income accrued during 2005. In 2005, we reversed deferred state incometax liabilities of $83 million that are not expected to reverse during thephase-out. We recorded $4 million as a reduction to Income Tax Expense and, forthe Ohio companies, established a regulatory liability for $57 million pendingrate-making treatment in Ohio. See "Ormet" section of Note 4 for furtherdiscussion. For those companies in which state income taxes flow through forrate-making purposes , the adjustments reduced the regulatory assets associatedwith the deferred state income tax liabilities by $22 million. In November2006, the PUCO ordered that the $57 million be amortized to income as an offsetto power supply contract losses incurred by CSPCo and OPCo for sales to Ormet.At December 31, 2008, the $57 million regulatory liability was fully amortized. The Ohio legislation also imposed a new commercial activity tax at a fullyphased-in rate of 0.26% on all Ohio gross receipts. The new tax is beingphased-in over a five-year period that began July 1, 2005 at 23% of the full0.26% rate. As a result of this new tax, expenses of approximately $9 million,$6 million and $4 million were recorded in 2008, 2007 and 2006, respectively, inTaxes Other Than Income Taxes. In the second quarter of 2006, the Texas state legislature replaced the existingfranchise/income tax with a gross margin tax at a 1% rate for electricutilities. Overall, the law reduced Texas income tax rates and was effectiveJanuary 1, 2007. The new gross margin tax is income-based for purposes of theapplication of SFAS 109. Based on the new law, we reviewed deferred taxliabilities with consideration given to the rate changes and changes to theallowed deductible items with temporary differences. As a result, in the secondquarter of 2006, we recorded a net reduction to Deferred Income Taxes on ourConsolidated Balance Sheet of $48 million of which $2 million was credited toIncome Tax Expense and $46 million was credited to Regulatory Assets based uponthe related rate-making treatment. In July 2007, the Governor of Michigan signed Michigan Senate Bill 0094 (MBTAct) and related companion bills into law providing a comprehensive restructuring of Michigan's principal business tax. The new law is effectiveJanuary 1, 2008 and replaces the Michigan Single Business Tax that expired atthe end of 2007. The MBT Act is composed of a new tax which will be calculatedbased upon two components: (a) a business income tax (BIT) imposed at a rate of4.95% 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 newlaw also includes significant credits for engaging in Michigan-based activity. In September 2007, the Governor of Michigan signed House Bill 5198 which amendsthe MBT Act to provide for a new deduction on the BIT and GRT tax returns equalto the book-tax basis differences triggered as a result of the enactment of theMBT Act. This new state-only temporary difference will be deducted over a15-year period on the MBT Act tax returns starting in 2015. The purpose of thenew MBT Act state deduction was to provide companies relief from the recordationof the SFAS 109 Income Tax Liability. We have evaluated the impact of the MBTAct and the application of the MBT Act will not materially affect our netincome, 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 ratefrom 8.75% to 8.5% beginning in 2009. The corporate income tax rate could alsobe reduced to 7.75% in 2012 and 7% in 2013 contingent upon the state governmentachieving certain minimum levels of shortfall reserve funds. We have evaluatedthe impact of the law change and the application of the law change will notmaterially impact our net income, cash flows or financial condition. 0 0 17000000 0 0 17000000 -16000000 -1000000 -1000000 -16000000 -1000000 -1000000 4000000 -20000000 21000000 4000000 -20000000 21000000 -660000000 -630000000 -591000000 -660000000 -630000000 -591000000 426000000 422000000 418000000 415000000 19000000 -21000000 49000000 3.40 2.87 2.52 1380000000 1168000000 1002000000 958000000 841000000 732000000 2789000000 2952000000 634000000 601000000 3973000000 3019000000 42000000 52000000 449000000 379000000 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES RATES AND SERVICE REGULATION Our public utility subsidiaries' rates are regulated by the FERC and stateregulatory commissions in our eleven state operating territories. The stateregulatory commissions approve retail rates and regulate the retail services andoperations of the utility subsidiaries for the generation and supply of power, amajority of transmission energy delivery services and distribution services.The FERC regulates our affiliated transactions, including AEPSC intercompanyservice billing which are generally at cost, under the 2005 Public UtilityHolding Company Act and the Federal Power Act. The FERC also has jurisdictionover the issuances and acquisitions of securities of our public utilitysubsidiaries, the acquisition or sale of certain utility assets and mergers withanother electric utility or holding company. A FERC order in 2008 pursuant tothe Federal Power Act codified that for non-power goods and services, anon-regulated affiliate can bill a public utility company no more than marketwhile a public utility must bill the higher of cost or market to a non-regulatedaffiliate. The state regulatory commissions in placeStateVirginia andplaceStateWest Virginia also regulate certain intercompany transactions undertheir affiliates statutes. The FERC regulates wholesale power markets and wholesale power transactions.Our wholesale power transactions are generally market-based. They arecost-based regulated when we negotiate and file a cost-based contract with theFERC or the FERC determines that we have "market power" in the region where thetransaction occurs. We enter into wholesale power supply contracts with variousmunicipalities and cooperatives that are FERC-regulated, cost-based contracts.Our wholesale power transactions in the SPP region are cost-based due to SWEPCoand PSO having market power in the SPP region. The FERC also regulates, on a cost basis, our wholesale transmission service andrates except in placeStateTexas. The FERC claims jurisdiction over retailtransmission rates when retail rates are unbundled in connection withrestructuring. CSPCo's and OPCo's retail rates in placeStateOhio, APCo's retailrates in Virginia, I&M's retail rates in placeStateMichigan and TCC's and TNC'sretail rates in placeStateTexas are unbundled. Therefore, CSPCo's and OPCo'sretail transmission rates are based on the FERC's Open Access TransmissionTariff (OATT) rates that are cost-based. Although APCo's retail rates inVirginia, I&M's retail rates in placeStateMichigan and TCC's and TNC's retailrates in placeStateTexas are unbundled, retail transmission rates are regulated,on a cost basis, by the state regulatory commissions. Starting in 2009, APComay file, and the Virginia SCC shall approve, a rate adjustment clause thatpasses through charges associated with the FERC's OATT rates to APCo'splaceStateVirginia retail customers. Bundled retail transmission rates areregulated, on a cost basis, by the state commissions. In addition, the FERC regulates the SIA, the Interconnection Agreement, the CSWOperating Agreement, the System Transmission Integration Agreement, theTransmission Equalization Agreement, the Transmission Coordination Agreement andthe AEP System Interim Allowance Agreement, all of which allocate shared systemcosts and revenues to the utility subsidiaries that are parties to eachagreement. The state regulatory commissions regulate all of our retail public utilityservices/operations (generation/power supply, transmission and distributionoperations) and rates except in placeStateOhio and the ERCOT region ofplaceStateTexas. Our retail generation/power supply operations and rates forCSPCo and OPCo in placeStateOhio are no longer cost-based regulated. Theserates were subject to RSPs through dateMonth12Day31Year2008December 31, 2008.The PUCO extended these rates until they issue a ruling on the ESPs or the endof the February 2009 billing cycle, whichever comes first. The ESP rates areunder recently enacted legislation, which continues the concept of increasingrates over time to approach market rates. In the ERCOT region ofplaceStateTexas, the generation/supply business is under customer choice andmarket pricing. AEP has no placeStateTexas jurisdictional retailgeneration/power supply operations other than a minor supply operation throug h acommercial and industrial customer REP. In 2007, the placeStateVirginialegislation ended a transition to market-based rates and returned APCo tocost-based regulation. See Note 4 for further information on restructuringlegislation and its effects on AEP in placeStateOhio, placeStateTexas andplaceStateMichigan. Both the FERC and state regulatory commissions are permitted to review and auditthe books and records of any company within a public utility holding companysystem. PRINCIPLES OF CONSOLIDATION Our consolidated financial statements include our wholly-owned andmajority-owned subsidiaries and variable interest entities (VIEs) of which weare the primary beneficiary. Intercompany items are eliminated inconsolidation. Equity investments not substantially-controlled and which we arenot the primary beneficiary of the entity, that are 50% or less owned areaccounted for using the equity method of accounting and recorded as DeferredCharges and Other on our Consolidated Balance Sheets; equity earnings areincluded in Equity Earnings of Unconsolidated Subsidiaries on our ConsolidatedStatements of Income. For years, we have had ownership interests in generatingunits that are jointly-owned with nonaffiliated companies. Our proportionateshare of the operating costs associated with such facilities is included on ourConsolidated Statements of Income and our proportionate share of the assets andliabilities are reflected on our Consolidated Balance Sheets. FIN 46R is a consolidation model that considers risk absorption of a variableinterest entity (VIE), also referred to as variability. Entities are requiredto consolidate a VIE when it is determined that they are the primary beneficiaryof that VIE, as defined by FIN 46R. In determining whether we are the primarybeneficiary of a VIE, we consider factors such as equity at risk, the amount ofvariability of the VIE we absorb, guarantees of indebtedness, voting rightsincluding kick-out rights, power to direct the VIE and other factors. Webelieve that significant assumptions and judgments have been consistentlyapplied and that there are no other reasonable judgments or assumptions thatwould have resulted in a different conclusion. We are the primary beneficiary of Sabine, DHLC, JMG and a protected cell of EIS.We hold a variable interest in Potomac-Appalachian Transmission Highline, LLCWest Virginia Series (West Virginia Series). In addition, we have not providedfinancial or other support that was not previously contractually required to anyVIE. Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has noequity investment in Sabine but is Sabine's only customer. SWEPCo hasguaranteed the debt obligations and lease obligations of Sabine. Under theterms of the note agreements, substantially all assets are pledged and allrights under the lignite mining agreement are assigned to SWEPCo. The creditorsof Sabine have no recourse to any AEP entity other than SWEPCo. Under theprovisions of the mining agreement, SWEPCo is required to pay, as a part of thecost of lignite delivered, an amount equal to mining costs plus a management feewhich is included in Fuel and Other Consumables Used for Electric Generation onour Consolidated Statements of Income. Based on these facts, management hasconcluded SWEPCo is the primary beneficiary and is required to consolidateSabine. SWEPCo's total billings from Sabine for the years endeddateMonth12Day31Year2008December 31, 2008 and 2007 were $110 million and $95million, respectively. See the tables below for the classification of Sabine'sassets and liabilities on our Consolidated Balance Sheets. DHLC is a wholly-owned subsidiary of SWEPCo. DHLC is a mining operator whosells 50% of the lignite produced to SWEPCo and 50% to Cleco Corporation, anonaffiliated company. SWEPCo and Cleco Corporation share half of the executiveboard seats, with equal voting rights and each entity guarantees a 50% share ofDHLC's debt. The creditors of DHLC have no recourse to any AEP entity otherthan SWEPCo. Based on the structure and equity ownership, management hasconcluded that SWEPCo is the primary beneficiary and is required to consolidateDHLC. SWEPCo's total billings from DHLC for the years endeddateMonth12Day31Year2008December 31, 2008 and 2007 were $44 million and $35million, respectively. These billings are included in Fuel and OtherConsumables Used for Electric Generation on our Consolidated Statements ofIncome. See the tables below for the classification of DHLC assets andliabilities on our Consolidated Balance Sheets. OPCo has a lease agreement with JMG to finance OPCo's FGD system installed onOPCo's Gavin Plant. The PUCO approved the original lease agreement between OPCoand JMG. JMG has a capital structure of substantially all debt from pollutioncontrol bonds and other debt. JMG owns and leases the FGD to OPCo. JMG isconsidered a single-lessee leasing arrangement with only one asset. OPCo'slease payments are the only form of repayment associated with JMG's debtobligations even though OPCo does not guarantee JMG's debt. The creditors ofJMG 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 theentity, management has concluded OPCo is the primary beneficiary and is requiredto consolidate JMG. OPCo's total billings from JMG for the years endeddateMonth12Day31Year2008December 31, 2008 and 2007 were $57 million and $46million, respectively. See the tables below for the classi fication of JMG'sassets and liabilities on our Consolidated Balance Sheets. EIS is a captive insurance company with multiple protected cells in which oursubsidiaries participate in one protected cell for approximately ten lines ofinsurance. Neither AEP nor its subsidiaries have an equity investment in EIS.The AEP system is essentially this EIS cell's only participant, but allowcertain third parties access to this insurance. Our subsidiaries and anyallowed third parties share in the insurance coverage, premiums and risk of lossfrom claims. Based on the structure of the protected cell, we have concludedthat we are the primary beneficiary and that we are required to consolidate theprotected cell. Our insurance premium payments to EIS for the years endeddateMonth12Day31Year2008December 31, 2008 and 2007 were $28 million and $26million, respectively. See the tables below for the classification of EIS'sassets and liabilities on our Consolidated Balance Sheets. The balances below represent the assets and liabilities of the VIEs that areconsolidated. These balances include intercompany transactions that would beeliminated upon consolidation. AMERICAN ELECTRIC PLACEPOWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES DATEMONTH12DAY31YEAR2008DECEMBER 31, 2008 (IN MILLIONS) SWEPCO SWEPCO OPCO SABINE DHLC JMG EIS ------ ---- --- --- ASSETSCurrent Assets $ 33 $ 22 $ 11 $-------------- 107 Net Property, Plant and Equipment 117 33 423 -Other Noncurrent Assets 24 11 1 2TOTAL ASSETS $ 174 $ 66 $ 435 $ - --- - -- - --- - 109 --- LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities $ 32 $ 18 $ 161------------------- $ 30Noncurrent Liabilities 142 44 257 60Common Shareholders' Equity - 4 17 19TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 174 $ 66 - --- - -- $ 435 $ 109 - --- - --- AMERICAN ELECTRIC PLACEPOWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES DATEMONTH12DAY31YEAR2007DECEMBER 31, 2007 (IN MILLIONS) SWEPCO SWEPCO OPCO SABINE DHLC JMG EIS ====== === === ASSETSCurrent Assets $ 24 $ 29 $ 5 $-------------- -Net Property, Plant and Equipment 97 41 443 -Other Noncurrent Assets 25 13 1 21TOTAL ASSETS $ 146 $ 83 $ 449 $ - --- - -- - --- - 21 -- LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities $ 14 $ 26 $ 98------------------- $ -Noncurrent Liabilities 130 54 335 -Common Shareholders' Equity 2 3 16 21TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 146 $ 83 - --- - -- $ 449 $ 21 - --- - -- In September 2007, we and Allegheny (AYE) formed a joint venture by creatingPotomac-Appalachian Transmission Highline, LLC (PATH). PATH is a series limitedliability company and was created to construct a high-voltage transmission lineproject in the PJM region. PATH consists of the "Ohio Series," the "WestVirginia Series (PATH-WV)," both owned equally by AYE and us and the "AlleghenySeries" which is 100% owned by AYE. Provisions exist within the PATH-WVagreement that make it a VIE. The "Ohio Series" does not include the sameprovision that makes PATH-WV a VIE. The other series are not considered VIEs.We are not required to consolidate PATH-WV as we are not the primarybeneficiary, although we hold a significant interest in PATH-WV. Our equityinvestment in PATH-WV is included in Deferred Charges and Other on ourConsolidated Balance Sheets. We and AYE share the returns and losses equally inPATH-WV. Our subsidiaries and AYE's subsidiaries provide ser vices to the PATHcompanies through service agreements. At the current time, PATH-WV has no debtoutstanding. However, when debt is issued, the debt to equity ratio in eachsplaceCityeries will be consistent with other regulated utilities and theentities are designed to maintain this financing structure. The entitiesrecover costs through regulated rates. Given the structure of the entity, we may be required to provide futurefinancial support to PATH-WV in the form of a capital call. This would beconsidered an increase to our investment in the entity. Our maximum exposure toloss is to the extent of our investment. Currently the entity has no debtfinancing. The likelihood of such a loss is remote since the FERC approvedPATH-WV's request for regulatory recovery of cost and a return on the equityinvested. Our investment in PATH-WV as of dateMonth12Day31Year2008December 31, 2008 was: AS REPORTED ON THE CONSOLIDATED MAXIMUM BALANCE SHEET EXPOSURE ============= ======== (IN MILLIONS) ------------- Capital Contribution from Parent $ 4 $ 4 Retained Earnings 2 2 TOTAL INVESTMENT IN PATH-WV $ 6 $ 6 We record our investment in PATH-WV in Deferred Charges and Other on ourConsolidated Balance Sheets. As of dateMonth12Day31Year2007December 31, 2007,we did not make a capital contribution to PATH-WV and therefore had no retainedearnings. ACCOUNTING FOR THE EFFECTS OF COST-BASED REGULATION As the owner of cost-based rate-regulated electric public utility companies, ourconsolidated financial statements reflect the actions of regulators that resultin the recognition of certain revenues and expenses in different time periodsthan enterprises that are not rate-regulated. In accordance with SFAS 71,regulatory assets (deferred expenses) and regulatory liabilities (future revenuereductions or refunds) are recorded to reflect the economic effects ofregulation by matching expenses with their recovery through regulated revenuesand income with its passage to customers through the reduction of regulatedrevenues. Due to the commencement of legislatively required restructuring and atransition to customer choice and market-based rates, we discontinued theapplication of SFAS 71, regulatory accounting, for the generation portion of ourbusiness as follows: in Ohio for OPCo and CSPCo in September 2000, in Virginiafor APCo in June 2000 and in Texas for TCC and TNC and the Texas portion ofSWEPCo in September 1999. In 2007, the placeStateVirginia legislature amendedits restructuring legislation to provide for the re-regulation of generation andsupply 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 andstranded plant costs if they are not recoverable in regulated rates. Inaddition, an enterprise is required to eliminate from its balance sheet theeffects of any actions of regulators that had been recognized as regulatoryassets and regulatory liabilities pursuant to SFAS 71. Such impairments andadjustments arising from the discontinuance or reapplication of SFAS 71 areclassified by SFAS 101 as an extraordinary item. Consistent with SFAS 101, APCorecorded an extraordinary reduction in earnings and shareholder's equity fromthe reapplication of SFAS 71 regulatory acc ounting in 2007 resulting from there-regulation of their generation and supply rates on a cost basis. USE OF ESTIMATES The preparation of these financial statements in conformity with accountingprinciples generally accepted in the United States of America (GAAP) requiresmanagement to make estimates and assumptions that affect the amounts reported inthe financial statements and accompanying notes. These estimates include, butare not limited to, inventory valuation, allowance for doubtful accounts,goodwill, intangible and long-lived asset impairment, unbilled electricityrevenue, valuation of long-term energy contracts, the effects of regulation,long-lived asset recovery, the effects of contingencies and certain assumptionsmade in accounting for pension and postretirement benefits. The estimates andassumptions used are based upon management's evaluation of the relevant factsand circumstances as of the date of the financial statements. Actual resultscould ultimately differ from those estimates. PROPERTY, PLANT AND EQUIPMENT AND EQUITY INVESTMENTS Electric utility property, plant and equipment are stated at original purchasecost. Property, plant and equipment of nonregulated operations and equityinvestments (included in Deferred Charges and Other) are stated at fair marketvalue at acquisition (or as adjusted for any applicable impairments) plus theoriginal cost of property acquired or constructed since the acquisition, lessdisposals. Additions, major replacements and betterments are added to the plantaccounts. For the Utility Operations segment, normal and routine retirementsfrom the plant accounts, net of salvage, are charged to accumulated depreciationfor both cost-based rate-regulated and most nonregulated operations under thegroup composite method of depreciation. The group composite method ofdepreciation assumes that on average, asset components are retired at the end oftheir useful lives and thus there is no gain or loss. The equipment in eachprimary electric plant account is identified as a separate gr oup. Under thegroup composite method of depreciation, continuous interim routine replacementsof items such as boiler tubes, pumps, motors, etc. result in the original cost,less salvage, being charged to accumulated depreciation. For the nonregulatedgeneration assets, a gain or loss would be recorded if the retirement is notconsidered an interim routine replacement. The depreciation rates that areestablished for the generating plants take into account the past history ofinterim capital replacements and the amount of salvage received. These ratesand the related lives are subject to periodic review. Gains and losses arerecorded for any retirements in the AEP River Operations and Generation andMarketing segments. Removal costs are charged to regulatory liabilities forcost-based rate-regulated operations and charged to expense for nonregulatedoperations. The costs of labor, materials and overhead incurred to operate andmaintain our plants are included in operat ing expenses. Long-lived assets are required to be tested for impairment when it is determinedthat the carrying value of the assets may no longer be recoverable or when theassets meet the held for sale criteria under SFAS 144, "Accounting for theImpairment or Disposal of Long-Lived Assets." Equity investments are requiredto be tested for impairment when it is determined there may be an other thantemporary loss in value. The fair value of an asset or investment is the amount at which that asset orinvestment could be bought or sold in a current transaction between willingparties, as opposed to a forced or liquidation sale. Quoted market prices inactive markets are the best evidence of fair value and are used as the basis forthe measurement, if available. In the absence of quoted prices for identical orsimilar assets or investments in active markets, fair value is estimated usingvarious internal and external valuation methods including cash flow analysis andappraisals. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) AND INTEREST CAPITALIZATION AFUDC represents the estimated cost of borrowed and equity funds used to financeconstruction projects that is capitalized and recovered through depreciationover the service life of regulated electric utility plant. For nonregulatedoperations, including generating assets in placeStateOhio and placeStateTexas,effective with the discontinuance of SFAS 71 regulatory accounting, interest iscapitalized during construction in accordance with SFAS 34, "Capitalization ofInterest Costs." VALUATION OF NONDERIVATIVE FINANCIAL INSTRUMENTS The book values of Cash and Cash Equivalents, Accounts Receivable, Short-termDebt and Accounts Payable approximate fair value because of the short-termmaturity of these instruments. The book value of the pre-April 1983 spentnuclear fuel disposal liability approximates the best estimate of its fairvalue. CASH AND CASH EQUIVALENTS Cash and Cash Equivalents include temporary cash investments with originalmaturities of three months or less. OTHER TEMPORARY INVESTMENTS Other Temporary Investments include marketable securities that we intend to holdfor less than one year, investments by our protected cell insurance company andfunds held by trustees primarily for the payment of debt. We classify our investments in marketable securities as available-for-sale orheld-to-maturity in accordance with the provisions of SFAS No. 115, "Accountingfor Certain Investments in Debt and Equity Securities" (SFAS 115). We do nothave any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments arecarried at fair value with the unrealized gain or loss, net of tax, reported inother comprehensive income. Held-to-maturity securities reflected in OtherTemporary Investments are carried at amortized cost. The cost of securitiessold is based on the specific identification or weighted average cost method.The fair value of most investment securities is determined by currentlyavailable market prices. Where quoted market prices are not available, we usethe market price of similar types of securities that are traded in the market toestimate fair value. In evaluating potential impairment of securities with unrealized losses, weconsidered, among other criteria, the current fair value compared to cost, thelength of time the security's fair value has been below cost, our intent andability to retain the investment for a period of time sufficient to allow forany anticipated recovery in value and current economic conditions. During 2008,2007 and 2006, we did not record any other-than-temporary impairments of OtherTemporary Investments. The following is a summary of Other Temporary Investments: DECEMBER 31, ============ 2008 2007 ESTIMATED ESTIMATED FAIR FAIR COST GROSS UNREALIZED GAINS GROSS UNREALIZED LOSSES ---- ---------------------- VALUE COST GROSS UNREALIZED GAINS GROSSUNREALIZED LOSSES VALUE OTHER TEMPORARY INVESTMENTS (IN MILLIONS) ------------- Cash (a) $ 243 $ - $ - $ 243-------- $ 273 $ - $ - $ 273 Debt Securities 56 - - 56 66 - - 66 Corporate Equity Securities 27 11 10 28 - 26 - 26TOTAL OTHER TEMPORARY INVESTMENTS $ 326 $ 11 - --- - -- $ 10 $ 327 $ 339 $ 26 $ - -- - --- - --- - -- - - $ 365 - - --- (a) Primarily represents amounts held for the payment of debt. Proceeds from sales of current available-for-sale securities were $1.2 billion,$10.5 billion and $17.4 billion in 2008, 2007 and 2006, respectively. Purchasesof current available-for-sale securities were $1.1 billion, $10.3 billion and$17.7 billion in 2008, 2007 and 2006, respectively. During 2008, there were nogross realized gains or losses from the sale of current available-for-salesecurities. Gross realized gains from the sale of current available-for-salesecurities were $16 million and $39 million in 2007 and 2006, respectively.Gross realized losses from the sale of current available-for-sale securitieswere not material in 2007 or 2006. At dateMonth12Day31Year2008December 31,2008, the fair value of corporate equity securities with an unrealized lossposition was $17 million and we had no investments in a continuous unrealizedloss position for more than twelve months. At dateMonth12Day31Year2008December 31, 2008, the fair value of debt securities are primarily debt based mutualfunds with short-term, intermediate and long-term maturities. INVENTORY Fossil fuel inventories are generally carried at average cost. Materials andsupplies inventories are carried at average cost. ACCOUNTS RECEIVABLE Customer accounts receivable primarily include receivables from wholesale andretail energy customers, receivables from energy contract counterparties relatedto our risk management activities and customer receivables primarily related toother revenue-generating activities. We recognize revenue from electric power sales when we deliver power to ourcustomers. To the extent that deliveries have occurred but a bill has not beenissued, we accrue and recognize, as Accrued Unbilled Revenues on ourConsolidated Balance Sheets, an estimate of the revenues for energy deliveredsince the last billing. AEP Credit factors accounts receivable for certain subsidiaries, includingCSPCo, I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCodoes not have regulatory authority to sell accounts receivable in itsplaceStateWest Virginia regulatory jurisdiction, only a portion of APCo'saccounts receivable are sold to AEP Credit. AEP Credit has a sale ofreceivables agreement with banks and commercial paper conduits. Under the saleof receivables agreement, AEP Credit sells an interest in the receivables itacquires to the commercial paper conduits and banks and receives cash. Thistransaction constitutes a sale of receivables in accordance with SFAS 140,"Accounting for Transfers and Servicing of Financial Assets and Extinguishmentsof Liabilities," allowing the receivables to be removed from the company'sbalance sheet (see "Sale of Receivables - AEP Credit" section of Note 14). DEFERRED FUEL COSTS The cost of fuel and related emission allowances and emission controlchemicals/consumables is charged to Fuel and Other Consumables Used for ElectricGeneration expense when the fuel is burned or the allowance or consumable isutilized. The cost of fuel also includes the amortization of nuclear fuelcosts which are computed primarily on the units-of-production method. Whereapplicable under governing state regulatory commission retail rate orders, fuelcost over-recoveries (the excess of fuel revenues billed to customers overapplicable fuel costs incurred) are deferred as current regulatory liabilitiesand under-recoveries (the excess of applicable fuel costs incurred over fuelrevenues billed to customers) are deferred as current regulatory assets. Thesedeferrals are amortized when refunded or when billed to customers in latermonths with the regulator's review and approval. The amount of an over-recoveryor under-recovery can also be affected by actions of regulator s. On a routinebasis, state regulatory commissions audit our fuel cost calculations anddeferrals. When a fuel cost disallowance becomes probable, we adjust ourdeferrals and record provisions for estimated refunds to recognize theseprobable outcomes. Fuel cost over-recovery and under-recovery balances areclassified as noncurrent when the fuel clauses have been suspended orterminated. In general, changes in fuel costs in Kentucky for KPCo, Indiana (beginning July1, 2007) and Michigan for I&M, Texas, Louisiana and Arkansas for SWEPCo,Oklahoma for PSO and Virginia and West Virginia (beginning July 1, 2006) forAPCo are reflected in rates in a timely manner through the fuel cost adjustmentclauses in place in those states. All of the profits from off-system sales areshared with customers through fuel clauses in placeStateWest Virginia (beginningdateMonth7Day1Year2006July 1, 2006). A portion of profits from off-system salesare shared with customers through fuel clauses in Texas, placeStateOklahoma,placeStateLouisiana, placeStateArkansas, placeStateKentucky, placeStateVirginia(beginning dateMonth9Day1Year2007September 1, 2007) and in some areas ofplaceStateMichigan. Where fuel clauses have been eliminated due to thetransition to market pricing (placeStateOhio effective January 1, 2001), changesin fuel costs impact earnings unless recovered in th e sales price forelectricity. In other state jurisdictions (prior to July 1, 2007 in Indiana andprior to July 1, 2006 in West Virginia), where fuel clauses were capped, frozenor suspended for a period of years, fuel costs impacted earnings. REVENUE RECOGNITION Regulatory Accounting Our consolidated financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periodsthan enterprises that are not rate-regulated. Regulatory assets (deferredexpenses) and regulatory liabilities (deferred revenue reductions or refunds)are recorded to reflect the economic effects of regulation by matching expenseswith their recovery through regulated revenues in the same accounting period andby matching income with its passage to customers in cost-based regulated rates.Regulatory liabilities or regulatory assets are also recorded for unrealized MTMgains or losses that occur due to changes in the fair value of physical and/orfinancial contracts that are derivatives and that are subject to the regulatedratemaking process when realized. When regulatory assets are probable of recovery through regulated rates, werecord them as assets on our Consolidated Balance Sheets. We test forprobability of recovery at each balance sheet date or whenever new events occur.Examples include the issuance of a regulatory commission order or passage of newlegislation. If it is determined that recovery of a regulatory asset is nolonger probable, we write off that regulatory asset as a charge against income. Traditional Electricity Supply and Delivery Activities Revenues are recognized from retail and wholesale electricity sales andelectricity transmission and distribution delivery services. We recognize therevenues on our Consolidated Statements of Income upon delivery of the energy tothe customer and include unbilled as well as billed amounts. In accordance withthe applicable state commission regulatory treatment, PSO and SWEPCo do notrecord the fuel portion of unbilled revenue. Most of the power produced at the generation plants of the AEP East companies issold to PJM, the RTO operating in the east service territory. We purchase powerfrom PJM to supply our customers. These power sales and purchases are reportedon a net basis as revenues on our Consolidated Statements of Income. Other RTOsin which we operate do not function in the same manner as PJM. They function asbalancing organizations and not as exchanges. Physical energy purchases, including those from RTOs, that are identified asnon-trading, but excluding PJM purchases described in the preceding paragraph,are accounted for on a gross basis in Purchased Electricity for Resale on ourConsolidated Statements of Income. In general, we record expenses when purchased electricity is received and whenexpenses are incurred, with the exception of certain power purchase contractsthat are derivatives and accounted for using MTM accounting wheregeneration/supply rates are not cost-based regulated, such as in Ohio and theERCOT portion of Texas. In jurisdictions where the generation/supply businessis subject to cost-based regulation, the unrealized MTM amounts are deferred asregulatory assets (for losses) and regulatory liabilities (for gains). For power purchased under derivative contracts in our west zone where we areshort capacity, we recognize as revenues the unrealized gains and losses (otherthan those subject to regulatory deferral) that result from measuring thesecontracts at fair value during the period before settlement. If the contractresults in the physical delivery of power from a RTO or any other counterparty,we reverse the previously recorded unrealized gains and losses from MTMvaluations and record the settled amounts gross as Purchased Electricity forResale. If the contract does not result in physical delivery, we reverse thepreviously recorded unrealized gains and losses from MTM valuations and recordthe settled amounts as Revenues on our Consolidated Statements of Income on anet basis (see "Derivatives and Hedging" section of Note 11). Energy Marketing and Risk Management Activities We engage in wholesale electricity, natural gas, coal and emission allowancesmarketing and risk management activities focused on wholesale markets where weown assets and adjacent markets. Our activities include the purchase and saleof energy under forward contracts at fixed and variable prices and the buyingand selling of financial energy contracts, which include exchange traded futuresand options, as well as over-the-counter options and swaps. We engage incertain energy marketing and risk management transactions with RTOs. We recognize revenues and expenses from wholesale marketing and risk managementtransactions that are not derivatives upon delivery of the commodity. We useMTM accounting for wholesale marketing and risk management transactions that arederivatives unless the derivative is designated in a qualifying cash flow hedgerelationship or a normal purchase or sale. We include the unrealized andrealized gains and losses on wholesale marketing and risk managementtransactions that are accounted for using MTM in Revenues on our ConsolidatedStatements of Income on a net basis. In jurisdictions subject to cost-basedregulation, we defer the unrealized MTM amounts as regulatory assets (forlosses) and regulatory liabilities (for gains). We include unrealized MTM gainsand losses resulting from derivative contracts on our Consolidated BalanceSheets as Risk Management Assets or Liabilities as appropriate. Certain qualifying wholesale marketing and risk management derivativetransactions are designated as hedges of variability in future cash flows as aresult of forecasted transactions (cash flow hedge). We initially record theeffective 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, wesubsequently reclassify the gain or loss on the hedge from Accumulated OtherComprehensive Income into revenues or expenses within the same financialstatement line item as the forecasted transaction on our Consolidated Statementsof Income. Excluding those jurisdictions subject to cost-based regulation, werecognize the ineffective portion of the gain or loss in revenues or expenseimmediately on our Consolidated Statements of Income, depending on the specificnature of the associated hedged risk. In regulated jurisdictions, we defer theineffective portion as regulatory assets (for losses) and regulator y liabilities(for gains) (see "Cash Flow Hedging Strategies" section of Note 11). Barging Activities AEP River Operations' revenue is recognized based on percentage of voyagecompletion. The proportion of freight transportation revenue to be recognizedis determined by applying a percentage to the contractual charges for suchservices. The percentage is determined by dividing the number of miles from theloading point to the position of the barge as of the end of the accountingperiod by the total miles to the destination specified in the customer's freightcontract. The position of the barge at accounting period end is determined byour computerized barge tracking system. Construction Projects for Outside Parties We engage in construction projects for outside parties and account for theprojects on the percentage-of-completion method of revenue recognition. Thismethod recognizes revenue, including the related margin, as we incur projectcosts. We include such revenue and related expenses in Utility Operationsrevenue and Other Operation and Maintenance expense on ourplacePlaceNameConsolidated PlaceTypeStatements of Income. We also includecontractually billable expenses not yet billed in Current Assets on ourConsolidated Balance Sheets. LEVELIZATION OF NUCLEAR REFUELING OUTAGE COSTS In order to match costs with nuclear refueling cycles, I&M defers incrementaloperation and maintenance costs associated with periodic refueling outages atits Cook Plant and amortizes the costs over the period beginning with the monthfollowing the start of each unit's refueling outage and lasting until the end ofthe month in which the same unit's next scheduled refueling outage begins. I&Madjusts the amortization amount as necessary to ensure full amortization of alldeferred costs by the end of the refueling cycle. MAINTENANCE We expense maintenance costs as incurred. If it becomes probable that we willrecover specifically-incurred costs through future rates, we establish aregulatory asset to match the expensing of those maintenance costs with theirrecovery in cost-based regulated revenues. We defer distribution tree trimmingcosts for PSO and amortize the costs above the level included in base ratescommensurate with recovery through a rate rider in placeStateOklahoma. INCOME TAXES AND INVESTMENT TAX CREDITS We use the liability method of accounting for income taxes. Under the liabilitymethod, we provide deferred income taxes for all temporary differences betweenthe book and tax basis of assets and liabilities which will result in a futuretax consequence. When the flow-through method of accounting for temporary differences isreflected in regulated revenues (that is, when deferred taxes are not includedin the cost of service for determining regulated rates for electricity), werecord deferred income taxes and establish related regulatory assets andliabilities to match the regulated revenues and tax expense. We account for investment tax credits under the flow-through method except whereregulatory commissions reflect investment tax credits in the rate-making processon a deferral basis. We amortize deferred investment tax credits over the lifeof the plant investment. We account for uncertain tax positions in accordance with FIN 48. Effectivewith the adoption of FIN 48 beginning dateYear2007Day1Month1January 1, 2007, weclassify interest expense or income related to uncertain tax positions asinterest expense or income as appropriate and classify penalties as OtherOperation and Maintenance. EXCISE TAXES We act as an agent for some state and local governments and collect fromcustomers certain excise taxes levied by those state or local governments on ourcustomers. We do not recognize these taxes as revenue or expense. DEBT AND PREFERRED STOCK We defer gains and losses from the reacquisition of debt used to financeregulated electric utility plants and amortize the deferral over the remainingterm of the reacquired debt in accordance with their rate-making treatmentunless the debt is refinanced. If we refinance the reacquired debt associatedwith the regulated business, the reacquisition costs attributable to theportions of the business subject to cost-based regulatory accounting aregenerally deferred and amortized over the term of the replacement debtconsistent with its recovery in rates. Some jurisdictions require that thesecosts be expensed upon reacquisition. We report gains and losses on thereacquisition of debt for operations not subject to cost-based rate regulationin Interest Expense on our Consolidated Statements of Income. We defer debt discount or premium and debt issuance expenses and amortizegenerally utilizing the straight-line method over the term of the related debt.The straight-line method approximates the effective interest method and isconsistent with the treatment in rates for regulated operations. We include theamortization expense in Interest Expense on our Consolidated Statements ofIncome. Where reflected in rates, we include redemption premiums paid to reacquirepreferred stock of certain utility subsidiaries in paid-in capital and amortizethe premiums to retained earnings commensurate with recovery in rates. Wecredit the excess of par value over costs of preferred stock reacquired topaid-in capital and reclassify the excess to retained earnings upon theredemption of the entire preferred stock series. We credit the excess of parvalue over the costs of reacquired preferred stock for nonregulated subsidiariesto retained earnings upon reacquisition. GOODWILL AND INTANGIBLE ASSETS When we acquire businesses, we record the fair value of all assets andliabilities, including intangible assets. To the extent that considerationexceeds the fair value of identified assets, we record goodwill. We do notamortize goodwill and intangible assets with indefinite lives. We test acquiredgoodwill and other intangible assets with indefinite lives for impairment atleast annually at their estimated fair value. We test goodwill at the reportingunit level and other intangibles at the asset level. Fair value is the amountat which an asset or liability could be bought or sold in a current transactionbetween willing parties, that is, other than in a forced or liquidation sale.Quoted market prices in active markets are the best evidence of fair value andare used as the basis for the measurement, if available. In the absence ofquoted prices for identical or similar assets in active markets, we estimatefair value using various internal and external valuation meth ods. We amortizeintangible assets with finite lives over their respective estimated lives,currently ranging from timeHour17Minute05 to 15 years, to their estimatedresidual values. We also review the lives of the amortizable intangibles withfinite lives on an annual basis. EMISSION ALLOWANCES We record emission allowances at cost, including the annual SO2 and NOx emissionallowance entitlements received at no cost from the Federal EPA and States. Wefollow the inventory model for these allowances. We record allowances expectedto be consumed within one year in Materials and Supplies and allowances withexpected consumption beyond one year in Other Noncurrent Assets - DeferredCharges and Other on our Consolidated Balance Sheets. We record the consumptionof allowances in the production of energy in Fuel and Other Consumables Used forElectric Generation on our Consolidated Statements of Income at an average cost.We record allowances held for speculation in Current Assets - Prepayments andOther on our Consolidated Balance Sheets. We report the purchases and sales ofallowances in the Operating Activities section of the Statements of Cash Flows.We record the net margin on sales of emission allowances in Utility OperationsRevenue on our Consolidated Statements of Income because of it s integral natureto the production process of energy and our revenue optimization strategy forour utility operations. The net margin on sales of emission allowances affectsthe determination of deferred fuel costs and the amortization of regulatoryassets for certain jurisdictions. NUCLEAR TRUST FUNDS Nuclear decommissioning and spent nuclear fuel trust funds represent funds thatregulatory commissions allow us to collect through rates to fund futuredecommissioning and spent nuclear fuel disposal liabilities. By rules ororders, the IURC, the MPSC and the FERC established investment limitations andgeneral risk management guidelines. In general, limitations include: Acceptable investments (rated investment grade or above when purchased). Maximum percentage invested in a specific type of investment. Prohibition of investment in obligations of AEP or its affiliates. Withdrawals permitted only for payment of decommissioning costs and trustexpenses. We maintain trust funds for each regulatory jurisdiction. These funds aremanaged by external investment managers who must comply with the guidelines andrules of the applicable regulatory authorities. The trust assets are investedto optimize the net of tax earnings of the trust giving consideration toliquidity, risk, diversification, and other prudent investment objectives. We record securities held in these trust funds as Spent Nuclear Fuel andDecommissioning Trusts on our Consolidated Balance Sheets. We record thesesecurities at market value. We classify securities in the trust funds asavailable-for-sale due to their long-term purpose. Other-than-temporary impairments are considered realized losses as we do not make specific investmentdecisions regarding the assets held in these trusts. They reduce the cost basisof the securities which will affect any future unrealized gain or realized gainsor losses. We record unrealized gains and other-than-temporary impairments fromsecurities in these trust funds as adjustments to the regulatory liabilityaccount for the nuclear decommissioning trust funds and to regulatory assets orliabilities for the spent nuclear fuel disposal trust funds in accordance withtheir treatment in rates. See Note 9 for additional discussion of nuclearmatters. COMPREHENSIVE INCOME (LOSS) Comprehensive income (loss) is defined as the change in equity (net assets) of abusiness enterprise during a period from transactions and other events andcircumstances from nonowner sources. It includes all changes in equity during aperiod except those resulting from investments by owners and distributions toowners. Comprehensive income (loss) has two components: net income (loss) andother comprehensive income (loss). COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)(AOCI) AOCI is included on our Consolidated Balance Sheets in our common shareholders'equity section. The following table provides the components that constitute thebalance sheet amount in AOCI: DECEMBER 31, 2008 2007 COMPONENTS (IN MILLIONS)Securities Available for placeCitySale, Net of Tax $ 1 $-------------------------------------------------- 17 Cash Flow Hedges, Net of Tax (22) (26) Amortization of Pension and OPEB Deferred Costs, Net of Tax 12 - Pension and OPEB Funded Status, Net of Tax (443) (145) TOTAL $ (452) $ (154) - ----- - ----- STOCK-BASED COMPENSATION PLANS At dateMonth12Day31Year2008December 31, 2008, we had stock options, performanceunits, restricted shares and restricted stock units outstanding to employeesunder The Amended and Restated American Electric Power System Long-TermIncentive Plan (LTIP). This plan was last approved by shareholders in 2005. We maintain career share accounts under the Stock Ownership Requirement Plan tofacilitate executives in meeting minimum stock ownership requirements assignedto executives by the HR Committee of the Board of Directors. Career shares arederived from vested performance units granted to employees under the LTIP.Career shares are equal in value to shares of AEP common stock and do not becomepayable to executives until after their service ends. Dividends paid on careershares are reinvested as additional career shares. We also compensate our non-employee directors, in part, with stock units underThe Stock Unit Accumulation Plan for Non-Employee Directors. These stock unitsbecome payable in cash to Directors after their service ends. In addition, we maintain a variety of tax qualified and nonqualified deferredcompensation plans for employees and non-employee directors that include, amongother options, an investment in or an investment return equivalent to that ofAEP stock. On January 1, 2006, we adopted SFAS No. 123 (revised 2004), "Share-BasedPayment" (SFAS 123R), which requires the measurement and recognition ofcompensation expense for all share-based payment awards made to employees anddirectors including stock options and employee stock purchases based onestimated fair values. We recognize compensation expense for all share-based payment awards withservice only condition granted on or after dateMonth1Day1Year2006January 1, 2006using the straight-line single-option method. In 2008, 2007 and 2006, wegranted awards with performance conditions which are expensed on the acceleratedmultiple-option approach. Stock-based compensation expense recognized on ourConsolidated Statements of Income for the years ended dateMonth12Day31Year2008December 31, 2008, 2007 and 2006 is based on awardsultimately expected to vest. Therefore, stock-based compensation expense hasbeen reduced to reflect estimated forfeitures. SFAS 123R requires forfeituresto be estimated at the time of grant and revised, if necessary, in subsequentperiods if actual forfeitures differ from those estimates. For the years ended December 31, 2008, 2007 and 2006, compensation cost isincluded in Net Income for the performance share units, phantom stock units,restricted shares, restricted stock units and the Director's stock units. SeeNote 15 for additional discussion. EARNINGS PER SHARE (EPS) Basic earnings per common share is calculated by dividing net earnings availableto common shareholders by the weighted average number of common sharesoutstanding during the period. Diluted earnings per common share is calculatedby adjusting the weighted average outstanding common shares, assuming conversionof all potentially dilutive stock options and awards. The following table presents our basic and diluted EPS calculations included onour Consolidated Statements of Income: YEARS ENDED DECEMBER 31, 2008 2007 2006 (IN --- MILLIONS, EXCEPT PER SHARE DATA) -------------------------------- $/SHARE $/SHARE $/SHAREEARNINGS APPLICABLE TO COMMON STOCK $ 1,380 $ 1,089 $ 1,002 Average Number of Basic Shares Outstanding 402.1 $ 3.43 398.8 $ 2.73 394.2 $ 2.54Average Dilutive Effect of: Performance Share Units 1.2 0.01 0.9 0.01 1.8 0.01 Stock Options 0.1 - 0.3 - 0.3 -Restricted Stock Units 0.1 - 0.1 - 0.1 - Restricted Shares 0.1 - 0.1 - 0.1 - AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING 403.6 $ ----- - 3.42 400.2 $ 2.72 396.5 $ ---- ----- - ---- ----- - 2.53 ---- The assumed conversion of stock options does not affect net earnings (loss) forpurposes of calculating diluted earnings per share. Options to purchase 470,016, 83,150 and 367,500 shares of common stock wereoutstanding at dateMonth12Day31Year2008December 31, 2008, 2007 and 2006,respectively, but were not included in the computation of diluted earnings pershare. Since the options' exercise prices were greater than the year-end marketprice of the common shares, the effect would be antidilutive. SUPPLEMENTARY INFORMATION YEARS ENDED DECEMBER 31, 2008 2007 2006 RELATED PARTY TRANSACTIONS (IN MILLIONS) AEP CONSOLIDATED REVENUES - UTILITY OPERATIONS:-----------------------------------------------Power Pool Purchases - Ohio Valley Electric Corporation (43.47% Owned) $ (54) $ (29) $ (37)AEP CONSOLIDATED REVENUES - OTHER:Ohio Valley Electric Corporation - Barging and Other Transportation Services (43.47% Owned) 32 31 28AEP CONSOLIDATED EXPENSES - PURCHASED ENERGY FOR RESALE: Ohio Valley Electric Corporation (43.47% Owned) 263 226 223 Sweeny Cogeneration Limited Partnership (a) - 86 121 (a) In October 2007, we sold our 50% ownership in the Sweeny CogenerationLimited Partnership. See "Sweeny Cogeneration Plant" section of Note 7. YEARS ENDED DECEMBER 31, 2008 2007 2006 CASH FLOW INFORMATION (IN MILLIONS) ------------- Cash paid for:--------------Interest, Net of Capitalized Amounts $ 853 $ 734 $ 664 Income Taxes, Net of Refunds 233 576 358Noncash Investing and Financing Activities:Acquisitions Under Capital Leases 62 160 106Assumption of Liabilities Related to Acquisitions/Divestitures, Net - 8 -Disposition of Assets Related to Electric Transmission placeStateTexas Joint Venture - (14) -Construction Expenditures Included in Accounts Payable at December 31, 460 345 404Acquisition of Nuclear Fuel Included in Accounts Payable at December 31, 38 84 -Noncash Donation Expense Related to Issuance of Treasury Shares to AEP Foundation 40 - - TRANSMISSION INVESTMENTS We participate in certain joint ventures which involve transmission projects toown and operate transmission facilities. These investments are recorded usingthe equity method and reported as Deferred Charges and Other on our ConsolidatedBalance Sheets. POWER PROJECTS During 2007, we sold our 50% interest in Sweeny, a nonregulated power plant witha capacity of 480 MW located in placeStateTexas. Our 50% interest in aninternational power plant totaling 600 MW located in placecountry-regionMexico was sold in 2006 (see "Dispositions" section of Note 7). We account for investments in power projects that are 50% or less owned usingthe equity method and report them as Deferred Charges and Other on ourConsolidated Balance Sheets. RECLASSIFICATIONS Certain prior period financial statement items have been reclassified to conformto current period presentation. See "FSP FIN 39-1 "Amendment of FASBInterpretation No. 39" section of Note 2 for discussion of changes in nettingcertain balance sheet amounts. These reclassifications had no impact on ourpreviously reported net income or changes in shareholders' equity. ORGANIZATION The principal business conducted by seven of our electric utility operating companies is the generation, transmission and distribution of electric power. TCC exited the generation business and along with WPCo and KGPCo, provide only transmission and distribution services. TNC is a part owner in the Oklaunion Plant operated by PSO. TNC leases their entire portion of the output of the plant through 2027 to a non-utility affiliate. AEGCo is a regulated electricity generation business whose function is to provide power to our regulated electric utility operating companies. These companies are subject to regulation by the FERC under the Federal Power Act and the Energy Policy Act of 2005. These companies 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. We also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States. In addition, our operations include nonregulated wind farms and barging operations and we provide various energy-related services. Yes 0000004904 12000000 0 0 12000000 0 0 2774000000 2546000000 3359000000 90000000 222000000 186000000 -160000000 -512000000 0 -183000000 16000000 -187000000 -13000000 -26000000 -14000000 88000000 65000000 50000000 1368000000 1065000000 992000000 0 -0.20 0 3925000000 3867000000 3639000000 600000000 600000000 447000000 792000000 876000000 888000000 1260000000 1347000000 21242000000 20233000000 284000000 11000000 RATE MATTERS ------------- Our subsidiaries are involved in rate and regulatory proceedings at the FERC andtheir state commissions. This note is a discussion of rate matters and industryrestructuring related proceedings that could have a material effect on netincome and cash flows. For discussion of the FERC's November 2008 order on AEP's allocation ofoff-system sales, see "Allocation of Off-system Sales Margins" section within"FERC Rate Matters". PLACESTATEOHIO RATE MATTERS - ----------------------------- PLACESTATEOHIO ELECTRIC SECURITY PLAN FILINGS In April 2008, the placeStateOhio legislature passed Senate Bill 221, whichamended the restructuring law effective dateYear2008Day31Month7July 31, 2008 andrequired electric utilities to adjust their rates by filing an Electric SecurityPlan (stocktickerESP). Electric utilities could include a fuel cost recoverymechanism (FCR) in their ESP filing. Electric utilities also had an option tofile a Market Rate Offer (stocktickerMRO) for generation pricing. AnstocktickerMRO, from the date of its commencement, would have transitioned CSPCoand OPCo to full market rates no sooner than six years and no later than tenyears after the PUCO approves an MRO. The PUCO has the authority to approveand/or modify each utility's stocktickerESP request. The PUCO is required toapprove an stocktickerESP if, in the aggregate, the stocktickerESP is morefavorable to ratepayers than an stocktickerMRO. Both alternatives involve a"significantly excessive earnings" test (SEET) based on what pub lic 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 thePUCO to establish rates for 2009 through 2011. CSPCo and OPCo did not file anoptional MRO. CSPCo's and OPCo's ESP filings requested an annual rate increasefor 2009 through 2011 that would not exceed approximately 15% per year. Asignificant portion of the requested ESP increases resulted from theimplementation of a FCR that primarily includes fuel costs, purchased powercosts, consumables such as urea, other variable production costs and gains andlosses on sales of emission allowances. The FCR is proposed to be phased intocustomer bills over the three-year period from 2009 through 2011 and recoveredwith a weighted average cost of capital carrying cost deferral over seven yearsfrom 2012 through 2018. If the ESPs are approved as filed, effective with theimplementation of the ESPs, CSPCo and OPCo will defer fuel costover/under-recoveries and related carrying costs, including amounts unre coveredthrough the phase in period, for future recovery. In addition to the FCR, the requested ESP increases would also recoverincremental carrying costs associated with environmental costs, Provider of LastResort (POLR) charges to compensate for the risk of customers changing electricsuppliers, automatic increases for distribution reliability costs and forunexpected non-fuel generation costs. The filings also include recovery forprograms for smart metering initiatives, economic development, mandated energyefficiency, renewable resources and peak demand reduction programs. Within the ESP requests, CSPCo and OPCo would also recover existing regulatoryassets of $47 million and $39 million, respectively, for customer choiceimplementation and line extension carrying costs incurred through December 2008.In addition, CSPCo and OPCo would recover related unrecorded equity carryingcosts of $31 million and $23 million, respectively, through December 2008. ThePUCO had previously issued orders allowing deferral of these costs. Such costswould be recovered over an 8-year period beginning January 2011. If the PUCOdoes not approve recovery of these regulatory assets in this or some futureproceeding, it would have an adverse effect on future net income and cash flows. Hearings were held in November and December 2008. Many intervenors filedopposing testimony. CSPCo and OPCo requested retroactive application of the newrates, including the FCR, back to the start of the January 2009 billing cycleupon approval of the ESPs. The RSP rates were effective for the years endeddateYear2006Day31Month12December 31, 2006, 2007 and 2008 under which CSPCo andOPCo had three annual generation rate increases of 3% and 7%, respectively. TheRSP also allowed additional annual generation rate increases of up to an averageof 4% per year to recover new governmentally-mandated costs. In January 2009,CSPCo and OPCo filed an application requesting the PUCO to authorize deferredfuel accounting beginning dateYear2009Day1Month1January 1, 2009. A motion todismiss 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 ratesuntil the PUCO issues a ruling on the ESPs or the end of the March 2009 billingcycle, whichever comes first. Management is unable to predict the financialstatement impact of the restructuring legislation until the PUCO acts onspecific proposals made by CSPCo and OPCo in their ESPs. CSPCo and OPCoanticipate a final order from the PUCO during the first quarter of 2009. 2008 GENERATION RIDER AND TRANSMISSION RIDER RATE SETTLEMENT On dateYear2008Day30Month1January 30, 2008, the PUCO approved a settlementagreement, among CSPCo, OPCo and other parties, under the additional average 4%generation rate increase and transmission cost recovery rider (TCRR) provisionsof the RSP. The increase was due to additional governmentally-mandated costsincluding incremental environmental costs. Under the settlement, the PUCO alsoapproved recovery through the TCRR of increased PJM costs associated withtransmission 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 ofincreased PJM billings previously expensed from June 2007 to December 2007 fortransmission line losses. The PUCO also approved a credit applied to the TCRRof $10 million for OPCo and $8 million for CSPCo for a reduction in PJM netcongestion costs. To the extent that collections for the TC RR recoveries areunder/over actual net costs, CSPCo and OPCo will defer the difference as aregulatory asset or regulatory liability and adjust future customer billings toreflect actual costs, including carrying costs on the deferral. In addition,the PUCO approved recoveries through generation rates of environmental costs andrelated carrying costs of $29 million for CSPCo and $5 million for OPCo. TheseRSP rate adjustments were implemented in February 2008. The TCRR continues inCSPCo's and OPCo's proposed ESPs to provide for the recovery of PJM relatedcosts. 2009 GENERATION RIDER AND TRANSMISSION RIDER In October 2008, CSPCo and OPCo filed an application to update the TCRR. Theapplication requested an average decrease of 3% for CSPCo and an averageincrease of 7% for OPCo, including under recoveries from the prior year andrelated carrying charges. Based on the requests, CSPCo's annual revenues woulddecrease approximately $5 million and OPCo's annual revenues would increaseapproximately $13 million. In December 2008, the PUCO issued a final order approving the application withcertain modifications. First, the rate to calculate carrying costs will changefrom using a current weighted average cost of capital rate (WACC), whichincludes a return on equity and a gross up for income taxes, to a long-term debtrate. 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-relatedcredit which had been applied against the PJM transmission marginal line losssince CSPCo's and OPCo's proposed fuel adjustment clause in the filing of theESP includes this credit. The new TCRR became effective with the January 2009billing cycle. PLACESTATEOHIO IGCC PLANT In March 2005, CSPCo and OPCo filed a joint application with the PUCO seekingauthority to recover costs related to building and operating a 629 MW IGCC powerplant using clean-coal technology. The application proposed three phases ofcost recovery associated with the IGCC plant: Phase 1, recovery of $24 millionin pre-construction costs; Phase 2, concurrent recovery ofconstruction-financing costs; and Phase 3, recovery or refund in distributionrates of any difference between the generation rates which may be a market-basedstandard service offer price for generation and the expected higher cost ofoperating and maintaining the plant, including a return on and return of theprojected cost to construct the plant. In June 2006, the PUCO issued an order approving a tariff to allow CSPCo andOPCo to recover Phase 1 pre-construction costs over a period of no more thantwelve months effective dateYear2006Day1Month7July 1, 2006. During that periodCSPCo and OPCo each collected $12 million in pre-construction costs and incurred$11 million in pre-construction costs. As a result, CSPCo and OPCo eachestablished a net regulatory liability of approximately $1 million. The order also provided that if CSPCo and OPCo have not commenced a continuouscourse of construction of the proposed IGCC plant within five years of the June2006 PUCO order, all Phase 1 cost recoveries associated with items that may beutilized in projects at other sites must be refunded to Ohio ratepayers withinterest. The PUCO deferred ruling on cost recovery for Phases 2 and 3 pendingfurther hearings. In 2006, intervenors filed four separate appeals of the PUCO's order in the IGCCproceeding. In March 2008, the Ohio Supreme Court issued its opinion affirmingin part, and reversing in part the PUCO's order and remanded the matter back tothe PUCO. The Ohio Supreme Court held that while there could be an opportunityunder existing law to recover a portion of the IGCC costs in distribution rates,traditional rate making procedures would apply to the recoverable portion. TheOhio Supreme Court did not address the matter of refunding the Phase 1 costrecovery and declined to create an exception to its precedent of denying claimsfor refund of past recoveries from approved orders of the PUCO. In September2008, the Ohio Consumers' Counsel filed a motion with the PUCO requesting allPhase 1 costs be refunded to placeStateOhio ratepayers with interest because theOhio Supreme Court invalidated the underlying foundation for the Phase 1recovery. In October 2008, CSPCo and OPCo filed a motion w ith the PUCO thatargued the Ohio Consumers' Counsel's motion was without legal merit and contraryto past precedent. In January 2009, a PUCO Attorney Examiner issued an order that CSPCo and OPCofile a detailed statement outlining the status of the construction of the IGCCplant, including whether CSPCo and OPCo are engaged in a continuous course ofconstruction on the IGCC plant. In February 2009, CSPCo and OPCo filed astatement that CSPCo and OPCo have not commenced construction of the IGCC plantand believe there exist real statutory barriers to the construction of any newbase load generation in placeStateOhio, including IGCC plants. The statementalso indicated that while construction on the IGCC plant might not begin by June2011, changes in circumstances could result in the commencement of constructionon a continuous course by that time. As of December 2007 the estimate cost to build the IGCC plant was $2.7 billionwhich has continued to increase significantly. Management continues to pursuethe ultimate construction of the IGCC plant. However, CSPCo and OPCo will notstart construction of the IGCC plant until sufficient assurance of regulatorycost recovery exists. If CSPCo and OPCo were required to refund the $24 million collected and thosecosts were not recoverable in another jurisdiction in connection with theconstruction of an IGCC plant, it would have an adverse effect on future netincome and cash flows. Management cannot predict the outcome of the costrecovery litigation concerning the Ohio IGCC plant or what, if any effect, thelitigation will have on future net income and cash flows. ORMET Effective dateYear2007Day1Month1January 1, 2007, CSPCo and OPCo began to serveOrmet, a major industrial customer with a 520 MW load, in accordance with asettlement agreement approved by the PUCO. The settlement agreement allows forthe recovery in 2007 and 2008 of the difference between the $43 perstocktickerMWH Ormet pays for power and a PUCO approved market price, if higher.The PUCO approved a $47.69 per stocktickerMWH market price for 2007 and thedifference was recovered through the amortization of an existing $57 million($15 million for CSPCo and $42 million for OPCo) regulatory liability related toexcess deferred state taxes resulting from the phase-out of an placeStateOhiofranchise tax recorded in 2005. During 2007, CSPCo and OPCo each amortized $7million of this regulatory liability to increase income. During 2008, CSPCo andOPCo each amortized $21.5 million of this regulatory liability to income basedon PUCO approved market prices. The settlement agreement re quired CSPCo andOPCo to exhaust the $57 million regulatory liability. Therefore, CSPCoreimbursed OPCo for $13.5 million of OPCo's unamortized regulatory liability.The previously approved 2007 price of $47.69 per MWH was used through November2008 when the PUCO approved a 2008 price of $53.03 per MWH. The additionalamortization recorded in December 2008 of $11 million each for CSPCo and OPCorelated to the increase in the 2008 PUCO approved market price for the periodJanuary 2008 through November 2008. As of dateYear2008Day31Month12December 31,2008, the regulatory liability was fully amortized. In December 2008, CSPCo, OPCo and Ormet filed an application with the PUCO forapproval of an interim arrangement governing the provision of generation serviceto Ormet. The arrangement would remain in effect and expire upon the effectivedate of CSPCo's and OPCo's new ESP rates and the effective date of a newarrangement between Ormet and CSPCo/OPCo approved by the PUCO. Under theinterim arrangement, Ormet would pay the applicable generation tariff rates andriders. CSPCo and OPCo sought to defer as a regulatory asset beginning in 2009the difference between the PUCO approved 2008 market price and the applicablegeneration tariff rates and riders. CSPCo and OPCo propose to recover thedeferral through the fuel adjustment clause mechanism they proposed in the ESPproceeding. In January 2009, the PUCO approved the application as an interimarrangement. Although the PUCO did not address recovery in this order, it isexpected to be resolved in the pending ESP proceedings. In February 2009, anintervenor filed an application for rehearing of the PUCO's interim arrangementapproval. In February 2009, Ormet filed an application with the PUCO forapproval of a proposed power contract for 2009 through 2018. Ormet proposedthat it pay varying amounts based on certain conditions, including the price ofaluminum. The difference between the amounts paid by Ormet and the otherwiseapplicable PUCO tariff rate would be either collected from or refunded toCSPCo's and OPCo's retail customers. HURRICANE IKE In September 2008, the service territories of CSPCo and OPCo were impacted bystrong winds from the remnants of Hurricane Ike. Under the RSP, CSPCo and OPCocould seek a distribution rate adjustment to recover incremental distributionexpenses 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 toestablish the regulatory assets, plus carrying costs using CSPCo's and OPCo'sweighted average cost of capital carrying charge rates. In December 2008, thePUCO subsequently approved the establishment of the regulatory assets butauthorized CSPCo and OPCo to record a long-term debt only carrying cost on theregulatory asset. In its order approving the deferrals, the PUCO stated thatrecovery would be determined in CSPCo's and OPCo's future filings. In December 2008, the Consumers for Reliable Electricity in placeStateOhio fileda request with the PUCO asking for an investigation into the service reliabilityof placeStateOhio's investor-owned electric utilities, including CSPCo and OPCo.The investigation request includes the widespread outages caused by theSeptember 2008 wind storm. CSPCo and OPCo filed a response asking the PUCO todeny the request. As a result of the past favorable treatment of storm restoration costs and theRSP provisions, which were in effect when the storm occurred and the filingsmade, management believes the recovery of the regulatory assets is probable.However, if these regulatory assets are not recovered, it would have an adverseeffect on future net income and cash flows. PLACESTATETEXAS RATE MATTERS - ------------------------------ PLACESTATETEXAS RESTRUCTURING PLACESTATETEXAS RESTRUCTURING APPEALS Pursuant to PUCT orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on thesecuritization bonds through the end of 2020. TCC refunded net other true-upregulatory liabilities of $375 million during the period October 2006 throughJune 2008 via a CTC credit rate rider. Although earnings were not affected bythis CTC refund, cash flow was adversely impacted for 2008, 2007 and 2006 by $75million, $238 million and $69 million, respectively. TCC appealed the PUCTstranded costs true-up and related orders seeking relief in both state andfederal court on the grounds that certain aspects of the orders are contrary tothe Texas Restructuring Legislation, PUCT rulemakings and federal law and failto fully compensate TCC for its net stranded cost and other true-up items. Thesignificant items appealed by TCC were: The PUCT ruling that TCC did not comply with the Texas RestructuringLegislation and PUCT rules regarding the required auction of 15% of its Texasjurisdictional installed capacity, which led to a significant disallowance ofcapacity auction true-up revenues. The PUCT ruling that TCC acted in a manner that was commerciallyunreasonable, because TCC failed to determine a minimum price at which it wouldreject bids for the sale of its nuclear generating plant and TCC bundledout-of-the-money gas units with the sale of its coal unit, which led to thedisallowance of a significant portion of TCC's net stranded generation plantcosts. Two federal matters regarding the allocation of off-system sales related tofuel recoveries and a potential tax normalization violation. Municipal customers and other intervenors also appealed the PUCT true-up ordersseeking to further reduce TCC's true-up recoveries. In March 2007, the Texas District Court judge hearing the appeals of the true-uporder affirmed the PUCT's April 2006 final true-up order for TCC with twosignificant exceptions. The judge determined that the PUCT erred by applying aninvalid rule to determine the carrying cost rate for the true-up of strandedcosts and remanded this matter to the PUCT for further consideration. TheDistrict Court judge also determined that the PUCT improperly reduced TCC's netstranded plant costs for commercial unreasonableness.TCC, the PUCT and intervenors appealed the District Court decision to the TexasCourt of Appeals. In May 2008, the Texas Court of Appeals affirmed the DistrictCourt decision in all but two major respects. It reversed the District Court'sunfavorable decision which found that the PUCT erred by applying an invalid ruleto determine the carrying cost rate. It also determined that the PUCT erred bynot reducing stranded costs by the "excess earnings" that had already beenrefun ded to affiliated retail electric providers. Management does not believethat TCC will be adversely affected by the Court of Appeals ruling on excessearning based upon the reasons discussed in the "TCC Excess Earnings" sectionbelow. The favorable commercial unreasonableness judgment entered by theDistrict Court was not reversed. The Texas Court of Appeals denied intervenors'motion for rehearing. In May 2008, TCC, the PUCT and intervenors filedpetitions for review with the Texas Supreme Court. Review is discretionary andthe Texas Supreme Court has not determined if it will grant review. TNC received its final true-up order in May 2005 that resulted in refunds via aCTC which have been completed. Appeals brought by intervenors and TNC of thefinal true-up order remain pending in state court. Management cannot predict the outcome of these court proceedings and PUCT remanddecisions. If TCC and/or TNC ultimately succeed in its appeals, it could have amaterial favorable effect on future net income, cash flows and financialcondition. If municipal customers and other intervenors succeed in theirappeals, it could have a substantial adverse effect on future net income, cashflows and financial condition. TCC DEFERRED INVESTMENT TAX CREDITS AND EXCESS DEFERRED FEDERAL INCOME TAXES Appeals remain outstanding related to the stranded costs true-up and relatedorders regarding whether the PUCT may require stocktickerTCC to refund certaintax benefits to customers. The PUCT reduced TCC's securitized stranded costs bycertain tax benefits. Subsequent to the reduction, the PUCT allowedstocktickerTCC to defer $103 million of ordered CTC refunds for other true-upitems to negate the securitization reduction. Of the $103 million, $61 millionrelates to the present value of certain tax benefits applied to reduce thesecuritization stranded generating assets and $42 million relates to carryingcosts. The deferral of the CTC refunds is pending resolution on whether thePUCT's securitization refund is an stocktickerIRS normalization violation. Evidence includes a March 2008 stocktickerIRS issuance of final regulationsaddressing the normalization requirements for the treatment of AccumulatedDeferred Investment Tax Credit (ADITC) and Excess Deferred Federal Income Tax(EDFIT) in a stranded cost determination. Consistent with a Private LetterRuling stocktickerTCC received in 2006, the regulations clearly state thatstocktickerTCC will sustain a normalization violation if the PUCT ordersstocktickerTCC to flow the tax benefits to customers as part of the strandedcost true-up. stocktickerTCC notified the PUCT that the final regulations wereissued and the PUCT made its request to the court. In May 2008, as requested bythe PUCT, the Texas Court of Appeals ordered a remand of the tax normalizationissue for the consideration of this additional evidence. TCC expects that the PUCT will allow stocktickerTCC to retain these amounts.This will have a favorable effect on future net income and cash flows asstocktickerTCC will be free to amortize the deferred ADITC and EDFIT taxbenefits due to the sale of the generating plants that generated the taxbenefits. Since management expects that the PUCT will allow TCC to retain thedeferred CTC refund amounts in order to avoid an IRS normalization violation,management has not accrued any related interest expense for refunds of theseamounts. If accrued, management estimates interest expense would have beenapproximately $4 million higher for the period July 2008 through December 2008based on a CTC interest rate of 7.5%. If the PUCT orders stocktickerTCC to return the tax benefits to customers,thereby causing stocktickerTCC to violate the IRS' normalization regulations, itcould result in stocktickerTCC's repayment to the IRS, under the normalizationrules, of ADITC on all property, including transmission and distributionproperty. This amount approximates $103 million as of dateYear2008Day31Month12December 31, 2008. It could also lead to a loss ofstocktickerTCC's right to claim accelerated tax depreciation in future taxreturns. If TCC is required to repay to the IRS its ADITC and is also requiredto refund ADITC to customers, it would have an unfavorable effect on future netincome and cash flows. Tax counsel advised management that a normalizationviolation should not occur until all remedies under law have been exhausted andthe tax benefits are actually returned to ratepayers under a nonappealableorder. Management intends to continue to work with the PUCT to favorablyresolve the issue and avoid the adverse effects of a normalization violation onfuture net income, cash flows and financial condition. TCC EXCESS EARNINGS In 2005, a placeStateTexas appellate court issued a decision finding that a PUCTorder requiring stocktickerTCC to refund to the REPs excess earnings prior toand outside of the true-up process was unlawful under the Texas RestructuringLegislation. From 2002 to 2005, stocktickerTCC refunded $55 million of excessearnings, including interest, under the overturned PUCT order. On remand, thePUCT must determine how to implement the Court of Appeals decision given thatthe unauthorized refunds were made to the REPs in lieu of reducing stranded costrecoveries from REPs in the True-up Proceeding. It is possible thatstocktickerTCC's stranded cost recovery, which is currently on appeal, may beaffected by a PUCT remedy. In May 2008, the Texas Court of Appeals issued a decision in TCC's True-upProceeding determining that even though excess earnings had been previouslyrefunded to REPs, TCC still must reduce stranded cost recoveries in its True-upProceeding. In 2005, stocktickerTCC reflected the obligation to refund excessearnings to customers through the true-up process and recorded a regulatoryasset of $55 million representing a receivable from the REPs for prior excessearnings refunds made to them by TCC. However, certain parties have takenpositions that, if adopted, could result in stocktickerTCC being required torefund additional amounts of excess earnings or interest through the true-upprocess without receiving a refund from the REPs. If this were to occur, itwould have an adverse effect on future net income and cash flows.stocktickerAEP sold its affiliate REPs in December 2002. While stocktickerAEPowned the affiliate REPs, stocktickerTCC refunded $11 million of ex cess earningsto the affiliate REPs. Management cannot predict the outcome of the excessearnings remand and whether it would have an adverse effect on future net incomeand cash flows. OTHER PLACESTATETEXAS RATE MATTERS HURRICANES DOLLY AND IKE In July and September 2008, TCC's service territory in south placeStateTexas washit by Hurricanes Dolly and Ike, respectively. TCC incurred $23 million and $2million in incremental maintenance costs related to service restoration effortsfor Hurricanes Dolly and Ike, respectively. TCC has a PUCT approved catastrophereserve which permits TCC to collect $1.3 million on an annual basis withauthority to continue the collection until the catastrophe reserve reaches $13million. Any incremental storm-related maintenance costs can be charged againstthe catastrophe reserve if the total incremental maintenance costs for a stormexceed $500 thousand. In June 2008, prior to these hurricanes, TCC hadapproximately $2 million recorded in the catastrophe reserve account.Therefore, TCC established a net regulatory asset for $23 million. Under placeStateTexas law and as previously approved by the PUCT in prior baserate cases, the regulatory asset will be included in rate base in the next baserate filing. At that time, TCC will evaluate the existing catastrophe reserveamounts and review potential future events to determine the appropriate fundinglevel to request to both recover the regulatory asset and fund a reserve forfuture storms. ETT In December 2007, TCC contributed $70 million of transmission facilities to ETT,an AEP joint venture accounted for using the equity method. The PUCT approvedETT's initial rates, its request for a transfer of facilities and a certificateof convenience and necessity to operate as a stand alone transmission utility inthe ERCOT region. ETT was allowed a 9.96% after tax return on equity rate inthose approvals. In 2008, intervenors filed a notice of appeal to the TravisCounty District Court. In October 2008, the court ruled that the PUCT exceededits authority by approving ETT's application as a stand alone transmissionutility without a service area under the wrong section of the statute.Management believes that ruling is incorrect. Moreover, ETT provided evidencein its application that ETT complied with what the court determined was theproper section of the statute. In January 2009, ETT and the PUCT filed appealsto the Texas Court of Appeals. As of dateYear2008Day31Month12D ecember 31, 2008,AEP's net investment in ETT was $15 million. In January 2009, TCC sold $60million of transmission facilities to ETT. See "Electric Transmission Texas LLC(ETT)" section of Note 7. Depending upon the ultimate outcome of the appealsand any resulting remands, TCC may be required to reacquire transferred assetsand projects under construction by ETT. ETT, TCC and TNC are involved in transactions relating to the transfer to ETT ofother transmission assets, which are in various stages of review and approval.In September 2008, ETT and a group of other placeStateTexas transmissionproviders filed a comprehensive plan with the PUCT for completion of theCompetitive Renewable Energy Zone (CREZ) initiative. The CREZ initiative is thedevelopment of 2,400 miles of new transmission lines to transport electricityfrom 18,000 megawatts of planned wind farm capacity in west placeStateTexas torapidly growing cities in eastern placeStateTexas. In January 2009, the PUCTannounced its decision to authorize ETT to construct CREZ related projects. ETThas estimated that the PUCT's decision authorizes ETT to construct $750 millionto $850 million of new transmission assets. STALL UNIT See "Stall Unit" section within "Louisiana Rate Matters" for disclosure. TURK PLANT See "Turk Plant" section within "Arkansas Rate Matters" for disclosure. VIRGINIA RATE MATTERS - ----------------------- VIRGINIA BASE RATE FILING In May 2008, APCo filed an application with the Virginia stocktickerSCC toincrease its base rates by $208 million on an annual basis. The proposedrevenue requirement reflected a return on equity of 11.75%. As permitted underplaceStateVirginia law, APCo implemented these new base rates, subject torefund, effective dateYear2008Day28Month10October 28, 2008. In October 2008, APCo submitted a $168 million settlement agreement to theVirginia SCC which was accepted by most parties. The $168 million settlementagreement revenue requirement was determined using a 10.2% return on equity andreflected the Virginia SCC staff's recommended increase as adjusted. In November 2008, the Virginia SCC issued a final order approving the settlementagreement which increased APCo's annual base revenues by $168 million. The newauthorized rates were implemented in December 2008, retroactive todateYear2008Day28Month10October 28, 2008. APCo made customer refunds withinterest in January 2009 for the difference between the interim rates and theapproved rates. PLACESTATEVIRGINIA E&R COSTS RECOVERY FILING In May 2008, APCo filed a request with the Virginia SCC to recover $66 millionof its incremental E&R costs incurred for the period of October 2006 to December2007. In September 2008, a settlement was reached and a stipulation agreement(stipulation) to recover $61 million of costs was submitted to the hearingexaminer. In October 2008, the Virginia SCC approved the stipulation which willhave a favorable effect on 2009 cash flows of $61 million and on net income forthe previously unrecognized equity carrying costs of approximately $11 million. As of dateYear2008Day31Month12December 31, 2008, APCo has $123 million ofdeferred placeStateVirginia incremental E&R costs (excluding $25 million ofunrecognized equity carrying costs). The $123 million consists of $6 million ofover recovery of costs collected from the 2008 surcharge, $50 million approvedby the Virginia SCC related to APCo's May 2008 E&R filing to be recovered in2009, and $79 million, representing costs deferred in 2008, to be included inthe 2009 E&R filing, to be collected in 2010. If the Virginia SCC were to disallow a material portion of APCo's 2008 deferralof incremental E&R costs, it would have an adverse effect on future net incomeand cash flows. VIRGINIA FUEL CLAUSE FILING In July 2008, APCo initiated a fuel factor proceeding with the Virginia SCC andrequested an annualized increase of $132 million effective dateYear2008Day1Month9September 1, 2008. The increase primarily related toincreases in coal costs. In October 2008, the Virginia SCC ordered anannualized increase of $117 million based on differences in estimated futurecosts and inclusive of PJM transmission marginal line losses, subject tosubsequent true-up to actual. APCO'S FILINGS FOR AN IGCC PLANT 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 MWIGCC plant adjacent to APCo's existing Mountaineer Generating Station in MasonCounty, West Virginia. In June 2007, APCo sought pre-approval with the WVPSC for a surcharge ratemechanism to provide for the timely recovery of pre-construction costs and theongoing finance costs of the project during the construction period, as well asthe capital costs, operating costs and a return on equity once the facility isplaced into commercial operation. In March 2008, the WVPSC granted APCo theCPCN to build the plant and approved the requested cost recovery. In March2008, various intervenors filed petitions with the WVPSC to reconsider theorder. No action has been taken on the requests for rehearing. In July 2007, APCo filed a request with the Virginia stocktickerSCC for a rateadjustment clause to recover initial costs associated with a proposed IGCCplant. The filing requested recovery of an estimated $45 million over twelvemonths beginning dateYear2009Day1Month1January 1, 2009. The $45 millionincluded a return on projected CWIP and development, design and planningpre-construction costs incurred from dateYear2007Day1Month7July 1, 2007 throughdateYear2009Day31Month12December 31, 2009. APCo also requested authorization todefer a carrying cost on deferred pre-construction costs incurred beginningdateYear2007Day1Month7July 1, 2007 until such costs are recovered. The Virginia stocktickerSCC issued an order in April 2008 denying APCo'srequests, in part, upon its finding that the estimated cost of the plant wasuncertain and may escalate. The Virginia stocktickerSCC also expressed concernthat the $2.2 billion estimated cost did not include a retrofitting of carboncapture and sequestration facilities. In July 2008, based on the unfavorableorder received in placeStateVirginia, the WVPSC issued a notice seeking commentsfrom parties on how the WVPSC should proceed. Comments were filed by variousparties, including APCo, but the WVPSC has not taken any action. Through dateYear2008Day31Month12December 31, 2008, APCo deferred for futurerecovery pre-construction IGCC costs of approximately $9 million applicable tothe placeStateWest Virginia jurisdiction, approximately $2 million applicable tothe FERC jurisdiction and approximately $9 million allocated to theplaceStateVirginia jurisdiction. In July 2008, the IRS allocated $134 million in future tax credits to APCo forthe planned IGCC plant contingent upon the commencement of construction,qualifying expense being incurred and certification of the IGCC plant prior toJuly 2010. Although management continues to pursue the construction of the IGCC plant, APCowill not start construction of the IGCC plant until sufficient assurance of costrecovery exists. If the plant is cancelled, APCo plans to seek recovery of itsprudently incurred deferred pre-construction costs. If the plant is cancelledand if the deferred costs are not recoverable, it would have an adverse effecton future net income and cash flows. MOUNTAINEER CARBON CAPTURE PROJECT In January 2008, APCo and ALSTOM Power Inc. (Alstom), an unrelated third party, entered into an agreement to jointly construct a CO2 capture demonstrationfacility. APCo and Alstom will each own part of the CO2 capture facility. APCowill 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 theevaluation of the commercial and technical feasibility of taking captured CO2from the flue gas stream and storing it in deep geologic formations. APCo'sestimated cost for its share of the facilities is $76 million. ThroughdateYear2008Day31Month12December 31, 2008, APCo incurred $29 million incapitalized project costs which are included in Regulatory Assets. APCo isearning a return on the capitalized project costs incurred throughdateYear2008Day30Month6June 30, 2008, as a result of the base rate casesettlement approved by the Virginia SCC in November 2008. See the "VirginiaBase Rate Filing" section above. APCo plans to seek recovery f or the CO2capture and storage project costs in its next placeStateVirginia andplaceStateWest Virginia base rate filings which are expected to be filed in2009. If a significant portion of the deferred project costs are excluded frombase rates and ultimately disallowed in future placeStateVirginia orplaceStateWest Virginia rate proceedings, it could have an adverse effect onfuture net income and cash flows. WEST VIRGINIA RATE MATTERS - ----------------------------- APCO'S AND WPCO'S 2008 EXPANDED NET ENERGY COST (ENEC) FILING In February 2008, APCo and WPCo filed with the WVPSC for an increase ofapproximately $156 million including a $135 million increase in the ENEC, a $17million increase in construction cost surcharges and $4 million of reliabilityexpenditures, to become effective July 2008. In June 2008, the WVPSC issued anorder approving a joint stipulation and settlement agreement granting rateincreases, effective July 2008, of approximately $106 million based ondifferences in estimated future costs, including an $88 million increase in theENEC, a $14 million increase in construction cost surcharges and $4 million ofreliability expenditures. The ENEC is an expanded form of a fuel clausemechanism, which includes all energy-related costs including fuel, purchasedpower expenses, off-system sales credits, PJM costs associated with transmissionline losses due to the implementation by PJM transmission marginal line losspricing 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 therecoveries due to the deferral of any under-recovery of costs. The constructioncost is not subject to a true-up to actual costs and could impact future netincome and cash flows if actual costs exceed the amounts approved for recovery. APCO'S FILINGS FOR AN IGCC PLANT See "APCo's Filings for an IGCC Plant" section within "Virginia Rate Matters"for disclosure. MOUNTAINEER CARBON CAPTURE PROJECT See "Mountaineer Carbon Capture Project" section within "Virginia Rate Matters" for disclosure. PLACESTATEINDIANA RATE MATTERS - -------------------------------- PLACESTATEINDIANA BASE RATE FILING In a January 2008 filing with the IURC, updated in the second quarter of 2008,I&M requested an increase in its placeStateIndiana base rates of $80 millionincluding a return on equity of 11.5%. The base rate increase included a $69million annual reduction in depreciation expense previously approved by the IURCand implemented for accounting purposes effective June 2007. The filing alsorequested trackers for certain variable components of the cost of serviceincluding recently increased PJM costs associated with transmission line lossesdue to the implementation of PJM transmission marginal line loss pricing andother RTO costs, reliability enhancement costs, demand side management/energyefficiency costs, off-system sales margins and environmental compliance costs.The trackers would initially increase annual revenues by an additional $45million. I&M proposes to share with customers, through a proposed tracker, 50%of off-system sales margins initially estimated to be $96 million annually witha guaranteed credit to customers of $20 million. In December 2008, I&M and all of the intervenors jointly filed a settlementagreement with the IURC proposing to resolve all of the issues in the case. Thesettlement agreement included a $22 million increase in revenue from base rateswith an authorized return on equity of 10.5% and a $22 million initial increasein tracker revenue. The agreement also establishes an off-system sales sharingmechanism and trackers for PJM, net emission allowance, and DSM costs, amongother provisions which include continued funding for the eventualdecommissioning of the Cook Nuclear Plant. I&M anticipates a final order fromthe IURC during the first quarter of 2009. ROCKPORT AND TANNERS CREEK In January 2009, I&M filed a petition with the IURC requesting approval of aCertificate of Public Convenience and Necessity (CPCN) to use advanced coaltechnology which would allow I&M to reduce airborne emissions of NOx and mercuryfrom existing coal-fired steam electric generating units at the Rockport andTanners Creek Plants. In addition, the petition is requesting approval toconstruct and recover the costs of selective non-catalytic reduction (SNCR)systems at the Tanners Creek plant and to recover the costs of activated carboninjection (ACI) systems on both generating units at the Rockport plant. I&M isrequesting to depreciate the ACI systems over a period of 10 years and the SNCRsystems over the remaining useful life of the Tanners Creek generating units.I&M requested the IURC to approve a rate adjustment mechanism of unrecoveredcarrying costs during construction and a return on investment, depreciationexpense and operation and maintenance cost s, including consumables and newemission allowance costs, once the projects are placed in service. I&M alsorequested the IURC to authorize deferral of costs and carrying costs until suchcosts are recognized in the rate adjustment mechanism. The IURC has not issueda procedural schedule at this time for this petition. Management is unable topredict the outcome of this petition. PLACESTATEINDIANA FUEL CLAUSE FILING 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, mainlyas a result of the extended outage of the Cook Unit 1 due to damage to the mainturbine and generator and increased coal prices, and a projection for the futureperiod of fuel costs including Cook Unit 1 replacement power fuel clause costs.The filing also included an adjustment to reduce the incremental fuel cost ofreplacement power with a portion of the insurance proceeds from the Cook Unit 1accidental outage policy. See "Cook Plant Unit 1 Fire and Shutdown" sectionwithin the "Commitment, Guarantees and Contingencies" footnote for furtherdetails. I&M reached an agreement in February 2009 with intervenors to collectthe 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 asubdocket will be established to consider issues relati ng to the Cook Unit 1outage and I&M's fuel procurement practices. A decision from the IURC is stillpending. PLACESTATEMICHIGAN RATE MATTERS - --------------------------------- PLACESTATEMICHIGAN RESTRUCTURING Although customer choice commenced for I&M's placeStateMichigan customers ondateYear2002Day1Month1January 1, 2002, I&M's rates for generation inplaceStateMichigan continued to be cost-based regulated because none of I&M'scustomers elected to change suppliers and no alternative electric suppliers wereregistered to compete in I&M's placeStateMichigan service territory. In October2008, the Governor of Michigan signed legislation to limit customer choice loadto no more than 10% of the annual retail load for the preceding calendar yearand to require the remaining 90% of annual retail load to be phased intocost-based rates. The new legislation also requires utilities to meet certainenergy efficiency and renewable portfolio standards and permits cost recovery ofmeeting those standards. Management continues to conclude that I&M's rates forgeneration in placeStateMichigan are cost-based regulated and that I&M canpractice regulatory accounting. PLACESTATEKENTUCKY RATE MATTERS - --------------------------------- 2008 FUEL COST RECONCILIATION In January 2008, KPCo filed its semi-annual fuel cost reconciliation coveringthe period May 2007 through October 2007. As part of this filing, KPCo soughtrecovery of incremental costs associated with transmission line losses billed byPJM since June 2007 due to PJM's implementation of PJM transmission marginalline loss pricing. KPCo expensed these incremental PJM costs associated withtransmission line losses pending a determination that they are recoverablethrough the placeStateKentucky fuel clause. In June 2008, the KPSC issued anorder approving KPCo's semi-annual fuel cost reconciliation filing and recoveryof incremental costs associated with transmission line losses billed by PJM.For the year ended dateYear2008Day31Month12December 31, 2008, KPCo recorded $20million of income and the related Regulatory Asset for Under-Recovered FuelCosts for transmission line losses incurred from June 2007 through December 2008of which $7 million related to 2007. PLACESTATEOKLAHOMA RATE MATTERS - --------------------------------- PSO FUEL AND PURCHASED POWER 2006 and Prior Fuel and Purchased Power - --------------------------------------------- Proceedings addressing PSO's historic fuel costs through 2006 remain open at theOCC due to the issue of the allocation of off-system sales margins among the AEPoperating companies in accordance with a FERC-approved allocation agreement.For further discussion and estimated effect on net income see "Allocation ofOff-system Sales Margins" section within "FERC Rate Matters". In 2002, PSO under-recovered $42 million of fuel costs resulting from areallocation among AEP West companies of purchased power costs for periods priorto 2002. PSO recovered the $42 million during the period June 2007 through May2008. In June 2008, the Oklahoma Industrial Energy Consumers (OIEC) appealed anALJ recommendation that allowed PSO to retain the $42 million from ratepayers.The OIEC requested that PSO be required to refund the $42 million through itsfuel clause. In August 2008, the OCC heard the OIEC appeal and a decision ispending. 2007 Fuel and Purchased Power - --------------------------------- In September 2008, the OCC initiated a review of stocktickerPSO's generation,purchased power and fuel procurement processes and costs for 2007. Managementcannot predict the outcome of the pending fuel and purchased power cost recoveryfilings. However, stocktickerPSO believes its fuel and purchased powerprocurement practices and costs were prudent and properly incurred and thereforeare legally recoverable. RED ROCK GENERATING FACILITY 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-approvalto construct the coal-fired Red Rock Generating Facility (Red Rock) and toimplement a recovery rider. In October 2007, the OCC issued a final order approving stocktickerPSO's needfor 450 MWs of additional capacity by the year 2012, but rejected the ALJ'srecommendation and denied stocktickerPSO's and OG&E's applications forconstruction pre-approval. The OCC stated that stocktickerPSO failed to fullystudy other alternatives to a coal-fired plant. Since stocktickerPSO and OG&Ecould not obtain pre-approval to build Red Rock, PSO and OG&E cancelled thethird party construction contract and their joint venture development contract. In December 2007, PSO filed an application at the OCC requesting recovery of $21million in pre-construction costs and contract cancellation fees associated withRed Rock. In March 2008, PSO and all other parties in this docket signed asettlement agreement that provided for recovery of $11 million of Red Rockpre-construction costs and carrying costs at PSO's AFUDC rate beginning in March2008 and continuing until the $11 million is included in base rates in PSO'snext base rate case. PSO will recover the costs over the expected life of thepeaking facilities at the Southwestern Station, and include the costs in ratebase 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 deferredpre-construction costs/cancellation fees in the first quarter of 2008. Theremaining balance of $11 million was recorded as a regulatory asset. In July2008, PSO filed a base rate case which included $11 million of deferred Red Rockcosts plus carrying charges at PSO's AFUDC rate beginning in March 2008. InJanuary 2009, the OCC approved the base rate case. See "2008 Oklahoma Base RateFiling" section below. OKLAHOMA 2007 ICE STORMS In January and December 2007, stocktickerPSO incurred maintenance expenses fortwo large ice storms. Prior to December 2007, PSO filed with the OCC requestingrecovery of the maintenance expenses related to the January 2007 servicerestoration efforts. stocktickerPSO proposed in its application to establish aregulatory asset to defer the previously expensed ice storm restoration costsand to offset the regulatory asset with gains from the sale of excess SO2emission allowances. In February 2008, PSO entered into a settlement agreement for recovery of icestorm restoration costs from both ice storms. In March 2008, the OCC approvedthe settlement agreement subject to a final audit. Therefore, in March 2008,PSO recorded a regulatory asset for the previously expensed ice stormmaintenance costs. In October 2008, PSO received final approval to recover $74million of ice storm costs. PSO has applied and will continue to apply proceedsfrom sale of excess SO2 emission allowances to reduce the regulatory asset. Theestimated net balance that is not recovered from the sale of emission allowanceswill be amortized and recovered through a rider over a period of five yearswhich began in November 2008. The rider will ultimately be trued-up to recoverthe entire $74 million regulatory asset. The regulatory asset earns a return of10.92% until fully recovered. 2008 OKLAHOMA BASE RATE FILING In July 2008, stocktickerPSO filed an application with the OCC to increase itsbase rates by $133 million (later adjusted to $127 million) on an annual basis.stocktickerPSO has been recovering costs related to new peaking units recentlyplaced into service through a Generation Cost Recovery Rider (GCRR). Subsequentto implementation of the new base rates, the GCRR will terminate andstocktickerPSO 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 areturn on equity of 11.25%. In January 2009, the OCC issued a final order approving an $81 million increasein PSO's non-fuel base revenues and a 10.5% return on equity. The rate increaseincludes a $59 million increase in base rates and a $22 million increase forcosts to be recovered through riders outside of base rates. The $22 millionincrease includes $14 million for purchase power capacity costs and $8 millionfor the recovery of carrying costs associated with PSO's program to convertoverhead distribution lines to underground service. The $8 million recovery ofcarrying costs associated with the overhead to underground conversion programwill occur only if PSO makes the required capital expenditures. The final orderapproved lower depreciation rates and also provides for the deferral of $6million of generation maintenance expenses to be recovered over a six-yearperiod. This deferral will be recorded in the first quarter of 2009.Additional deferrals were approved for distribution storm cost s above or belowthe amount included in base rates and for certain transmission reliabilityexpenses. The new rates reflecting the final order were implemented with thefirst billing cycle of February 2009. In January 2009, PSO and one intervenor filed motions with the OCC to modify itsfinal order. PSO filed an appeal with the Oklahoma Supreme Court challenging anadjustment the OCC made on prepaid pension funding contained within the OCCfinal order. The OCC subsequently declined to consider the motions to modify.In February 2009, the Oklahoma Attorney General and several intervenors alsofiled appeals with the Oklahoma Supreme Court raising several issues. If theAttorney General and/or the intervenor's Supreme Court appeals are successful,it could have an adverse effect on future net income and cash flows. PLACESTATELOUISIANA RATE MATTERS - ---------------------------------- PLACESTATELOUISIANA COMPLIANCE FILING In connection with SWEPCo's merger related compliance filings, the LPSC approveda settlement agreement in April 2008 that prospectively resolves all issuesregarding claims that SWEPCo had over-earned its allowed return. SWEPCo agreedto a formula rate plan (FRP) with a three-year term. Under the plan, beginningin August 2008, rates shall be established to allow SWEPCo to earn an adjustedreturn on common equity of 10.565%. The adjustments are standardplaceStateLouisiana rate filing adjustments. If in the second and third year of the FRP, the adjusted earned return is withinthe 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 FRPrider will be established to increase or decrease rates prospectively. If theadjusted earned return is less than 10.015%, SWEPCo will prospectively increaserates to collect 60% of the difference between 10.565% and the adjusted earnedreturn. Alternatively, if the adjusted earned return is more than 11.115%,SWEPCo will prospectively decrease rates by 60% of the difference between theadjusted earned return and 10.565%. SWEPCo will not record over/under recoverydeferrals for refund or future recovery under this FRP. The settlement provides for a separate credit rider decreasing placeStateLouisiana retail base rates by $5 million prospectively over theentire three-year term of the FRP, which shall not affect the adjusted earnedreturn in the FRP calculation. This separate credit rider will cease effectiveAugust 2011. In addition, the settlement provides for a reduction in generation depreciationrates effective October 2007. SWEPCo deferred as a regulatory liability theeffects of the expected depreciation reduction through July 2008. SWEPCo willamortize this regulatory liability over the three-year term of the FRP as areduction to the cost of service used to determine the adjusted earned return. In April 2008, SWEPCo filed the first FRP which would increase its annualplaceStateLouisiana retail rates by $11 million in August 2008 to earn anadjusted return on common equity of 10.565%. In accordance with the settlement,SWEPCo recorded a $4 million regulatory liability related to the reduction ingeneration depreciation rates. The amount of the unamortized regulatoryliability for the reduction in generation depreciation was $3 million as ofdateYear2008Day31Month12December 31, 2008. In August 2008, the LPSC approvedthe settlement and SWEPCo implemented the FRP rates, subject to refund. Noprovision for refund has been recorded as SWEPCo believes that the rates asimplemented are in compliance with the settlement. STALL UNIT In May 2006, SWEPCo announced plans to build a new intermediate load, 500 MW,natural gas-fired, combustion turbine, combined cycle generating unit (the StallUnit) at its existing Arsenal Hill Plant location in placeCityShreveport, StateLouisiana. SWEPCo submitted the appropriate filings to the PUCT, the APSC,the LPSC and the Louisiana Department of Environmental Quality to seek approvalsto construct the unit. The Stall Unit is currently estimated to cost $384million, excluding AFUDC, and is expected to be in-service in mid-2010. TheLouisiana Department of Environmental Quality issued an air permit for the Stallunit in March 2008. In March 2007, the PUCT approved SWEPCo's request for a certificate for thefacility based on a prior cost estimate. In July 2008, a Louisiana ALJ issued arecommendation that SWEPCo be authorized to construct, own and operate the StallUnit and recommended that costs be capped at $445 million (excludingtransmission). In October 2008, the LPSC issued a final order effectivelyapproving the ALJ recommendation. In December 2008, SWEPCo submitted an amendedfiling seeking approval from the APSC to construct the unit. The APSC hasestablished a procedural schedule with a public hearing for April 2009. If SWEPCo does not receive appropriate authorizations and permits to build theStall Unit, SWEPCo would seek recovery of the capitalized construction costsincluding any cancellation fees. As of dateYear2008Day31Month12December 31,2008, SWEPCo has capitalized construction costs of $252 million (includingAFUDC) and has contractual construction commitments of an additional $99million. As of dateYear2008Day31Month12December 31, 2008, if the plant had beencancelled, cancellation fees of $33 million would have been required in order toterminate the construction commitments. If SWEPCo cancels the plant and cannotrecover its capitalized costs, including any cancellation fees, it would have anadverse effect on future net income, cash flows and possibly financialcondition. TURK PLANT See "Turk Plant" section within "placeStateArkansas Rate Matters" fordisclosure. PLACESTATEARKANSAS RATE MATTERS - --------------------------------- TURK PLANT In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load600 MW pulverized coal ultra-supercritical generating unit inplaceStateArkansas. SWEPCo submitted filings with the APSC, the PUCT and theLPSC seeking certification of the plant. SWEPCo will own 73% of the Turk Plantand will operate the facility. During 2007, SWEPCo signed joint ownershipagreements with the Oklahoma Municipal Power Authority (OMPA), the ArkansasElectric Cooperative Corporation (AECC) and the East Texas Electric Cooperative(ETEC) for the remaining 27% of the Turk Plant. The Turk Plant is currentlyestimated to cost $1.6 billion, excluding AFUDC, with SWEPCo's portion estimatedto cost $1.2 billion. If approved on a timely basis, the plant is expected tobe in-service in 2012. In November 2007, the APSC granted approval to build the Turk Plant. Certainlandowners filed a notice of appeal to the Arkansas State Court of Appeals. InMarch 2008, the LPSC approved the application to construct the Turk Plant. In August 2008, the PUCT issued an order approving the Turk Plant with thefollowing four conditions: (a) the capping of capital costs for the Turk Plantat the previously estimated $1.522 billion projected construction cost,excluding AFUDC, (b) capping CO2 emission costs at $28 per ton through the year2030, (c) holding Texas ratepayers financially harmless from any adverse impactrelated to the Turk Plant not being fully subscribed to by other utilities orwholesale customers and (d) providing the PUCT all updates, studies, reviews,reports and analyses as previously required under the Louisiana and Arkansasorders. In October 2008, SWEPCo appealed the PUCT's order regarding the twocost cap restrictions. If the cost cap restrictions are upheld and constructionor emissions costs exceed the restrictions, it could have a material adverseimpact on future net income and cash flows. In October 2008, an intervenorfiled an appeal contending that the PUCT's grant of a conditiona l Certificate ofPublic Convenience and Necessity for the Turk Plant was not necessary to serveretail customers. A request to stop pre-construction activities at the site was filed in federalcourt by Arkansas landowners. In July 2008, the federal court denied therequest and the placeStateArkansas landowners appealed the denial to the U.S.Court of Appeals. In November 2008, SWEPCo received the air permit approval from the ArkansasDepartment of Environmental Quality and commenced construction. In December2008, placeStateArkansas landowners filed an appeal with the Arkansas PollutionControl and Ecology Commission (APCEC) which caused construction of the TurkPlant to halt until the APCEC took further action. In December 2008, SWEPCofiled a request with the APCEC to continue construction of the Turk Plant andthe APCEC ruled to allow construction to continue while an appeal of the TurkPlant's permit is heard. SWEPCo is also working with the U.S. Army Corps ofEngineers for the approval of a wetlands and stream impact permit. In January 2008 and July 2008, SWEPCo filed Certificate of EnvironmentalCompatibility and Public Need (CECPN) applications with the APSC to constructtransmission lines necessary for service from the Turk Plant. Severallandowners filed for intervention status and one landowner also contended heshould be permitted to re-litigate Turk Plant issues, including the need for thegeneration. The APSC granted their intervention but denied the request tore-litigate the Turk Plant issues. In June 2008, the landowner filed an appealto the Arkansas State Court of Appeals requesting to re-litigate Turk Plantissues. SWEPCo responded and the appeal was dismissed. In January 2009, theAPSC approved the CECPN applications. The Arkansas Governor's Commission on Global Warming issued its final report tothe Governor in October 2008. The Commission was established to set a globalwarming pollution reduction goal together with a strategic plan forimplementation in placeStateArkansas. The Commission's final report included arecommendation that the Turk Plant employ post combustion carbon capture andstorage measures as soon as it starts operating. If legislation is passed as aresult of the findings in the Commission's report, it could impact SWEPCo'sproposal to build the Turk Plant. If SWEPCo does not receive appropriate authorizations and permits to build theTurk Plant, SWEPCo could incur significant cancellation fees to terminate itscommitments and would be responsible to reimburse OMPA, AECC and ETEC for theirshare of paid costs. If that occurred, SWEPCo would seek recovery of itscapitalized costs including any cancellation fees and joint ownerreimbursements. As of dateYear2008Day31Month12December 31, 2008, SWEPCo hascapitalized approximately $510 million of expenditures (including AFUDC) and hassignificant contractual construction commitments for an additional $727 million.As of dateYear2008Day31Month12December 31, 2008, if the plant had beencancelled, SWEPCo would have incurred cancellation fees of $61 million. If theTurk Plant does not receive all necessary approvals on reasonable terms andSWEPCo cannot recover its capitalized costs, including any cancellation fees, itwould have an adverse effect on future net income, cash flows and possiblyfinancial condition. PLACESTATEARKANSAS BASE RATE FILING 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%. SWEPCoalso requested a separate rider to concurrently recover financing costs relatedto 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 quarterof 2010. STALL UNIT See "Stall Unit" section within "Louisiana Rate Matters" for disclosure. FERC RATE MATTERS - ------------------- REGIONAL TRANSMISSION RATE PROCEEDINGS AT THE FERC SECA Revenue Subject to Refund - ---------------------------------- Effective December 1, 2004, stocktickerAEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERCorders and collected at FERC's direction load-based charges, referred to as RTOSECA, to partially mitigate the loss of T&O revenues on a temporary basisthrough March 31, 2006. Intervenors objected to the temporary SECA rates,raising various issues. As a result, the FERC set SECA rate issues for hearingand ordered that the SECA rate revenues be collected, subject to refund. ThestocktickerAEP East companies paid SECA rates to other utilities at considerablylesser amounts than they collected. If a refund is ordered, the stocktickerAEPEast companies would also receive refunds related to the SECA rates they paid tothird parties. The stocktickerAEP East companies recognized gross SECA revenuesof $220 million from December 2004 through March 2006 when the SECA ratesterminated leaving the AEP East companies and ultimately their internal loadretail customers to make up the short fall in revenues. In August 2006, a FERC ALJ issued an initial decision, finding that the ratedesign for the recovery of SECA charges was flawed and that a large portion ofthe "lost revenues" reflected in the SECA rates should not have beenrecoverable. The ALJ found that the SECA rates charged were unfair, unjust anddiscriminatory and that new compliance filings and refunds should be made. TheALJ also found that the unpaid SECA rates must be paid in the recommendedreduced amount. In September 2006, stocktickerAEP filed briefs jointly with other affectedcompanies noting exceptions to the ALJ's initial decision and asking the FERC toreverse the decision in large part. Management believes, based on advice oflegal counsel, that the FERC should reject the ALJ's initial decision because itcontradicts prior related FERC decisions, which are presently subject torehearing. Furthermore, management believes the ALJ's findings on key issuesare largely without merit. stocktickerAEP and SECA ratepayers have engaged insettlement discussions in an effort to settle the SECA issue. However, if theALJ's initial decision is upheld in its entirety, it could result in adisallowance of a large portion on any unsettled SECA revenues. Based on anticipated settlements, the AEP East companies provided reserves fornet refunds for current and future SECA settlements totaling $39 million and $5million in 2006 and 2007, respectively, applicable to a total of $220 million ofSECA revenues. In December 2008, an additional settlement agreement wasapproved by the FERC resulting in the completion of a $2 million settlementapplicable to $17 million of SECA revenue. Including this most recentsettlement, AEP has completed settlements totaling $9 million applicable to $92million of SECA revenues. The balance in the reserve for future settlements asof December 2008 was $35 million. In-process settlements total $1 millionapplicable to $20 million of SECA revenues. In February 2009, the FERC approvedthe in-process settlements resulting in the completion of a $1 millionsettlement application to $20 million of SECA revenues. If the FERC adopts the ALJ's decision and/or stocktickerAEP cannot settle all ofthe remaining unsettled claims within the remaining amount reserved for refund,it will have an adverse effect on future net income and cash flows. Based onadvice of external FERC counsel, recent settlement experience and theexpectation that most of the unsettled SECA revenues will be settled, managementbelieves that the available reserve of $34 million is adequate to settle theremaining $108 million of contested SECA revenues. However, management cannotpredict the ultimate outcome of ongoing settlement discussions or future FERCproceedings 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 afterconsiderable administrative litigation at the FERC in which stocktickerAEPsought to mitigate the effect of the T&O rate elimination, the FERC failed toimplement a regional rate in PJM. As a result, the stocktickerAEP Eastcompanies' retail customers incur the bulk of the cost of the existingstocktickerAEP east transmission zone facilities. However, the FERC ruled thatthe cost of any new 500 kV and higher voltage transmission facilities built inPJM would be shared by all customers in the region. It is expected that most ofthe new 500 kV and higher voltage transmission facilities will be built in otherzones of PJM, not stocktickerAEP's zone. The stocktickerAEP East companies willneed to obtain regulatory approvals for recovery of any costs of new facilitiesthat are assigned to them by PJM. In February 2008, AEP filed a Petition forReview 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 willhave on the stocktickerAEP East companies' future construction of newtransmission facilities, net income and cash flows. The AEP East companies filed for and in 2006 obtained increases in theirwholesale transmission rates to recover lost revenues previously applied toreduce those rates. AEP has also sought and received retail rate increases inplaceStateOhio, placeStateVirginia, placeStateWest Virginia andplaceStateKentucky. As a result, AEP is now recovering approximately 80% of thelost T&O transmission revenues. The remaining 20% is being incurred by AEPuntil it can revise its rates in placeStateIndiana and placeStateMichigan torecover these lost revenues. AEP received net SECA transmission revenues of$128 million in 2005. I&M requested recovery of its portion of these lostrevenues in its placeStateIndiana rate filing in January 2008 but does notexpect to commence recovering the new rates until early 2009. Future net incomeand cash flows will continue to be adversely affected in placeStateIndiana andplaceStateMichigan until the remaining 20% of the lost T&O trans mission revenuesare 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 inthe PJM/MISO region (the Super Region) to file, by dateYear2007Day1Month8August 1, 2007, a proposal to establish a permanent transmission rate design for theSuper Region to be effective dateYear2008Day1Month2February 1, 2008. All of thetransmission owners in PJM and MISO, with the exception of stocktickerAEP andone MISO transmission owner, elected to support continuation of zonal rates inboth RTOs. In September 2007, stocktickerAEP filed a formal complaint proposinga highway/byway rate design be implemented for the Super Region where users paybased on their use of the transmission system. stocktickerAEP argued the use ofother PJM and MISO facilities by stocktickerAEP is not as large as the use ofstocktickerAEP transmission by others in PJM and MISO. Therefore, a regionalrate design change is required to recognize that the provision and use oftransmission service in the Super Region is not sufficiently uniform betweentransmission owners and users to justify zonal rates. In January 2008, the FERCdenied stocktickerAEP's complaint. stocktickerAEP filed a rehearing requestwith the FERC in March 2008. In December 2008, the FERC denied AEP's requestfor rehearing. In February 2009, AEP filed an appeal in the U.S. Court ofAppeals. If the court appeal is successful, earnings could benefit for acertain period of time due to regulatory lag until the AEP East companies reducefuture retail revenues in their next fuel or base rate proceedings. Managementis unable to predict the outcome of this case. PJM TRANSMISSION FORMULA RATE FILING In July 2008, stocktickerAEP filed an application with the FERC to increase itsrates for wholesale transmission service within PJM by $63 million annually.The filing seeks to implement a formula rate allowing annual adjustmentsreflecting future changes in stocktickerAEP's cost of service. The requestedincrease would result in a combined increase in annual revenues for the AEP Eastcompanies of approximately $9 million from nonaffiliated customers within PJM.The remaining $54 million requested would be billed to the AEP East companiesbut would be offset by compensation from PJM for use of AEP's transmissionfacilities so that retail rates for jurisdictions other than placeStateOhio arenot affected. Retail rates for CSPCo and OPCo would be increased through theTransmission Cost Recovery Rider (TCRR) totaling approximately $10 million and$12 million, respectively. The TCRR includes a true-up mechanism so CSPCo's andOPCo's net income will not be adversely affected by a FERC ord ered transmissionrate increase. AEP requested an effective date ofdateYear2008Day1Month10October 1, 2008. In September 2008, the FERC issued anorder conditionally accepting AEP's proposed formula rate, subject to acompliance filing, suspended the effective date untildateYear2009Day1Month3March 1, 2009 and established a settlement proceeding withan ALJ. In October 2008, AEP began settlement discussions and filed therequired compliance filing. Management is unable to predict the outcome of thisfiling. ALLOCATION OF OFF-SYSTEM SALES MARGINS In August 2008, the OCC filed a complaint at the FERC alleging that AEP inappropriately allocated off-system sales margins between the AEP Eastcompanies and the AEP West companies and did not properly allocate off-systemsales margins within the AEP West companies. The PUCT, the APSC and theOklahoma Industrial Energy Consumers intervened in this filing. In November2008, the FERC issued a final order concluding that AEP inappropriately deviatedfrom off-system sales margin allocation methods in the AEP SIA and the CSWOperating Agreement for the period June 2000 through March 2006. The FERCordered AEP to recalculate and reallocate the off-system sales margins incompliance with the AEP SIA and to have the AEP East companies issue refunds tothe AEP West companies. Although the FERC determined that AEP deviated from theCSW Operating Agreement, the FERC determined the allocation methodology to bereasonable. The FERC ordered AEP to submit a revised CSW Operating Agreementfor the period June 2000 to March 2006. In December 2008, AE P filed a motionfor rehearing and a revised CSW Operating Agreement for the period June 2000 toMarch 2006. The motion for rehearing is still pending. In January 2009, AEPfiled a compliance filing with the FERC and refunded approximately $250 millionfrom the AEP East companies to the AEP West companies. The AEP West companiesshared a portion of such revenues with their wholesale and retail customersduring this period. In December 2008, the AEP West companies recorded aprovision for refund which had a $97 million unfavorable effect on AEP netincome. In January 2009, SWEPCo refunded approximately $13 million to FERCwholesale customers. In February 2009, SWEPCo filed a settlement agreementwith the PUCT that provides for the placeStateTexas retail jurisdiction refundto be made through the fuel clause recovery mechanism. PSO will begin refundingapproximately $54 million plus accrued interest to placeStateOklahoma retailcustomers through the fuel adjustment clause over a 12-month period beginningwith the March 2009 billing cycle. TCC and TNC in placeStateTexas and SWEPCo inplaceStateArkansas and placeStateLouisiana will be working with their statecommissions to determine the effect the FERC order will have on retail rates.Management believes that the existing provision for refund is adequate toaddress 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 AEPWest companies recorded in December 2008 including the net increase (decrease)to net income for the year ended dateYear2008Day31Month12December 31, 2008: INCREASE/ AMOUNTS TO BE (TRANSFERRED)/ (DECREASE) RECEIVED INCLUDING INTEREST 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 stocktickerPSO $ 72 $ 12 -------------- SWEPCo 85 20 stocktickerTCC 68 23 TNC 25 10 TOTAL - AEP WEST COMPANIES 250 65 --- -- TOTAL - AEP CONSOLIDATED $ - $ (97) Management cannot predict the outcome of the requested FERC rehearing proceedingor any future regulatory proceedings but believes our provision regarding future regulatory proceedings is adequate. ASSET IMPAIRMENTS AND OTHER RELATED CHARGES 2008 We recorded $255 million as a pretax gain in January 2008 under AssetImpairments and Other Related Charges as a result of the settlement with TEM.See "Plaquemine Cogeneration Facility" section of this note for additionalinformation. 2007 None 2006 We recorded a pretax impairment of assets totaling $209 million as a result ofthe terms of our agreement to sell the Plaquemine Cogeneration Facility to Dow.See "Plaquemine Cogeneration Facility" section of this note for additionalinformation regarding this sale. The categories of impairments and gains on dispositions include: Years Ended December 31, 2008 2007 2006Asset Impairments and Other Related Charges (Pretax) (in millions)Plaquemine Cogeneration Facility $ - $ - $209TEM Settlement (255) - -Total $ (255) $ - $ 209 Gain (Loss) on Disposition of Assets, Net (Pretax)Texas REPs $ - $ 20 $ 70Revenue Sharing on Plaquemine Cogeneration Facility 1310 -Gain on Sale of Land Rights and Other Miscellaneous Property, Plant and Equipment 3 11 (1)Total $ 16 $ 41 $ 69 Gain on Disposition of Equity Investments, Net (Pretax) Sweeny $ - $ 47 $ -Other - - 3Total $ - $ 47 $ 3 9000000 1000000 0 498000000 76000000 24000000 3.43 2.93 2.54 STOCK-BASED COMPENSATION As previously approved by shareholder vote, the Amended and Restated AmericanElectric Power System Long-Term Incentive Plan (LTIP) authorizes the use of19,200,000 shares of AEP common stock for various types of stock-based compensation awards, including stock options, to employees. A maximum of9,000,000 shares may be used under this plan for full value share awards, whichinclude performance units, restricted shares and restricted stock units. TheBoard of Directors and shareholders last approved the LTIP in 2005. Thefollowing sections provide further information regarding each type ofstock-based compensation award granted by the Human Resources Committee of theBoard of Directors (HR Committee). We adopted SFAS 123 (revised 2004) "Share-Based Payments" (SFAS 123R), effectiveJanuary 1, 2006. Stock Options We did not grant stock options in 2008, 2007 or 2006 but we do have outstandingstock options from grants in earlier periods that vested or were exercised inthese years. The exercise price of all outstanding stock options equaled orexceeded the market price of AEP's common stock on the date of grant. Alloutstanding stock options were granted with a ten-year term and generallyvested, subject to the participant's continued employment, in approximatelyequal 1/3 increments on January 1st of the year following the first, second andthird anniversary of the grant date. We record compensation cost for stockoptions over the vesting period based on the fair value on the grant date. TheLTIP does not specify a maximum contractual term for stock options. The total fair value of stock options vested and the total intrinsic value ofoptions exercised are as follows: Years Ended December 31, 2008 2007 2006Stock Options (in thousands)Fair Value of Stock Options Vested $ 25 $ 1,377$ 3,667Intrinsic Value of Options Exercised (a) 655 29,38916,823 (a) Intrinsic value is calculated as market price at exercise date less theoption exercise price. A summary of AEP stock option transactions during the years ended December 31,2008, 2007 and 2006 is as follows: 2008 2007 2006 Options Weighted Average Exercise Price OptionsWeighted Average Exercise Price Options Weighted AverageExercise Price (in thousands) (in thousands) (in thousands) Outstanding at January 1, 1,196 $ 32.693,670 $ 34.41 6,222 $ 34.16 Granted - N/A - N/A- N/A Exercised/Converted (68) 31.97 (2,454) 35.24 (2,343) 33.12 Forfeited/Expired - N/A (20)35.08 (209) 41.58Outstanding at December 31, 1,128 32.731,196 32.69 3,670 34.41 Options Exercisable at December 31, 1,125 $ 32.721,193 $ 32.68 3,411 $ 34.83 The following table summarizes information about AEP stock options outstandingat December 31, 2008. Options Outstanding 2008 Range of Exercise Prices Numberof OptionsOutstanding WeightedAverageRemainingLife WeightedAverageExercise Price AggregateIntrinsic Value (in thousands) (in years) (inthousands)$27.06 - $27.95 509 4.02 $ 27.39 $3,001$30.76 - $38.65 472 2.83 34.15375$44.10 - $49.00 147 2.36 46.71-Total (a) 1,128 3.31 32.73 $3,376 (a) Options outstanding are not significantly different from the number ofshares expected to vest. The following table summarizes information about AEP stock options exercisableat December 31, 2008. Options Exercisable 2008 Range of Exercise Prices Numberof OptionsExercisable WeightedAverageRemainingLife WeightedAverageExercise Price AggregateIntrinsic Value (in thousands) (in years) (inthousands)$27.06 - $27.95 509 4.02 $ 27.39 $3,001$30.76 - $38.65 469 2.81 34.12375$44.10 - $49.00 147 2.36 46.71-Total 1,125 3.30 32.72 $ 3,376 We include the proceeds received from exercised stock options in common stockand paid-in capital. Performance Units Our performance units are equal in value to the market value of shares of AEPcommon stock. The number of performance units held is multiplied by aperformance score to determine the actual number of performance units realized.The performance score is determined at the end of the performance period basedon performance measures, which include both performance and market conditions,established for each grant at the beginning of the performance period by the HRCommittee and can range from 0% to 200%. Performance units are paid in cash orstock at the employee's election at the end of a three-year performance andvesting period, unless they are needed to satisfy a participant's stockownership requirement. In that case, they are mandatorily deferred as AEPCareer Shares, a form of phantom stock units, until after the end of theparticipant's AEP career. AEP Career Shares have a value equivalent to themarket value of shares of AEP common stock shares and are paid in cash after theparticipant's termination of employm ent. Amounts equivalent to cash dividendson both performance units and AEP Career Shares accrue as additional units. Werecorded compensation cost for performance units over the three-year vestingperiod. The liability for both the performance units and AEP Career Shares,recorded in Employee Benefits and Pension Obligations on our ConsolidatedBalance Sheets, is adjusted for changes in value. The fair value of performanceunit awards is based on the estimated performance score and the current 20-dayaverage closing price of AEP common stock at the date of valuation. The HR Committee awarded performance units and reinvested dividends onoutstanding performance units and AEP Career Shares for the years ended December31, 2008, 2007 and 2006 as follows: Years Ended December 31, Performance Units 2008 2007 2006Awarded Units (in thousands) 1,384 8671,635Weighted Average Unit Fair Value at Grant Date $ 30.11 $47.64 $ 39.75Vesting Period (years) 3 3 3 Performance Units and AEP Career Shares Years Ended December 31,(Reinvested Dividends Portion) 2008 2007 2006Awarded Units (in thousands) 149 109118Weighted Average Grant Date Fair Value $ 37.21 $ 45.93$ 36.87Vesting Period (years) (a) (a) (a) (a) The vesting period for the reinvested dividends on performance units isequal to the remaining life of the related performance units. Dividends on AEPCareer Shares vest immediately upon grant. Performance scores and final awards are determined and certified by the HRCommittee in accordance with the pre-established performance measures. The HRCommittee has discretion to reduce or eliminate the value of final awards, butmay not increase them. The performance scores for all open performance periodsare dependent on two equally-weighted performance measures: three-year totalshareholder return measured relative to utility companies in the S&P 500 Indexand three-year cumulative earnings per share measured relative to aboard-approved target. The value of each performance unit earned equals theaverage closing price of AEP common stock for the last 20 days of theperformance period. In January 2009, the HR Committee certified a performance score for thethree-year period ended December 31, 2008 of 120.3%. As a result, 1,088,302performance units were earned. Of this amount 42,214 were mandatorily deferredas AEP Career Shares, 66,415 were voluntarily deferred into the IncentiveCompensation Deferral Program and the remaining units were paid in cash. In January 2008, the HR Committee certified a performance score for thethree-year period ended December 31, 2007 of 154.3%. As a result, 1,508,383performance units were earned. Of this amount 313,781 were mandatorily deferredas AEP Career Shares, 68,107 were voluntarily deferred into the IncentiveCompensation Deferral Program and the remaining units were paid in cash. Due to the anticipated 2004 CEO succession, on December 10, 2003, the HRCommittee made performance unit grants for the shortened performance period ofDecember 10, 2003 through December 31, 2004. No performance period ended onDecember 31, 2006 because this performance period was shorter than the normalthree-year period and there were no other performance unit grants in 2003. In2005, the HR Committee certified a performance factor of 123.1% for performanceunits granted on December 10, 2003 and 946,789 performance units weremandatorily deferred into AEP stock units. These units had a three year vestingperiod which ended on December 31, 2006, at which time, 917,032 units vested andthe remaining units were forfeited due to participant terminations. Of the917,032 vested units 388,801 were mandatorily deferred as AEP Career Shares andthe remaining units were paid in cash. The cash payouts for the years ended December 31, 2008, 2007 and 2006 were asfollows: Years Ended December 31, 2008 2007 2006 (in thousands)Cash Payouts for Performance Units $ 52,960 $ 21,460$ 2,630Cash Payouts for AEP Career Share Distributions 1,2361,348 1,079 Restricted Shares and Restricted Stock Units The independent members of the Board of Directors granted 300,000 restricted shares to the Chairman, President and CEO on January 2, 2004 upon thecommencement of his AEP employment. Of these restricted shares, 50,000 vestedon January 1, 2005 and 50,000 vested on January 1, 2006. The remaining 200,000restricted shares vest, subject to his continued employment, in approximatelyequal thirds on November 30, 2009, 2010 and 2011. Compensation cost forrestricted shares is measured at fair value on the grant date and recorded overthe vesting period. Fair value is determined by multiplying the number of sharesgranted by the grant date market price of $30.76. The maximum term for theserestricted shares is eight years. AEP has not granted other restricted shares.Dividends on these restricted shares are paid in cash. The HR Committee also grants restricted stock units (RSUs), which generallyvest, subject to the participant's continued employment, over at least threeyears in approximately equal annual increments on the anniversaries of the grantdate. Amounts equivalent to dividends paid on RSUs accrue as additional RSUsand vest on the last vesting date associated with the underlying units.Compensation cost is measured at fair value on the grant date and recorded overthe vesting period. Fair value is determined by multiplying the number of unitsgranted by the grant date market price. The maximum contractual term of RSUs issix years from the grant date. The HR Committee has granted RSUs with performance vesting conditions to certainemployees who are integral to our project to design and build proposed IGCCpower plants. In February 2007, the HR Committee granted approximately 12,000shares of RSUs that vest 10% on each of the first three anniversaries of thegrant date. An additional 10% vest on the date the IGCC plant achievessubstantial completion. Another 20% vest on the date the IGCC plant achievescommercial operation. An additional 20% vest one year after the IGCC plantachieves commercial operation, subject to achievement of plant availabilitytargets. The remaining 20% vest two years after the IGCC plant achievescommercial operation, subject to achievement of plant availability targets. In January 2006, the HR Committee granted approximately 11,000 shares of RSUswith performance vesting conditions related to our IGCC project. Twenty percentof these awards vested on each of the first three anniversaries of the grantdate. An additional 20% vest on the date the IGCC plant achieves commercialoperation. The remaining 20% vest one year after the IGCC plant achievescommercial operation, subject to achievement of plant availability targets. In 2008, the HR Committee did not grant RSUs with performance vestingconditions. The HR Committee awarded RSUs, including units awarded for dividends, for theyears ended December 31, 2008, 2007 and 2006 as follows: Years Ended December 31, 2008 2007 2006Restricted Stock UnitsAwarded Units (in thousands) 56 148 65Weighted Average Grant Date Fair Value $ 41.69 $ 45.89$ 37.47 The total fair value and total intrinsic value of restricted shares andrestricted stock units vested during the years ended December 31, 2008, 2007 and2006 were as follows: Years Ended December 31, 2008 2007 2006Restricted Shares and Restricted Stock Units (in thousands) Fair Value of Restricted Shares and Restricted Stock Units Vested $2,619 $ 2,711 $ 3,939Intrinsic Value of Restricted Shares and Restricted Stock Units Vested (a)2,534 3,646 4,686 (a) Intrinsic value is calculated as market price. A summary of the status of our nonvested restricted shares and RSUs as ofDecember 31, 2008 and changes during the year ended December 31, 2008 are asfollows: Shares/Units Weighted Average Grant Date Fair ValueNonvested Restricted Shares andRestricted Stock Units (in thousands)Nonvested at January 1, 2008 453 $ 36.93Granted 56 41.69Vested (65) 40.19Forfeited (1) 42.80Nonvested at December 31, 2008 443 37.04 The total aggregate intrinsic value of nonvested restricted shares and RSUs asof December 31, 2008 was $14 million and the weighted average remainingcontractual life was 2.62 years. Other Stock-Based Plans We also have a Stock Unit Accumulation Plan for Nonemployee Directors providingeach nonemployee director with AEP stock units as a substantial portion of theirquarterly compensation for their services as a director. Amounts equivalent tocash dividends on the stock units accrue as additional AEP stock units. Thenonemployee directors vest immediately upon award of the stock units. Stockunits are paid in cash upon termination of board service or up to 10 years laterif the participant so elects. Cash payments for stock units are calculatedbased on the average closing price of AEP common stock for the 20 trading daysimmediately preceding the payment date. We recorded the compensation cost for stock units when the units are awarded andadjusted the liability for changes in value based on the current 20-day averageclosing price of AEP common stock at the date of valuation. We had no material cash payouts for stock unit distributions for the years endedDecember 31, 2008, 2007 and 2006. The Board of Directors awarded stock units, including units awarded fordividends, for the years ended December 31, 2008, 2007 and 2006 as follows: Years Ended December 31, 2008 2007 2006Stock Unit Accumulation Plan for Non-Employee DirectorsAwarded Units (in thousands) 43 28 33Weighted Average Grant Date Fair Value $ 37.72 $ 46.46$ 36.66 Share-based Compensation Plans Compensation cost and the actual tax benefit realized for the tax deductionsfrom compensation cost for share-based payment arrangements recognized in incomeand total compensation cost capitalized in relation to the cost of an asset forthe years ended December 31, 2008, 2007 and 2006 were as follows: Years Ended December 31, 2008 2007 2006Share-based Compensation Plans (in thousands)Compensation Cost for Share-based Payment Arrangements (a) $(18,028) (b) $ 72,004 $ 45,842Actual Tax Benefit Realized (6,310) (b) 25,20116,045Total Compensation Cost Capitalized (5,026) (b)18,077 10,953 (a) Compensation cost for share-based payment arrangements is included inOther Operation and Maintenance on our Consolidated Statements of Income.(b) In 2008, AEP's declining total shareholder return and lower stock pricesignificantly reduced the accruals for performance units. During the years ended December 31, 2008, 2007 and 2006, there were nosignificant modifications affecting any of our share-based payment arrangements. As of December 31, 2008, there was $70 million of total unrecognized compensation cost related to unvested share-based compensation arrangementsgranted under the LTIP. Unrecognized compensation cost related to theperformance units and AEP Career Shares will change as the fair value isadjusted each period and forfeitures for all award types are realized. Ourunrecognized compensation cost will be recognized over a weighted-average periodof 1.78 years. Cash received from stock options exercised and actual tax benefit realized forthe tax deductions from stock options exercised during the years ended December31, 2008, 2007 and 2006 were as follows: Years Ended December 31, 2008 2007 2006Share-based Compensation Plans (in thousands)Cash Received from Stock Options Exercised $ 2,170 $86,527 $ 77,534Actual Tax Benefit Realized for the Tax Deductions from Stock Options Exercised219 10,282 5,825 Our practice is to use authorized but unissued shares to fulfill sharecommitments for stock option exercises and RSU vesting. Although we do notcurrently anticipate any changes to this practice, we could use reacquiredshares, shares acquired in the open market specifically for distribution underthe LTIP or any combination thereof for this purpose. The number of new sharesissued to fulfill vesting RSUs is generally reduced to offset AEP's tax withholding obligation. NEW ACCOUNTING PRONOUNCEMENTS Upon issuance of final pronouncements, we review the new accounting literatureto determine its relevance, if any, to our business. The following represents asummary of final pronouncements that we have determined relate to ouroperations. Pronouncements Adopted in 2008 The following standards were effective during 2008. Consequently, the financialstatements and footnotes reflect their impact. SFAS 157 "Fair Value Measurements" (SFAS 157) We partially adopted SFAS 157 effective January 1, 2008. The statement defines fair value, establishes a fair value measurement framework and expands fairvalue disclosures. In February 2008, the FASB issued FSP SFAS 157-1 "Application of FASB StatementNo. 157 to FASB Statement No. 13 and Other Accounting Pronouncements ThatAddress Fair Value Measurements for Purposes of Lease Classification orMeasurement under Statement 13" (SFAS 157-1) which amends SFAS 157 to excludeSFAS 13 "Accounting for Leases" (SFAS 13) and other accounting pronouncementsthat address fair value measurements for purposes of lease classification ormeasurement under SFAS 13. SFAS 157-1 was effective upon issuance and had animmaterial impact on our financial statements. In February 2008, the FASB issued FSP SFAS 157-2 "Effective Date of FASBStatement No. 157" (SFAS 157-2) which delays the effective date of SFAS 157 tofiscal years beginning after November 15, 2008 for all nonfinancial assets andnonfinancial liabilities, except those that are recognized or disclosed at fairvalue in the financial statements on a recurring basis (at least annually). Weadopted SFAS 157 effective January 1, 2009 for items within the scope of SFAS157-2. The adoption of SFAS 157-2 had an immaterial impact on our financialstatements. In October 2008, the FASB issued FSP SFAS 157-3 "Determining the Fair Value of aFinancial Asset When the Market for That Asset is Not Active" which clarifiesapplication of SFAS 157 in markets that are not active and provides anillustrative example. The FSP was effective upon issuance. The adoption ofthis standard had no impact on our financial statements. See "SFAS 157 Fair Value Measurements" Section of Note 11 for furtherinformation. 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 andcertain other items at fair value. The standard also established presentationand disclosure requirements designed to facilitate comparison between entitiesthat choose different measurement attributes for similar types of assets andliabilities. If the fair value option is elected, the effect of the firstremeasurement to fair value is reported as a cumulative effect adjustment to theopening balance of retained earnings. The statement is applied prospectivelyupon adoption. We adopted SFAS 159 effective January 1, 2008. At adoption, we did not electthe 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 generallyaccepted accounting principles in descending order of authority. The statementspecifies that the reporting entity, not its auditors, is responsible for itscompliance with GAAP. We adopted SFAS 162 in the fourth quarter of 2008. The adoption of thisstandard had no impact on our financial statements. EITF Issue No. 06-10 "Accounting for Collateral Assignment Split-Dollar LifeInsurance Arrangements"(EITF 06-10) In March 2007, the FASB ratified EITF 06-10, a consensus on collateralassignment split-dollar life insurance arrangements in which an employee ownsand controls the insurance policy. Under EITF 06-10, an employer shouldrecognize a liability for the postretirement benefit related to a collateralassignment split-dollar life insurance arrangement if the employer agreed tomaintain a life insurance policy during the employee's retirement or to providethe employee with a death benefit based on a substantive arrangement with theemployee. In addition, an employer should recognize and measure an asset basedon the nature and substance of the collateral assignment split-dollar lifeinsurance arrangement. EITF 06-10 requires recognition of the effects of itsapplication as either (a) a cumulative effect adjustment to retained earnings orother components of equity or net assets in the statement of financial positionat the beginning of the year of adoption or (b) retrospective application to allprior periods. We adopted EITF 06-10 effective January 1, 2008 with acumulative effect reduction of $16 million ($10 million, net of tax) tobeginning retained earnings. EITF Issue No. 06-11 "Accounting for Income Tax Benefits of Dividends onShare-Based Payment Awards"(EITF 06-11) In June 2007, the FASB addressed the recognition of income tax benefits ofdividends on employee share-based compensation. Under EITF 06-11, a realizedincome tax benefit from dividends or dividend equivalents that are charged toretained earnings and are paid to employees for equity-classified nonvestedequity shares, nonvested equity share units and outstanding equity share optionsshould be recognized as an increase to additional paid-in capital. We adopted EITF 06-11 effective January 1, 2008. The adoption of this standardhad an immaterial impact on our financial statements. FSP SFAS 133-1 and FIN 45-4 "Disclosures about Credit Derivatives and CertainGuarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No.45; and Clarification of the Effective Date of FASB Statement No. 161" (FSP SFAS133-1 and FIN 45-4) In September 2008, the FASB issued FSP SFAS 133-1 and FIN 45-4 amending SFAS 133and FIN 45 "Guarantor's Accounting and Disclosure Requirements for Guarantees,Including Indirect Guarantees of Indebtedness of Others." Under the SFAS 133requirements, the seller of a credit derivative shall disclose the followinginformation for each derivative, including credit derivatives embedded in ahybrid 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 collateralor 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 usesinternal groupings, the entity shall disclose how those groupings are determinedand used for managing risk. We adopted the standard effective December 31, 2008. The adoption of thisstandard had no impact on our financial statements but increased our guaranteesdisclosures in Note 6. FSP SFAS 140-4 and FIN 46R-8 "Disclosures by Public Entities (Enterprises) aboutTransfers of Financial Assets and Interests in Variable Interest Entities" (FSPSFAS 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 Extinguishmentsof Liabilities" and FIN 46R "Consolidation of Variable Interest Entities."Under the requirements, the transferor of financial assets in the securitizationor asset-backed financing arrangement must disclose the following: (a) Nature of any restrictions on assets reported by an entity in itsbalance sheet that relate to a transferred financial asset, including thecarrying amounts of such assets.(b) Method of reporting servicing assets and servicing liabilities. (c) If reported as sales and the transferor has continuing involvement withthe transferred financial assets and the transfers are accounted for as securedborrowings, 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 enterprisethat (a) is the primary beneficiary of a variable interest entity (VIE), (b)holds a significant variable interest in a VIE but is not the primarybeneficiary or (c) is a sponsor that holds a variable interest in a VIE. Theprinciple objectives of the disclosures required by this standard are to providefinancial statement users an understanding of: (a) Significant judgments and assumptions made to determine whether toconsolidate a variable interest entity and/or disclose information aboutinvolvement with a variable interest entity.(b) Nature of the restrictions on a consolidated variable interest entity'sassets reported in the balance sheet, including the carrying amounts of suchassets.(c) Nature of, and changes in, risks associated with a company's involvementwith a variable interest entity.(d) A variable interest entity's effect on the balance sheet, net income andcash flows.(e) The nature, purpose, size and activities of any variable interestequity, including how it is financed. We adopted the standard effective December 31, 2008. The adoption of thisstandard had no impact on our financial statements but increased our footnotedisclosures for variable interest entities. See "Principles of Consolidation"section of Note 1. 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 ofAmounts Related to Certain Contracts" by replacing the interpretation's definition of contracts with the definition of derivative instruments per SFAS133. The amendment requires entities that offset fair values of derivativeswith the same party under a netting agreement to net the fair values (orapproximate fair values) of related cash collateral. The entities must disclosewhether or not they offset fair values of derivatives and related cashcollateral and amounts recognized for cash collateral payables and receivablesat the end of each reporting period. We adopted the standard effective January 1, 2008. This standard changed ourmethod of netting certain balance sheet amounts and reduced assets andliabilities. It requires retrospective application as a change in accountingprinciple. Consequently, we reclassified the following amounts on the December31, 2007 Consolidated Balance Sheet as shown:Balance SheetLine Description As Reported forthe December 200710-K FSP FIN 39-1Reclassification As Reported forthe December 200810-KCurrent Assets: (in millions)Risk Management Assets $ 286 $ (15) $ 271Margin Deposits 58 (11) 47Long-term Risk Management Assets 340 (21)319 Current Liabilities: Risk Management Liabilities 250 (10)240Customer Deposits 337 (36) 301Long-term Risk Management Liabilities 189 (1)188 For certain risk management contracts, we are required to post or receive cashcollateral based on third party contractual agreements and risk profiles. Forthe December 31, 2008 balance sheet, we netted $11 million of cash collateralreceived from third parties against short-term and long-term risk managementassets and $43 million of cash collateral paid to third parties againstshort-term and long-term risk management liabilities. 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 2009financial statements when filed. The following paragraphs discuss theirexpected 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 aboutbusiness combinations and their effects. It established how the acquiringentity recognizes and measures the identifiable assets acquired, liabilitiesassumed, goodwill acquired, any gain on bargain purchases and any noncontrollinginterest in the acquired entity. SFAS 141R no longer allows acquisition-relatedcosts to be included in the cost of the business combination, but ratherexpensed in the periods they are incurred, with the exception of the costs toissue debt or equity securities which shall be recognized in accordance withother applicable GAAP. The standard requires disclosure of information for abusiness combination that occurs during the accounting period or prior to theissuance of the financial statements for the accounting period. SFAS 141R canaffect tax positions on previous acquisitions. We do not have any such taxpositions that result in adjustments. We adopted SFAS 141R effective January 1, 2009. It is effective prospectivelyfor business combinations with an acquisition date on or after January 1, 2009.We will apply it to any future business combinations. SFAS 160 "Noncontrolling Interest in Consolidated Financial Statements" (SFAS160) In December 2007, the FASB issued SFAS 160, modifying reporting fornoncontrolling interest (minority interest) in consolidated financial statements. The statement requires noncontrolling interest be reported inequity and establishes a new framework for recognizing net income or loss andcomprehensive income by the controlling interest. Upon deconsolidation due toloss of control over a subsidiary, the standard requires a fair valueremeasurement of any remaining noncontrolling equity investment to be used toproperly recognize the gain or loss. SFAS 160 requires specific disclosuresregarding changes in equity interest of both the controlling and noncontrollingparties and presentation of the noncontrolling equity balance and income or lossfor all periods presented. We adopted SFAS 160 effective January 1, 2009. The adoption of this standardhad an immaterial impact and will be applied retrospectively to prior periodfinancial statements in future filings so the presentation of noncontrollinginterest is comparable. SFAS 161 "Disclosures about Derivative Instruments and Hedging Activities" (SFAS161) In March 2008, the FASB issued SFAS 161, enhancing disclosure requirements forderivative instruments and hedging activities. Affected entities are requiredto provide enhanced disclosures about (a) how and why an entity uses derivativeinstruments, (b) how an entity accounts for derivative instruments and relatedhedged items and (c) how derivative instruments and related hedged items affectan entity's financial position, financial performance and cash flows. Thestandard requires that objectives for using derivative instruments be disclosedin terms of underlying risk and accounting designation. We adopted SFAS 161 effective January 1, 2009. This standard will increase ourdisclosure requirements related to derivative instruments and hedging activitiesin future reports. EITF Issue No. 08-5 "Issuer's Accounting for Liabilities Measured at Fair Valuewith a Third-Party Credit Enhancement" (EITF 08-5) In September 2008, the FASB ratified the consensus on liabilities withthird-party credit enhancements when the liability is measured and disclosed atfair value. The consensus treats the liability and the credit enhancement astwo units of accounting. Under the consensus, the fair value measurement of theliability does not include the effect of the third-party credit enhancement.Consequently, changes in the issuer's credit standing without the support of thecredit enhancement affect the fair value measurement of the issuer's liability.Entities will need to provide disclosures about the existence of any third-partycredit enhancements related to their liabilities. In the period of adoption,entities must disclose the valuation method(s) used to measure the fair value ofliabilities within its scope and any change in the fair value measurement methodthat occurs as a result of its initial application. We adopted EITF 08-5 effective January 1, 2009. It will be appliedprospectively with the effect of initial application included as a change infair value of the liability in the period of adoption. The adoption of thisstandard will impact the financial statements in the 2009 Annual Report as wereport fair value of long-term debt annually. EITF Issue No. 08-6 "Equity Method Investment Accounting Considerations" (EITF08-6) In November 2008, the FASB ratified the consensus on equity method investmentaccounting including initial and allocated carrying values and subsequentmeasurements. It requires initial carrying value be determined using the SFAS141R cost allocation method. When an investee issues shares, the equity methodinvestor should treat the transaction as if the investor sold part of itsinterest. We adopted EITF 08-6 effective January 1, 2009 with no impact on our financialstatements. It was applied prospectively. FSP EITF 03-6-1 "Determining Whether Instruments Granted in Share-Based PaymentTransactions Are Participating Securities" (EITF 03-6-1) In June 2008, the FASB addressed whether instruments granted in share-basedpayment transactions are participating securities prior to vesting anddetermined that the instruments need to be included in earnings allocation incomputing EPS under the two-class method described in SFAS 128 "Earnings perShare." We adopted EITF 03-6-1 effective January 1, 2009. The adoption of this standardhad an immaterial impact on our financial statements. FSP SFAS 142-3 "Determination of the Useful Life of Intangible Assets" (SFAS142-3) In April 2008, the FASB issued SFAS 142-3 amending factors that should beconsidered in developing renewal or extension assumptions used to determine theuseful life of a recognized intangible asset. The standard is expected toimprove consistency between the useful life of a recognized intangible asset andthe period of expected cash flows used to measure its fair value. We adopted SFAS 142-3 effective January 1, 2009. The guidance is prospectivelyapplied to intangible assets acquired after the effective date. The standard'sdisclosure requirements are applied prospectively to all intangible assets as ofJanuary 1, 2009. The adoption of this standard had no impact on our financialstatements. Pronouncements Effective in the Future The following standards will be effective in the future and their impactsdisclosed at that time. FSP SFAS 132R-1 "Employers' Disclosures about Postretirement Benefit PlanAssets" (FSP SFAS 132R-1) In December 2008, the FASB issued FSP SFAS 132R-1 providing additionaldisclosure guidance for pension and OPEB plan assets. The rule requiresdisclosure of investment policy including target allocations by investmentclass, investment goals, risk management policies and permitted or prohibitedinvestments. It specifies a minimum of investment classes by further dividingequity and debt securities by issuer grouping. The standard adds disclosurerequirements including hierarchical classes for fair value and concentration ofrisk. This standard is effective for fiscal years ending after December 15, 2009.Management expects this standard to increase the disclosure requirements relatedto our benefit plans. We will adopt the standard effective for the 2009 AnnualReport. Future Accounting Changes The FASB's standard-setting process is ongoing and until new standards have beenfinalized and issued, we cannot determine the impact on the reporting of ouroperations 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, earnings per sharecalculations, leases, insurance, hedge accounting consolidation policy, tradinginventory and related tax impacts. We also expect to see more FASB projects asa result of its desire to converge International Accounting Standards with GAAP.The ultimate pronouncements resulting from these and future projects could havean impact on our future net income and financial position. -298000000 79000000 0 -298000000 79000000 0 192000000 74000000 89000000 1917000000 11213000000 18080000000 1922000000 11086000000 18359000000 -48000000 49000000 36000000 1380000000 1089000000 1002000000 1380000000 1089000000 1002000000 45155000000 40319000000 49710000000 46145000000 10-K 159000000 144000000 99000000 3.42 2.92 2.53 0.03 0.06 0.03 12000000 24000000 10000000 16000000 41000000 69000000 1143000000 1159000000 2184000000 712000000 7938000000 7392000000 86000000 47000000 COMMITMENTS AND CONTINGENCIES We are subject to certain claims and legal actions arising in our ordinarycourse of business. In addition, our business activities are subject toextensive governmental regulation related to public health and the environment.The ultimate outcome of such pending or potential litigation against us cannotbe predicted. For current proceedings not specifically discussed below,management does not anticipate that the liabilities, if any, arising from suchproceedings would have a material adverse effect on our financial statements. Insurance and Potential Losses We maintain insurance coverage normal and customary for an integrated electricutility, subject to various deductibles. Our insurance includes coverage forall risks of physical loss or damage to our nonnuclear assets, subject toinsurance policy conditions and exclusions. Covered property generally includespower plants, substations, facilities and inventories. Excluded propertygenerally includes transmission and distribution lines, poles and towers. Ourinsurance programs also generally provide coverage against loss arising fromcertain claims made by third parties and are in excess of retentions absorbed byus. Coverage is generally provided by a combination of a South Carolinadomiciled protected-cell captive insurance company, EIS, together with and/or inaddition to various industry mutual and commercial insurance carriers. See Note 9 for a discussion of nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount ofinsurance carried may not be sufficient to meet potential losses andliabilities, including, but not limited to, liabilities relating to damage tothe Cook Plant and costs of replacement power in the event of an incident at theCook Plant. Future losses or liabilities, if they occur, which are notcompletely insured, unless recovered from customers, could have a materialadverse effect on our net income, cash flows and financial condition. COMMITMENTS Construction and Commitments The AEP System has substantial construction commitments to support itsoperations and environmental investments. In managing the overall constructionprogram and in the normal course of business, we contractually commit tothird-party construction vendors for certain material purchases and otherconstruction services. Budgeted construction expenditures for 2009 are $2.6billion. In addition, we expect to invest approximately $50 million in ourtransmission joint ventures in 2009. Budgeted construction expenditures aresubject to periodic review and modification and may vary based on the ongoingeffects of regulatory constraints, environmental regulations, businessopportunities, market volatility, economic trends, weather, legal reviews andthe ability to access capital. Our 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. Wedo not expect to incur penalty payments under these provisions that wouldmaterially affect our net income, cash flows or financial condition. The following table summarizes our actual contractual commitments at December31, 2008: Less Than 1 year 2-3 years 4-5 years After5 years TotalContractual Commitments (in millions)Fuel Purchase Contracts (a) $ 3,788 $ 4,832 $2,590 $ 7,362 $ 18,572Energy and Capacity Purchase Contracts (b) 51 7340 268 432Construction Contracts for Capital Assets (c) 661 993 613 - 2,267Total $ 4,500 $ 5,898 $ 3,243 $7,630 $ 21,271 (a) Represents contractual commitments to purchase coal, natural gas andother consumables as fuel for electric generation along with relatedtransportation of the fuel. The longest contract extends to the year 2035. Thecontracts provide for periodic price adjustments and contain various clausesthat would release us from our commitments under certain conditions. (b) Represents contractual commitments for energy and capacity purchasecontracts.(c) Represents only capital assets that are contractual commitments. CONTINGENCIES Federal EPA Complaint and Notice of Violation 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-firedgenerating plants in violation of the NSR requirements of the CAA. Cases withsimilar allegations against CSPCo, Dayton Power and Light Company (DP&L) andDuke Energy Ohio, Inc. were also filed related to their jointly-owned units. In 2007, the U.S. District Court approved our consent decree with the FederalEPA, the DOJ, the states and the special interest groups. The consent decreeresolved all issues related to various parties' claims against us in the NSRcases. Under the consent decree, we paid a $15 million civil penalty in 2008and provided $36 million for environmental mitigation projects coordinated withthe federal government and $24 million to the states for environmental mitigation. We expensed these amounts in 2007. In October 2008, the court approved a consent decree for a settlement reachedwith the Sierra Club in a case involving CSPCo's share of jointly-owned units atthe Stuart Station. The Stuart units, operated by DP&L, are equipped with SCRand FGD controls. Under the terms of the settlement, the joint-owners agreed tocertain emission targets related to NOx, SO2 and PM. They also agreed to makeenergy efficiency and renewable energy commitments that are conditioned onreceiving PUCO approval for recovery of costs. The joint-owners also agreed toforfeit 5,500 SO2 allowances and provide $300 thousand to a third partyorganization to establish a solar water heater rebate program. Another caseinvolving a jointly-owned Beckjord unit had a liability trial in 2008.Following the trial, the jury found no liability for claims made against thejointly-owned Beckjord unit. In December 2008, however, the court ordered anew trial in the Beckjord case. We are unable to estimate the loss or range of loss related to any contingentliability, if any, we might have for civil penalties under the pending CAAproceeding for Beckjord. We are also unable to predict the timing of resolutionof these matters. If we do not prevail, we believe we can recover any capitaland operating costs of additional pollution control equipment that may berequired as a result of the consent decree through future regulated rates ormarket prices of electricity. If we are unable to recover such costs or ifmaterial penalties are imposed, it would adversely affect our future net income,cash flows and possibly financial condition. SWEPCo Notice of Enforcement and Notice of Citizen Suit In March 2005, two special interest groups, Sierra Club and Public Citizen,filed a complaint in federal district court for the Eastern District of Texasalleging violations of the CAA at SWEPCo's Welsh Plant. In April 2008, theparties filed a proposed consent decree to resolve all claims in this case andin the pending appeal of the altered permit for the Welsh Plant. The consentdecree requires SWEPCo to install continuous particulate emission monitors atthe Welsh Plant, secure 65 MW of renewable energy capacity by 2010, fund $2million in emission reduction, energy efficiency or environmental mitigationprojects 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 ofEnforcement to SWEPCo relating to the Welsh Plant. A permit alteration wasissued in March 2007 that clarified or eliminated certain of the permitconditions. In June 2007, TCEQ denied a motion to overturn the permitalteration. The permit alteration was appealed to the Travis County DistrictCourt, but was resolved by entry of the consent decree in the federal citizensuit action, and dismissed with prejudice in July 2008. Notice of anadministrative settlement of the TCEQ enforcement action was published in June2008. The settlement requires SWEPCo to pay an administrative penalty of $49thousand and to fund a supplemental environmental project in the amount of $49thousand, and resolves all violations alleged by TCEQ. In October 2008, TCEQapproved the settlement. In February 2008, the Federal EPA issued a Notice of Violation (NOV) based onalleged violations of a percent sulfur in fuel limitation and the heat inputvalues listed in the previous state permit. The NOV also alleges that thepermit alteration issued by TCEQ was improper. SWEPCo met with the Federal EPAto discuss the alleged violations in March 2008. The Federal EPA did not objectto the settlement of similar alleged violations in the federal citizen suit. We are unable to predict the timing of any future action by the Federal EPA orthe effect of such action on our net income, cash flows or financial condition. Carbon Dioxide Public Nuisance Claims In 2004, eight states and the City of New York filed an action in federaldistrict court for the Southern District of New York against AEP, AEPSC, CinergyCorp, Xcel Energy, Southern Company and Tennessee Valley Authority. The NaturalResources Defense Council, on behalf of three special interest groups, filed asimilar complaint against the same defendants. The actions allege that CO2emissions from the defendants' power plants constitute a public nuisance underfederal common law due to impacts of global warming, and sought injunctiverelief in the form of specific emission reduction commitments from thedefendants. The dismissal of this lawsuit was appealed to the Second CircuitCourt of Appeals. Briefing and oral argument concluded in 2006. In April2007, the U.S. Supreme Court issued a decision holding that the Federal EPA hasauthority to regulate emissions of CO2 and other greenhouse gases under the CAA,which may impact the Second Circuit's analysis of these issues. The SecondCircuit requested supplementa l briefs addressing the impact of the SupremeCourt's decision on this case which we provided in 2007. We believe the actionsare without merit and intend to defend against the claims. Alaskan Villages' Claims 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 Californiaagainst AEP, AEPSC and 22 other unrelated defendants including oil & gascompanies, a coal company, and other electric generating companies. Thecomplaint alleges that the defendants' emissions of CO2 contribute to globalwarming and constitute a public and private nuisance and that the defendants areacting together. The complaint further alleges that some of the defendants,including AEP, conspired to create a false scientific debate about globalwarming in order to deceive the public and perpetuate the alleged nuisance. Theplaintiffs also allege that the effects of global warming will require therelocation of the village at an alleged cost of $95 million to $400 million.The defendants filed motions to dismiss the action. The motions are pendingbefore the court. We believe the action is without merit and intend to defendagainst the claims. The Comprehensive Environmental Response Compensation and Liability Act(Superfund) and State Remediation By-products from the generation of electricity include materials such as ash,slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products,which constitute the overwhelming percentage of these materials, are typicallytreated and deposited in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distributionfacilities have used asbestos, polychlorinated biphenyls (PCBs) and otherhazardous and nonhazardous materials. We currently incur costs to safelydispose of these substances. Superfund addresses clean-up of hazardous substances that have been released tothe environment. The Federal EPA administers the clean-up programs. Severalstates have enacted similar laws. At December 31, 2008, our subsidiaries arenamed by the Federal EPA as a Potentially Responsible Party (PRP) for six sitesfor which alleged liability is unresolved. There are nine additional sites forwhich our subsidiaries have received information requests which could lead toPRP designation. Our subsidiaries have also been named potentially liable atfour sites under state law including the I&M site discussed in the nextparagraph. In those instances where we have been named a PRP or defendant, ourdisposal or recycling activities were in accordance with the then-applicablelaws and regulations. Superfund does not recognize compliance as a defense, butimposes strict liability on parties who fall within its broad statutorycategories. Liability has been resolved for a number of sites with nosignificant effect on net i ncome. In March 2008, I&M received a letter from the Michigan Department ofEnvironmental Quality (MDEQ) concerning conditions at a site under state law andrequesting I&M take voluntary action necessary to prevent and/or mitigate publicharm. 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 recordedapproximately $4 million of expense through December 31, 2008. As theremediation work is completed, I&M's cost may increase. I&M cannot predict theamount of additional cost, if any. At present, our estimates do not anticipatematerial cleanup costs for this site. We evaluate the potential liability for each Superfund site separately, butseveral general statements can be made regarding our potential future liability.Disposal of materials at a particular site is often unsubstantiated and thequantity of materials deposited at a site was small and often nonhazardous.Although Superfund liability has been interpreted by the courts as joint andseveral, typically many parties are named as PRPs for each site and several ofthe parties are financially sound enterprises. At present, our estimates do notanticipate material cleanup costs for any of our identified Superfund sites. Cook Plant Unit 1 Fire and Shutdown In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbinevibrations, likely caused by blade failure, which resulted in a fire on theelectric generator. This equipment, located in the turbine building, isseparate and isolated from the nuclear reactor. The turbine rotors that causedthe vibration were installed in 2006 and are within the vendor's warrantyperiod. The warranty provides for the repair or replacement of the turbinerotors if the damage was caused by a defect in materials or workmanship. I&M isworking with its insurance company, Nuclear Electric Insurance Limited (NEIL),and its turbine vendor, Siemens, to evaluate the extent of the damage resultingfrom the incident and the costs to return the unit to service. Repair of theproperty damage and replacement of the turbine rotors and other equipment couldcost up to approximately $330 million. Management believes that I&M shouldrecover a significant portion of these costs through the turbine vendor'swarranty, insurance an d the regulatory process. Our current analysis indicatesthat with successful repairs and timely parts deliveries, Unit 1 could resumeoperations as early as September 2009 at reduced power. If the rotors cannot berepaired, replacement of parts will extend the outage into 2010. The refueling outage for Cook Plant Unit 2, which continues to operate at fullpower, will take place as scheduled in the spring of 2009. The refueling outagescheduled for the fall of 2009 for Unit 1 is currently being evaluated.Management anticipates that the loss of capacity from Unit 1 will not affectI&M's ability to serve customers due to the existence of sufficient generatingcapacity in the AEP Power Pool. I&M maintains property insurance through NEIL with a $1 million deductible. Asof December 31, 2008, we recorded $28 million in Prepayments and Other on ourConsolidated Balance Sheet representing recoverable amounts under propertyinsurance proceeds. I&M also maintains a separate accidental outage policy withNEIL whereby, after a 12-week deductible period, I&M is entitled to weeklypayments 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 weekfor up to an additional 110 weeks. I&M began receiving payments under theaccidental outage policy effective December 15, 2008. If the ultimate costs ofthe incident are not covered by warranty, insurance or through the regulatoryprocess or if the unit is not returned to service in a reasonable period oftime, it could have an adverse impact on net income, cash flows and financialcondition. In January 2009, I&M filed its regular semi-annual fuel filing in Indiana whichdetermines the fuel rate for the period April 2009 through September 2009. I&Mfiled to provide to customers a portion of the accidental outage insuranceproceeds expected during the forecast period. I&M has deferred $9 million ofaccidental outage insurance proceeds as of December 31, 2008 which is includedin Other Current Liabilities on our Consolidated Balance Sheet. TEM Litigation We agreed to sell up to approximately 800 MW of energy to Tractebel EnergyMarketing, Inc. (TEM) (now known as SUEZ Energy Marketing NA, Inc.) for a periodof 20 years under a Power Purchase and Sale Agreement (PPA). Beginning May 1,2003, we tendered replacement capacity, energy and ancillary services to TEMpursuant to the PPA that TEM rejected as nonconforming. In 2003, TEM and AEP separately filed declaratory judgment actions in the UnitedStates District Court for the Southern District of New York. In January 2008, we reached a settlement with TEM to resolve all litigationregarding the PPA. TEM paid us $255 million. We recorded the $255 million as apretax gain in January 2008 under Asset Impairments and Other Related Charges onour Consolidated Statements of Income. This settlement related to thePlaquemine Cogeneration Facility, which we impaired and sold in 2006. Enron Bankruptcy In 2001, we purchased HPL from Enron. Various HPL-related contingencies andindemnities from Enron remained unsettled at the date of Enron's bankruptcy. Inconnection with our acquisition of HPL, we entered into an agreement with BAMLease Company that granted HPL the exclusive right to use approximately 55billion cubic feet (BCF) of cushion gas required for the normal operation of theBammel gas storage facility. At the time of our acquisition of HPL, BOA andcertain other banks (the BOA Syndicate) and Enron entered into an agreementgranting HPL the exclusive use of the cushion gas. Also at the time of ouracquisition, Enron and the BOA Syndicate released HPL from all prior and futureliabilities and obligations in connection with the financing arrangement. Afterthe Enron bankruptcy, the BOA Syndicate informed HPL of a purported default byEnron under the terms of the financing arrangement. This dispute is beinglitigated in the Enron bankruptcy proceedings and in federal courts in Texas andNew York. In February 2004, Enron filed Notices of Rejection regarding the cushion gasexclusive right to use agreement and other incidental agreements. We objectedto Enron's attempted rejection of these agreements and filed an adversaryproceeding in the bankruptcy proceeding contesting Enron's right to reject theseagreements. In 2003, AEP filed a lawsuit against BOA in the United States District Court forthe Southern District of Texas. BOA led the lending syndicate involving themonetization of the cushion gas to Enron and its subsidiaries. The lawsuitasserts that BOA made representations and engaged in fraud to induce and promotethe stock sale of HPL, that BOA directly benefited from the sale of HPL and thatAEP undertook the stock purchase and entered into the cushion gas arrangementwith Enron and BOA based on misrepresentations that BOA made about Enron'sfinancial condition that BOA knew or should have known were false. In April2005, the Judge in Texas entered an order severing and transferring thedeclaratory judgment claims involving the right to use and cushion gas consentagreements to the Southern District of New York and retaining in the SouthernDistrict of Texas the four counts alleging breach of contract, fraud andnegligent misrepresentation. HPL and BOA filed motions for summary judgment inthe case pending in the Sout hern District of New York. Trial in federal courtin Texas was continued pending a decision on the motions for summary judgment inthe New York case. In August 2007, the judge in the New York action issued a decision granting BOAsummary judgment and dismissing our claims. In December 2007, the judge heldthat BOA is entitled to recover damages of approximately $347 million ($427million including interest at December 31, 2007). In August 2008, the courtentered a final judgment of $346 million (the original judgment less $1 millionBOA would have incurred to remove 55 BCF of natural gas from the Bammel storagefacility) and clarified the interest calculation method. We appealed and posteda bond covering the amount of the judgment entered against us. The appeal wasbriefed during the first quarter of 2009. In 2005, we sold our interest in HPL. We indemnified the buyer of HPL againstany damages resulting from the BOA litigation up to the purchase price. Afterrecalculation for the final judgment, the liability for the BOA litigation was$433 million and $427 million including interest at December 31, 2008 and 2007,respectively. These liabilities are included in Deferred Credits and Other onour Consolidated Balance Sheets. Shareholder Lawsuits In 2002 and 2003, three putative class action lawsuits were filed in FederalDistrict Court, Columbus, Ohio against AEP, certain executives and AEP's ERISAPlan Administrator alleging violations of ERISA in the selection of AEP stock asan investment alternative and in the allocation of assets to AEP stock. Inthese actions, the plaintiffs sought recovery of an unstated amount ofcompensatory damages, attorney fees and costs. Two of the three actions weredropped voluntarily by the plaintiffs in those cases. In July 2006, the courtentered judgment in the remaining case, denying plaintiff's motion for classcertification and dismissing all claims without prejudice. In August 2007, theappeals court reversed the trial court's decision and held that the plaintiffdid have standing to pursue his claim. The appeals court remanded the case tothe trial court to consider the issue of whether the plaintiff is an adequaterepresentative for the class of plan participants. In September 2008, the trialcourt denied the plain tiff's motion for class certification and ordered briefingon whether the plaintiff may maintain an ERISA claim on behalf of the Plan inthe absence of class certification. In October 2008, counsel for the plaintifffiled a motion to intervene on behalf of an individual seeking to intervene as anew plaintiff. We opposed this motion and will continue to defend against theseclaims. Natural Gas Markets Lawsuits In 2002, the Lieutenant Governor of California filed a lawsuit in Los AngelesCounty California Superior Court against numerous energy companies, includingAEP, alleging violations of California law through alleged fraudulent reportingof false natural gas price and volume information with an intent to affect themarket price of natural gas and electricity. AEP was dismissed from the case.A number of similar cases were also filed in California and in state and federalcourts in several states making essentially the same allegations under federalor state laws against the same companies. AEP (or a subsidiary) is among thecompanies named as defendants in some of these cases. These cases are atvarious pre-trial stages. In June 2008, we settled all of the cases pendingagainst us in California. The settlements did not impact 2008 earnings due toprovisions made in prior periods. We will continue to defend each remainingcase where an AEP company is a defendant. We believe the provision we have forthe remaining cas es is adequate.Rail Transportation Litigation In October 2008, the Oklahoma Municipal Power Authority and the Public UtilitiesBoard of the City of Brownsville, Texas, as co-owners of Oklaunion Plant, fileda lawsuit in United States District Court, Western District of Oklahoma againstAEP alleging breach of contract and breach of fiduciary duties related tonegotiations for rail transportation services for the plant. The plaintiffsallege that AEP assumed the duties of the project manager, PSO, and operated theplant for the project manager and is therefore responsible for the allegedbreaches. In December 2008, the court denied our motion to dismiss the case.We intend to vigorously defend against these allegations. We believe aprovision recorded in 2008 should be sufficient. FERC Long-term Contracts In 2002, the FERC held a hearing related to a complaint filed by Nevada PowerCompany and Sierra Pacific Power Company (the Nevada utilities). The complaintsought to break long-term contracts entered during the 2000 and 2001 Californiaenergy price spike which the customers alleged were "high-priced." Thecomplaint alleged that we sold power at unjust and unreasonable prices becausethe market for power was allegedly dysfunctional at the time such contracts wereexecuted. In 2003, the FERC rejected the complaint. In 2006, the U.S. Court ofAppeals for the Ninth Circuit reversed the FERC order and remanded the case tothe 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 ofcontractually-agreed rates except in cases of serious harm to the public. TheU.S. Supreme Court affirmed the Ninth Circuit's remand on two issues, marketmanipulation and excessive burden on consumers. The FERC initiated remandprocedures and gave the parties time to attempt to settle the issues. Webelieve a provision recorded in 2008 should be sufficient. We have assertedclaims against certain companies that sold power to us, which we resold to theNevada utilities, seeking to recover a portion of any amounts we may owe to theNevada utilities. Management is unable to predict the outcome of theseproceedings or their ultimate impact on future net income and cash flows. 161000000 42000000 0 0 0 1000000 10693000000 10079000000 9412000000 9088000000 2771000000 2743000000 2718000000 2699000000 4527000000 4352000000 4221000000 4131000000 3847000000 3138000000 2696000000 2285000000 -452000000 -154000000 -223000000 -27000000 660000000 630000000 591000000 3000000 6000000 3000000 83000000 51000000 114000000 -255000000 0 209000000 4527000000 4352000000 20249992 21499992 170000000 188000000 1285000000 1008000000 3783000000 2199000000 256000000 271000000 2008-12-31 BUSINESS SEGMENTS Our primary business is our electric utility operations. Within our UtilityOperations segment, we centrally dispatch all generation assets and manage ouroverall utility operations on an integrated basis because of the substantialimpact of cost-based rates and regulatory oversight. While our UtilityOperations segment remains our primary business segment, other segments includeour AEP River Operations segment with significant barging activities and ourGeneration and Marketing segment, which includes our nonregulated generating,marketing and risk management activities primarily in the ERCOT market area.Intersegment sales and transfers are generally based on underlying contractualarrangements and agreements. Our reportable segments and their related business activities are as follows: Utility Operations - - Generation of electricity for sale to U.S. retail and wholesale customers.- Electricity transmission and distribution in the U.S. AEP River Operations - - Commercial barging operations that annually transport approximately 33million tons of coal and dry bulk commodities primarily on the Ohio, Illinoisand lower Mississippi Rivers. Approximately 38% of the barging is fortransportation of agricultural products, 30% for coal, 13% for steel and 19% forother commodities. Effective July 30, 2008, AEP MEMCO LLC's name was changed toAEP River Operations LLC. Generation and Marketing - - Wind farms and marketing and risk management activities primarily inERCOT. Our 50% interest in Sweeny Cogeneration Plant was sold in October 2007.See "Sweeny Cogeneration Plant" section of Note 7. The remainder of our company's activities is presented as All Other. While notconsidered a business segment, All Other includes: - - Parent's guarantee revenue received from affiliates, investment income,interest income and interest expense, and other nonallocated costs.- Tax and interest expense adjustments related to our UK operations whichwere sold in 2004 and 2002.- Forward natural gas contracts that were not sold with our natural gaspipeline and storage operations in 2004 and 2005. These contracts are financialderivatives 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 CogenerationFacility" section of Note 7.- The 2008 cash settlement of a purchase power and sale agreement with TEMrelated to the Plaquemine Cogeneration Facility which was sold in 2006. Thecash settlement of $255 million ($164 million, net of tax) is included in NetIncome.- Revenue sharing related to the Plaquemine Cogeneration Facility. The tables below present our reportable segment information for the years endedDecember 31, 2008, 2007 and 2006 and balance sheet information as of December31, 2008 and 2007. These amounts include certain estimates and allocationswhere necessary. We reclassified prior year amounts to conform to the currentyear's segment presentation. See "FSP FIN 39-1 "Amendment of FASBInterpretation No. 39" (FSP FIN 39-1)" section of Note 2 for discussion ofchanges in netting certain balance sheet amounts. Nonutility Operations Utility Operations AEP RiverOperations GenerationandMarketing All Other (a) Reconciling Adjustments Consolidated (in millions)Year Ended December 31, 2008Revenues from:External Customers $ 13,326 (e) $ 616 $485 $ 13 $ - $ 14,440 Other Operating Segments 240 (e) 30(122) 9 (157) -Total Revenues $ 13,566 $ 646 $ 363$ 22 $ (157) $ 14,440 Depreciation and Amortization $ 1,450 $ 14 $28 $ 2 $ (11) (b) $ 1,483 Interest Income 42 - 178 (65) 56Interest Expense 916 5 2294 (79) (b) 958Income Tax Expense 515 26 1784 - 642 Income Before Discontinued Operations and Extraordinary Loss $1,115 $ 55 $ 65 $ 133 $ -$ 1,368Discontinued Operations, Net of Tax - -- 12 - 12Net Income $ 1,115 $ 55 $ 65 $145 $ $ 1,380 Gross Property Additions $ 3,871 $ 116 $2 $ (29) (c) $ - $ 3,960 Nonutility Operations Utility Operations AEP RiverOperations GenerationandMarketing All Other (a) Reconciling Adjustments Consolidated (in millions)Year Ended December 31, 2007Revenues from:External Customers $ 12,101 (e) $ 523 $708 $ 48 $ - $ 13,380 Other Operating Segments 554 (e) 14(406) (13) (149) - Total Revenues $ 12,655 $ 537 $ 302$ 35 $ (149) $ 13,380 Depreciation and Amortization $ 1,483 $ 11 $29 $ 2 $ (12) (b) $ 1,513 Interest Income 21 - 381 (70) 35Interest Expense 787 5 28108 (87) (b) 841Income Tax Expense (Credit) 486 35 5(10) - 516 Income (Loss) Before Discontinued Operations and Extraordinary Loss $1,031 $ 61 $ 67 $ (15) $ -$ 1,144Discontinued Operations, Net of Tax - -- 24 - 24Extraordinary Loss, Net of Tax (79) -- - - (79)Net Income $ 952 $ 61 $ 67 $9 $ - $ 1,089 Gross Property Additions $ 4,050 $ 12 $ 2$ 4 (c) $ - $ 4,068 Nonutility Operations Utility Operations AEP RiverOperations GenerationandMarketing All Other (a) Reconciling Adjustments Consolidated (in millions)Year Ended December 31, 2006Revenues from:External Customers $ 12,066 $ 520 $ 62$ (26) $ - $ 12,622Other Operating Segments (55) 12 -97 (54) -Total Revenues $ 12,011 $ 532 $ 62$ 71 $ (54) $ 12,622 Depreciation and Amortization $ 1,435 $ 11 $17 $ 4 $ - $ 1,467Interest Income 36 - 291 (68) 61Interest Expense 667 4 11118 (68) 732Income Tax Expense (Credit) 543 42 (19) (81) - 485 Income (Loss) Before Discontinued Operations and Extraordinary Loss $1,028 $ 80 $ 12 $ (128) $ -$ 992Discontinued Operations, Net of Tax - -- 10 - 10Net Income (Loss) $ 1,028 $ 80 $ 12$ (118) $ - $ 1,002 Gross Property Additions $ 3,494 $ 7 $ 1$ 26 (c) $ - $ 3,528 Nonutility Operations Utility Operations AEP RiverOperations GenerationandMarketing All Other (a) Reconciling Adjustments (b) Consolidated (in millions)December 31, 2008 Total Property, Plant and Equipment $ 48,997 $ 371$ 565 $ 10 $ (233) $ 49,710Accumulated Depreciation and Amortization 16,525 73140 8 (23) 16,723Total Property, Plant and Equipment - Net $ 32,472 $298 $ 425 $ 2 $ (210) $32,987 Total Assets $ 43,773 $ 439 $ 737$ 14,501 $ (14,295) (d) $ 45,155 Investments in Equity Method Subsidiaries 22 2- - - 24 Nonutility Operations Utility Operations AEP RiverOperations GenerationandMarketing All Other (a) Reconciling Adjustments (b) Consolidated (in millions)December 31, 2007 Total Property, Plant and Equipment $ 45,514 $ 263$ 567 $ 38 $ (237) $ 46,145Accumulated Depreciation and Amortization 16,107 61112 7 (12) 16,275Total Property, Plant and Equipment - Net $ 29,407 $202 $ 455 $ 31 $ (225) $29,870 Total Assets $ 39,298 $ 340 $ 697$ 12,117 $ (12,133) (d) $ 40,319 Investments in Equity Method Subsidiaries 14 2- - - 16 (a) All Other includes: - Parent's guarantee revenue received from affiliates, investmentincome, interest income and interest expense, and other nonallocated costs. - Tax and interest expense adjustments related to our UK operationswhich were sold in 2004 and 2002. - Forward natural gas contracts that were not sold with our natural gaspipeline and storage operations in 2004 and 2005. These contracts are financialderivatives which will gradually settle and completely expire in 2011. - Other energy supply related businesses, including the PlaquemineCogeneration Facility, which was sold in 2006. See "Plaquemine CogenerationFacility" section of Note 7. - The 2008 cash settlement of a purchase power and sale agreement withTEM related to the Plaquemine Cogeneration Facility which was sold in 2006. Thecash settlement of $255 million ($164 million, net of tax) is included in NetIncome. - Revenue sharing related to the Plaquemine Cogeneration Facility.(b) Includes eliminations due to a n intercompany capital lease which beganin the first quarter of 2007.(c) Gross Property Additions for All Other includes construction expenditures of $8 million, $4 million and $25 million in 2008, 2007 and 2006,respectively, related to the acquisition of turbines by one of our nonregulated,wholly-owned subsidiaries. These turbines were refurbished and transferred to agenerating facility within our Utility Operations segment in the fourth quarterof 2008. The transfer of these turbines resulted in the elimination of $37million from All Other and the addition of $37 million to Utility Operations.(d) Reconciling Adjustments for Total Assets primarily include theelimination of intercompany advances to affiliates and intercompany accountsreceivable along with the elimination of AEP's investments in subsidiarycompanies.(e) PSO and SWEPCo transferred certain existing ERCOT energy marketingcontracts to AEP Energy Partners, Inc. (AEPEP) (Generation and Marketingsegment) and entered into intercompany financial and physical purchase and salesagreements with AEPEP. As a result, we reported third-party net purchases orsales activity for thes e energy marketing contracts as Revenues from ExternalCustomers for the Utility Operations segment. This is offset by the UtilityOperations segment's related net sales (purchases) for these contracts to AEPEPin Revenues from Other Operating Segments of $122 million and $406 million forthe years ended December 31, 2008 and 2007, respectively. The Generation andMarketing segment also reports these purchases or sales contracts with UtilityOperations as Revenues from Other Operating Segments. ACQUISITIONS and DISPOSITIONS ACQUISITIONS 2008 Erlbacher companies (AEP River Operations segment) In June 2008, AEP River Operations purchased certain barging assets fromMissouri Barge Line Company, Missouri Dry Dock and Repair Company and CapeGirardeau Fleeting, Inc. (collectively known as Erlbacher companies) for $35million. These assets were incorporated into AEP River Operations' businesswhich will diversify its customer base. 2007 Darby Electric Generating Station (Utility Operations segment) In November 2006, CSPCo agreed to purchase Darby Electric Generating Station(Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and LightCompany, for $102 million and the assumption of liabilities of $2 million.CSPCo completed the purchase in April 2007. The Darby Plant is located nearMount Sterling, Ohio and is a natural gas, simple cycle power plant with agenerating capacity of 480 MW. Lawrenceburg Generating Station (Utility Operations segment) In January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station(Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG) for$325 million and the assumption of liabilities of $3 million. AEGCo completedthe purchase in May 2007. Lawrenceburg is located in Lawrenceburg, Indiana,adjacent to I&M's Tanners Creek Plant, and is a natural gas, combined cyclepower plant with a generating capacity of 1,096 MW. AEGCo sells the power toCSPCo through a FERC-approved unit power agreement. Dresden Plant (Utility Operations segment) In August 2007, AEGCo agreed to purchase the partially completed Dresden Plant from Dominion Resources, Inc. for $85 million and the assumption of liabilitiesof $2 million. AEGCo completed the purchase in September 2007. AEGCo incurredapproximately $78 million and $3 million in construction costs (excluding AFUDC)at the Dresden Plant in 2008 and 2007, respectively, and expects to incurapproximately $142 million in additional costs (excluding AFUDC) prior tocompletion in 2013. The Dresden Plant is located near Dresden, Ohio and is anatural gas, combined cycle power plant. When completed, the Dresden Plant willhave a generating capacity of 580 MW. 2006 None DISPOSITIONS 2009 Electric Transmission Texas LLC (ETT) (Utility Operations segment) In January 2009, TCC sold $60 million of transmission facilities to ETT. Seethe 2007 activity for ETT below. 2008 None 2007 Electric Transmission Texas LLC (ETT) (Utility Operations segment) In December 2007, TCC contributed $70 million of transmission facilities to ETT,a newly-formed affiliated entity which will own and operate transmission facilities in ERCOT. Through a series of transactions, we then sold, at netbook value, a 50% equity ownership interest in ETT to a subsidiary ofMidAmerican Energy Holdings Company. Texas Plants - Oklaunion Power Station (Utility Operations segment) In February 2007, TCC sold its 7.81% share of Oklaunion Power Station to thePublic Utilities Board of the City of Brownsville for $43 million plus capitaladjustments. The sale did not impact net income. Intercontinental Exchange, Inc. (ICE) (All Other) In November 2000, we made our initial investment in ICE. An initial public offering (IPO) occurred on November 15, 2005. During 2006, we soldapproximately 600,000 shares and recognized a $39 million pretax gain ($25million, net of tax). In March 2007, we sold 130,000 shares of ICE andrecognized a $16 million pretax gain ($10 million, net of tax). We recorded thegains in Interest and Investment Income on our Consolidated Statements of Incomefor the year ended December 31, 2007. Our remaining investment of approximately138,000 shares as of December 31, 2008 and 2007 is recorded in Other TemporaryInvestments on our Consolidated Balance Sheets. Texas REPs (Utility Operations segment) As part of the purchase power and sale agreement related to the sale of ourTexas REPs in 2002, we retained the right to share in earnings with Centricafrom the two REPs above a threshold amount through 2006 if the Texas retailmarket developed increased earnings opportunities. In 2007, we received thefinal earnings sharing payment of $20 million. We received $70 million in 2006for our share of earnings. The payments are reflected in Gain on Disposition ofAssets, Net on our Consolidated Statement of Income. Sweeny Cogeneration Plant (Generation and Marketing segment) In October 2007, we sold our 50% equity interest in Sweeny to ConocoPhillips forapproximately $80 million, including working capital and the buyer's assumptionof project debt. The Sweeny Cogeneration Plant is a 480 MW cogeneration plantlocated within ConocoPhillips' Sweeny refinery complex southwest of Houston,Texas. We were the managing partner of the plant, which is co-owned by GeneralElectric Company. As a result of the sale, we recognized a $47 million pretaxgain ($30 million, net of tax) in 2007, which is reflected in Gain onDisposition of Equity Investments, Net on our 2007 Consolidated Statement ofIncome. In addition to the sale of our interest in Sweeny, we agreed to separately sellour purchase power contract for our share of power generated by Sweeny through2014 for $11 million to ConocoPhillips. ConocoPhillips also agreed to assumecertain related third-party power obligations. These transactions werecompleted in conjunction with the sale of our 50% equity interest in October2007. As a result of this sale, we recognized an $11 million pretax gain ($7million, net of tax) in 2007, which is included in Other revenues on our 2007Consolidated Statement of Income. In 2007, we recognized a total of $58 millionin pretax gains on the Sweeny transactions ($37 million, net of tax). 2006 Compresion Bajio S de R.L. de C.V. (All Other) In January 2002, we acquired a 50% interest in Compresion Bajio S de R.L. deC.V. (Bajio), a 600 MW power plant in Mexico. We received an indicative offerfor Bajio in September 2005, which resulted in a pretax other-than-temporary impairment charge of approximately $7 million in 2005. We completed the sale inFebruary 2006 for approximately $29 million with no effect on our 2006 netincome. Plaquemine Cogeneration Facility (All Other) In August 2006, we reached an agreement to sell our Plaquemine Cogeneration Facility (the Facility) to Dow Chemical Company (Dow) for $64 million. Werecorded a pretax impairment of $209 million ($136 million, net of tax) in 2006based on the terms of the agreement to sell the Facility to Dow. We recordedthe impairment in Asset Impairments and Other Related Charges on our 2006Consolidated Statement of Income. The Facility does not meet the criteria fordiscontinued operations reporting. We completed the sale in 2006. Excluding the 2006 impairment of $209 milliondiscussed above, the effect of the sale on our 2006 net income was notsignificant. In addition to the cash proceeds, the sale agreement allows us toparticipate in gross margin sharing on the Facility for five years. Under thisagreement, we recorded gross margin sharing of $13 million and $10 millionduring 2008 and 2007, respectively. These margins were recorded in Gain onDisposition of Assets, Net on our 2008 and 2007 Consolidated Statements ofIncome. As a result of the sale, Dow reduced an existing below-current-market long-term power supply contract with us in Texas by 50 MW and we retained theright to any judgment paid by TEM for breaching the original Power Purchase andSale Agreement (PPA). In 2003, we filed that TEM breached the PPA. In January2008, we reached a settlement with TEM to resolve all litigation regarding thePPA. TEM paid us $255 million and we recorded the amount as a pretax gain underAsset Impairments and Other Related Charges on our Consolidated Statements ofIncome in 2008. See "TEM Litigation" section of Note 6. Intercontinental Exchange, Inc. (ICE) (All Other) See the above 2007 disclosure "Intercontinental Exchange, Inc. (ICE)" for information regarding sales in 2006. Yes 406071256 3800000000 3556000000 3528000000 3.39 2.86 2.50 11653000000 11061000000 10656000000 32987000000 29870000000 327000000 365000000 LEASES Leases of property, plant and equipment are for periods up to 60 years andrequire payments of related property taxes, maintenance and operating costs.The majority of the leases have purchase or renewal options and will be renewedor replaced by other leases. Lease rentals for both operating and capital leases are generally charged toOther Operation and Maintenance expense in accordance with rate-making treatmentfor regulated operations. Capital leases for nonregulated property areaccounted for as if the assets were owned and financed. The components ofrental costs are as follows: Years Ended December 31, 2008 2007 2006Lease Rental Costs (in millions)Net Lease Expense on Operating Leases $ 368 $ 364$ 340Amortization of Capital Leases 97 6864Interest on Capital Leases 16 20 17Total Lease Rental Costs $ 481 $ 452 $421 The following table shows the property, plant and equipment under capital leasesand related obligations recorded on our Consolidated Balance Sheets. Capitallease obligations are included in Current Liabilities - Other and NoncurrentLiabilities - Deferred Credits and Other on our Consolidated Balance Sheets. December 31, 2008 2007 (in millions)Property, Plant and Equipment Under Capital LeasesProduction $ 70 $ 89Distribution 15 15Other 443 458Construction Work in Progress - 39 Total Property, Plant and Equipment Under Capital Leases 528601Accumulated Amortization 205 232 Net Property, Plant and Equipment Under Capital Leases $ 323$ 369 Obligations Under Capital Leases Noncurrent Liability $ 226 $ 267Liability Due Within One Year 99 104Total Obligations Under Capital Leases $ 325 $ 371 Future minimum lease payments consisted of the following at December 31, 2008: Capital Leases Noncancelable Operating Leases Future Minimum Lease Payments (in millions)2009 $ 94 $ 3362010 67 3102011 52 4612012 26 2222013 20 215Later Years 149 1,671Total Future Minimum Lease Payments $ 408 $ 3,215Less Estimated Interest Element 83Estimated Present Value of Future Minimum Lease Payments $ 325 Master Lease Agreements We lease certain equipment under master lease agreements. GE Capital CommercialInc. (GE) notified us in November 2008 that they elected to terminate our MasterLeasing Agreements in accordance with the termination rights specified withinthe contract. In 2010 and 2011, we will be required to purchase all equipmentunder the lease and pay GE an amount equal to the unamortized value of allequipment then leased. As a result, the unamortized value of this equipment isreflected in our future minimum lease payments for 2010 ($298 thousand) and 2011($195 million). In December 2008, we signed new master lease agreements withone-year commitment periods that include lease terms of up to 10 years. Weexpect to enter into additional replacement leasing arrangements for theequipment affected by this notification prior to the termination dates of 2010and 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 theequipment at the end of the lease term. If the fair market value of the leasedequipment is below the unamortized balance at the end of the lease term, we arecommitted to pay the difference between the fair market value and theunamortized balance, with the total guarantee not to exceed 87% of theunamortized balance. Under the new master lease agreements, the lessor isguaranteed receipt of up to 68% of the unamortized balance at the end of thelease term. If the actual fair market value of the leased equipment is belowthe unamortized balance at the end of the lease term, we are committed to paythe difference between the actual fair market value and unamortized balance,with the total guarantee not to exceed 68% of the unamortized balance. AtDecember 31, 2008, the maximum potential loss for these lease agreements wasapproximately $20 million assuming the f air market value of the equipment iszero at the end of the lease term. Historically, at the end of the lease termthe fair market value has been in excess of the unamortized balance. Rockport Lease AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 withWilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trusteefor Rockport Plant Unit 2 (the Plant). The Owner Trustee was capitalized withequity from six owner participants with no relationship to AEP or any of itssubsidiaries and debt from a syndicate of banks and securities in a privateplacement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of thelease, which expires in 2022. The Owner Trustee owns the Plant and leases it toAEGCo and I&M. The lease is accounted for as an operating lease with thepayment obligations included in the future minimum lease payments scheduleearlier in this note. The lease term is for 33 years with potential renewaloptions. At the end of the lease term, AEGCo and I&M have the option to renewthe lease or the Owner Trustee can sell the Plant. Neither AEGCo, I&M nor AEPhas an ownership interest in the Owner Trustee and do not guarantee its debt.The future minimum lease payments for this sale-and-leaseback transaction as ofDecember 31, 2008 are as follows: AEGCo I&MFuture Minimum Lease Payments (in millions)2009 $ 74 $ 742010 74 742011 74 742012 74 742013 74 74Later Ye ars 665 665Total 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 875coal-transporting aluminum railcars. The lease is accounted for as an operatinglease. In January 2008, AEP Transportation assigned the remaining 848 railcarsunder the original lease agreement to I&M (390 railcars) and SWEPCo (458railcars). The assignment is accounted for as new operating leases for I&M andSWEPCo. The initial lease term was five years with three consecutive five-yearrenewal periods for a maximum lease term of twenty years. I&M and SWEPCo intendto renew these leases for the full lease term of twenty years, via the renewaloptions. The future minimum lease obligations are $20 million for I&M and $23million for SWEPCo for the remaining railcars as of December 31, 2008. Theseobligations are included in the future minimum lease payments schedule earlierin this note. Under the lease agreement, the lessor is guaranteed that the sale proceeds undera return-and-sale option will equal at least a lessee obligation amountspecified in the lease, which declines from approximately 84% under the currentfive year lease term to 77% at the end of the 20-year term of the projected fairmarket value of the equipment. I&M and SWEPCo have assumed the guarantee underthe return-and-sale option. I&M's maximum potential loss related to theguarantee is approximately $12 million ($8 million, net of tax) and SWEPCo's isapproximately $13 million ($9 million, net of tax) assuming the fair marketvalue of the equipment is zero at the end of the current five-year lease term.However, we believe that the fair market value would produce a sufficient salesprice to avoid any loss. We have other railcar lease arrangements that do not utilize this type offinancing structure. Sabine Dragline Lease In December 2006, Sabine Mining Company (Sabine), an entity consolidated underFIN 46R, entered into a capital lease agreement with a nonaffiliated company tofinance the purchase of a $53 million electric dragline for Sabine's miningoperations. In 2006, the initial capital outlay for the dragline was $26million. Sabine incurred an additional $14 million and $13 million oftransportation, assembly and upgrade costs in 2008 and 2007 respectively. Thedragline was completed in August 2008. For the years ended December 31, 2008and 2007, Sabine paid $1 million and $2 million, respectively, of interim rentprior to the completion in August 2008. Sabine began quarterly principal andinterest payments on the outstanding lease obligation in November 2008. Thecapital lease asset was included in Property, Plant and Equipment - Other andConstruction Work in Progress on our December 31, 2008 and 2007 ConsolidatedBalance Sheets, respectively. The short-term and long-term capital leaseobligations are included in Current Liabilities - Other and Noncurrent Liabilities - Deferred Credits and Other on our December 31, 2008 and 2007Consolidated Balance Sheets. The future payment obligations are included in ourfuture 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 withCiticorp Leasing, Inc. (CLI), an unrelated, unconsolidated, wholly-owned subsidiary of Citibank, N.A. to lease nuclear fuel for I&M's Cook Plant. InDecember 2007, I&M sold a portion of its unamortized nuclear fuel inventory toCLI at cost for $85 million. The lease has a variable rate based on one monthLIBOR 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 our future minimumlease payments schedule earlier in this note. The net capital lease asset isincluded in Property, Plant and Equipment - Other and the short-term andlong-term capital lease obligations are included in Current Liabilities - Otherand Noncurrent Liabilities - Deferred Credits and Other, respectively, on ourDecember 31, 2008 and 2007 Consolidated Balance Sheets. The future minimumlease payments for this sale-and-leaseback transaction as of December 31, 2008are as follows, based on estimated fuel burn: Future Minimum Lease Payments (in millions) 2009 $ 252010 182011 42012 72013 3Later Years -Total Future Minimum Lease Payments $ 57 -199000000 -98000000 15000000 -272000000 -117000000 182000000 3000000 486000000 76000000 76000000 16723000000 16275000000 634000000 436000000 --12-31 9611000000 8921000000 8606000000 71000000 -113000000 177000000 0 47000000 3000000 6.50 6.50 61000000 61000000 28104000000 25018000000 355000000 319000000 DERIVATIVES, HEDGING AND FAIR VALUE MEASUREMENTS----------------------------------------------------- DERIVATIVES AND HEDGING SFAS 133 requires recognition of all qualifying derivative instruments as eitherassets or liabilities in the statement of financial position at fair value. Thefair values of derivative instruments accounted for using MTM accounting orhedge accounting are based on exchange prices and broker quotes. If a quotedmarket price is not available, the estimate of fair value is based on the bestinformation available including valuation models that estimate future energyprices based on existing market and broker quotes and supply and demand marketdata and assumptions. The fair values determined are reduced by the appropriatevaluation adjustments for items such as discounting, liquidity and creditquality. Credit risk is the risk that the counterparty will fail to perform tothe contract or fail to pay amounts due. Liquidity risk represents the riskthat imperfections in the market will cause the price to be less than or morethan what the price should be based purely on supply and dema nd. Since energymarkets are imperfect and volatile, there are inherent risks related to theunderlying assumptions in models used to fair value risk management contracts.Unforeseen events can and will cause reasonable price curves to differ fromactual prices throughout a contract's term and at the time a contract settles.Therefore, there could be significant adverse or favorable effects on future netincome and cash flows if market prices are not consistent with our approach atestimating current market consensus for forward prices in the current period.This is particularly true for longer term contracts. Certain qualifying derivative instruments have been designated as normalpurchase or normal sale contracts, as provided in SFAS 133. Derivativecontracts that have been designated as normal purchases or normal sales underSFAS 133 are not subject to MTM accounting treatment and are recognized in theConsolidated Statements of Income on an accrual basis. Our accounting for the changes in the fair value of a derivative instrumentdepends on whether it qualifies for and has been designated as part of a hedgingrelationship and further, on the type of hedging relationship. Depending on theexposure, we designate a hedging instrument as a fair value hedge or a cash flowhedge. For fair value hedges (i.e. hedging the exposure to changes in the fairvalue of an asset, liability or an identified portion thereof that isattributable to a particular risk), we recognize the gain or loss on thederivative instrument as well as the offsetting loss or gain on the hedged itemassociated with the hedged risk in Net Income during the period of change. Forcash flow hedges (i.e. hedging the exposure to variability in expected futurecash flows that is attributable to a particular risk), we initially report theeffective portion of the gain or loss on the derivative instrument as acomponent of Accumulated Other Comprehensive Income (Loss) on our ConsolidatedBalance Sheets until the period the hedged item affects Net Income. Werecognize any hedge ineffectiveness in Net Income immediately during the periodof change, except in regulated jurisdictions where hedge ineffectiveness isrecorded as a regulatory asset (for losses) or a regulatory liability (forgains). For contracts that have not been designated as part of a hedging relationship,the accounting for changes in fair value depends on whether the derivativeinstrument is held for trading purposes. Unrealized and realized gains andlosses on derivative instruments held for trading purposes are included inRevenues on a net basis in the Consolidated Statements of Income. Unrealized andrealized gains and losses on derivative instruments not held for tradingpurposes are included in Revenues or Expenses on the Consolidated Statements ofIncome depending on the relevant facts and circumstances. However, unrealizedgains and losses in regulated jurisdictions for both trading and non-tradingderivative instruments are recorded as a regulatory asset (for losses) or aregulatory liability (for gains). FAIR VALUE HEDGING STRATEGIES At certain times, we enter into interest rate derivative transactions in orderto manage existing fixed interest rate risk exposure. These interest ratederivative transactions effectively modify our exposure to interest rate risk byconverting a portion of our fixed-rate debt to a floating rate. We record gainsor losses on swaps that qualify for fair value hedge accounting treatment, aswell as offsetting changes in the fair value of the debt being hedged, inInterest Expense on our Consolidated Statements of Income. During 2008, 2007and 2006, we recognized no hedge ineffectiveness related to these derivativetransactions. CASH FLOW HEDGING STRATEGIES We enter into, and designate as cash flow hedges, certain derivativetransactions for the purchase and sale of electricity, coal and natural gas(collectively "Power") in order to manage the variable price risk related to theforecasted purchase and sale of these commodities. We closely monitor thepotential impacts of commodity price changes and, where appropriate, enter intoderivative transactions to protect margins for a portion of future electricitysales and fuel or energy purchases. Realized gains and losses on thesederivatives designated as cash flow hedges are included in Revenues, Fuel andOther Consumables Used for Electric Generation or Purchased Electricity forResale on our Consolidated Statements of Income, depending on the specificnature of the risk being hedged. We do not hedge all variable price riskexposure related to energy commodities. During 2008, 2007 and 2006, werecognized immaterial amounts in Net Income related to hedge i neffectiveness. We enter into a variety of interest rate derivative transactions in order tomanage interest rate risk exposure. Some interest rate derivative transactionseffectively modify our exposure to interest rate risk by converting a portion ofour floating-rate debt to a fixed rate. We also enter into interest ratederivative contracts to manage interest rate exposure related to anticipatedborrowings of fixed-rate debt. Our anticipated fixed-rate debt offerings have ahigh probability of occurrence because the proceeds will be used to fundexisting debt maturities as well as fund projected capital expenditures. Wereclassify gains and losses on the hedges from Accumulated Other ComprehensiveIncome (Loss) into Interest Expense in those periods in which hedged interestpayments occur. During 2008, 2007 and 2006, we recognized immaterial amounts inNet Income related to hedge ineffectiveness. At times, we are exposed to foreign currency exchange rate risks primarilybecause we purchase certain fixed assets from foreign suppliers. In accordancewith our risk management policy, we may enter into foreign currency derivativetransactions to protect against the risk of increased cash outflows resultingfrom a foreign currency's appreciation against the dollar. The accumulatedgains or losses related to our foreign currency hedges are reclassified fromAccumulated Other Comprehensive Income (Loss) on our Consolidated Balance Sheetsinto Other Operation and Maintenance expense on our Consolidated Statements ofIncome over the depreciable lives of the fixed assets that were designated asthe hedged items in qualifying foreign currency hedging relationships. We donot hedge all foreign currency exposure. During 2008, 2007 and 2006, werecognized no hedge ineffectiveness related to these derivative transactions. Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) onour Consolidated Balance Sheet at dateMonth12Day31Year2008December 31, 2008were: ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) HEDGING ASSETS (A) HEDGING LIABILITIES (A) AFTER TAX ------------------ ----------------------- ---------PORTION EXPECTED TO BE RECLASSIFIED TO NET INCOME DURING THE NEXT TWELVE MONTHS------------------------------------------------------------------------------- (IN MILLIONS) ------------- Power $ 34 $ (23) $ 7 $ 7Interest Rate - (8) (29) (5)TOTAL $ 34 $ (31) $ (22) $ 2 (a) Hedging Assets and Hedging Liabilities are included in Risk ManagementAssets and Liabilities on our Consolidated Balance Sheet. Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) onour Consolidated Balance Sheet at dateMonth12Day31Year2007December 31, 2007were: ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) HEDGING ASSETS (A) HEDGING LIABILITIES (A) AFTER TAX ----------------------- ---------PORTION EXPECTED TO BE RECLASSIFIED TO NET INCOME DURING THE NEXT TWELVE MONTHS------------------------------------------------------------------------------- (IN MILLIONS) -------------Power $ 9 $ (10) $ (1) $ (2)Interest Rate - (3) (25) (3) TOTAL $ 9 $ (13) $ (26) $ (5) (a) Hedging Assets and Hedging Liabilities are included in Risk ManagementAssets and Liabilities on our Consolidated Balance Sheet. The actual amounts that we reclassify from Accumulated Other ComprehensiveIncome (Loss) to Net Income can differ due to market price changes. As ofdateMonth12Day31Year2008December 31, 2008, the maximum length of time that weare hedging (with SFAS 133 designated contracts) our exposure to variability infuture cash flows related to forecasted transactions is 47 months. The following table represents the activity in Accumulated Other ComprehensiveIncome (Loss) for derivative contracts that qualify as cash flow hedges atdateMonth12Day31Year2008December 31, 2008: AMOUNT (IN MILLIONS) ------------- BALANCE AT DATEMONTH12DAY31YEAR2005DECEMBER 31, 2005 $ (27) Changes in Fair Value 13 Reclasses from AOCI to Net Income 8 BALANCE AT DATEMONTH12DAY31YEAR2006DECEMBER 31, 2006 (6) --- Changes in Fair Value (5) Reclasses from AOCI to Net Income (15) BALANCE AT DATEMONTH12DAY31YEAR2007DECEMBER 31, 2007 (26) ---- Changes in Fair Value (3) Reclasses from AOCI to Net Income 7 BALANCE AT DATEMONTH12DAY31YEAR2008DECEMBER 31, 2008 $ (22) - ---- CREDIT RISK Credit risk is our risk of financial loss if counterparties fail to performtheir contractual obligations. We limit our credit risk by maintainingstringent credit policies whereby we assess a counterparty's creditworthinessprior to transacting with them and continue to assess their creditworthiness onan ongoing basis. We employ the use of standardized master agreements which mayinclude collateral requirements. These master agreements facilitate the nettingof cash flows associated with a single counterparty. Cash, letters of credit,and parental/affiliate guarantees may be obtained as security fromcounterparties in order to mitigate credit risk. The collateral agreementsrequire a counterparty to post cash or letters of credit in the event anexposure is exceeded in excess of an established threshold. The thresholdrepresents an unsecured credit limit which may be supported by aparental/affiliate guaranty, as determined in accordance with our credit pol icy.In addition, collateral agreements also provide that the failure or inability topost collateral is sufficient cause for termination and liquidation of allpositions. FAIR VALUE MEASUREMENTS SFAS 107 FAIR VALUE MEASUREMENTS The fair values of Long-term Debt are based on quoted market prices for the sameor similar issues and the current interest rates offered for instruments withsimilar maturities. These instruments are not marked-to-market. The estimatespresented are not necessarily indicative of the amounts that we could realize ina current market exchange. The book values and fair values of Long-term Debt atdateMonth12Day31Year2008December 31, 2008 and 2007 are summarized in thefollowing tables: DECEMBER 31, ============ 2008 2007 ---- BOOK VALUE FAIR VALUE BOOK VALUE FAIR ---------- VALUE (IN MILLIONS) ------------- Long-term Debt $ 15,983 $ 15,113 $ 14,994 $ 14,917 SFAS 157 FAIR VALUE MEASUREMENTS As described in Note 2, we completed our adoption of SFAS 157 effective dateMonth1Day1Year2009January 1, 2009. The statement defines fair value,establishes a fair value measurement framework and expands fair valuedisclosures. The adoption of SFAS 157 had an immaterial impact on our financialstatements. The provisions of SFAS 157 are applied prospectively, except for a)changes in fair value measurements of existing derivative financial instrumentsmeasured initially using the transaction price under EITF Issue No. 02-3 "IssuesInvolved in Accounting for Derivative Contracts Held for Trading Purposes andContracts Involved in Energy Trading and Risk Management Activities" (EITF02-3), b) existing hybrid financial instruments measured initially at fair valueusing the transaction price and c) blockage discount factors. Although thestatement is applied prospectively upon adoption, in accordance with theprovisions of SFAS 157 related to EITF 02-3, we recorded an immaterialtransition adjustment to beginning retained earnings. The impact of consideringour own credit risk when measuring the fair value of liabilities, includingderivatives, had an immaterial impact on fair value measurements upon adoption. In accordance with SFAS 157, assets and liabilities are classified based on theinputs utilized in the fair value measurement. SFAS 157 provides definitionsfor two types of inputs: observable and unobservable. Observable inputs arevaluation inputs that reflect the assumptions market participants would use inpricing the asset or liability developed based on market data obtained fromsources independent of the reporting entity. Unobservable inputs are valuationinputs that reflect the reporting entity's own assumptions about the assumptionsmarket participants would use in pricing the asset or liability developed basedon the best information in the circumstances. As defined in SFAS 157, fair value is the price that would be received to sellan asset or paid to transfer a liability in an orderly transaction betweenmarket participants at the measurement date (exit price). SFAS 157 establishes afair value hierarchy that prioritizes the inputs used to measure fair value. Thehierarchy gives the highest priority to unadjusted quoted prices in activemarkets for identical assets or liabilities (level 1 measurement) and the lowestpriority to unobservable inputs (level 3 measurement). Level 1 inputs are quoted prices (unadjusted) in active markets for identicalassets or liabilities that the reporting entity has the ability to access at themeasurement date. Level 1 inputs primarily consist of exchange tradedcontracts, listed equities and placecountry-regionU.S. government treasurysecurities that exhibit sufficient frequency and volume to provide pricinginformation on an ongoing basis. Level 2 inputs are inputs other than quoted prices included within level 1 thatare observable for the asset or liability, either directly or indirectly. Ifthe asset or liability has a specified (contractual) term, a level 2 input mustbe observable for substantially the full term of the asset or liability. Level2 inputs primarily consist of OTC broker quotes in moderately active or lessactive markets, exchange traded contracts where there was not sufficient marketactivity to warrant inclusion in level 1, OTC broker quotes that arecorroborated by the same or similar transactions that have occurred in themarket and certain non-exchange-traded debt securities. Level 3 inputs are unobservable inputs for the asset or liability. Unobservableinputs shall be used to measure fair value to the extent that the observableinputs are not available, thereby allowing for situations in which there islittle, if any, market activity for the asset or liability at the measurementdate. Level 3 inputs primarily consist of unobservable market data or arevalued based on models and/or assumptions. Risk Management Contracts include exchange traded, OTC and bilaterally executedderivative contracts. Exchange traded derivatives, namely futures contracts,are generally fair valued based on unadjusted quoted prices in active marketsand are classified within level 1. Other actively traded derivative fair valuesare verified using broker or dealer quotations, similar observable markettransactions in either the listed or OTC markets or valued using pricing modelswhere significant valuation inputs are directly or indirectly observable inactive markets. Derivative instruments, primarily swaps, forwards, and optionsthat meet these characteristics are classified within level 2. Bilaterallyexecuted agreements are derivative contracts entered into directly with thirdparties, and at times these instruments may be complex structured transactionsthat are tailored to meet the specific customer's energy requirements.Structured transactions utilize pricing models that are widely accepted in theenergy industry to measure fair value. We use a consistent modeling approach tovalue similar instruments. Valuation models utilize various inputs that includequoted prices for similar assets or liabilities in active markets, quoted pricesfor identical or similar assets or liabilities in markets that are not active,market corroborated inputs (i.e. inputs derived principally from, or correlatedto, observable market data) and other observable inputs for the asset orliability. Where observable inputs are available for substantially the fullterm of the asset or liability, the instrument is categorized in level 2.Certain OTC and bilaterally executed derivative instruments are executed in lessactive markets with a lower availability of pricing information. In addition,long-dated and illiquid complex or structured transactions or FTRs can introducethe need for internally developed modeling inputs based upon extrapolations andassumptions of observable market data to estim ate fair value. When such inputshave a significant impact on the measurement of fair value, the instrument iscategorized in level 3. In certain instances, the fair values of thetransactions included in level 3 that use internally developed model inputs areoffset partially or in full, by transactions included in level 2 whereobservable market data exists for the offsetting transaction. The following table sets forth by level within the fair value hierarchy ourfinancial assets and liabilities that were accounted for at fair value on arecurring basis as of December 31, 2008. As required by SFAS 157, financialassets and liabilities are classified in their entirety based on the lowestlevel of input that is significant to the fair value measurement. Our assessmentof the significance of a particular input to the fair value measurement requiresjudgment, and may affect the valuation of fair value assets and liabilities andtheir placement within the fair value hierarchy levels. ASSETS AND LIABILITIES MEASURED AT FAIR VALUE ON A RECURRING BASIS AS OF DATEMONTH12DAY31YEAR2008DECEMBER 31, 2008 LEVEL 1 LEVEL 2 LEVEL 3 OTHER TOTAL ASSETS: (IN MILLIONS) ------------- CASH AND CASH EQUIVALENTS Cash and Cash Equivalents (a) $ 304 $ - $ - ----------------------------- $ 60 $ 364 Debt Securities (b) - 47 - - 47 TOTAL CASH AND CASH EQUIVALENTS 304 47 - --- -- - 60 411 -- --- OTHER TEMPORARY INVESTMENTS Cash and Cash Equivalents (c) 217 - - ----------------------------- 26 243 Debt Securities (d) 56 - - - 56 Equity Securities (e) 28 - - - 28 TOTAL OTHER TEMPORARY INVESTMENTS 301 - - --- - - 26 327 -- --- RISK MANAGEMENT ASSETS Risk Management Contracts (f) 61 2,413 86 ----------------------------- (2,022) 538 Cash Flow and Fair Value Hedges (f) 6 32 - (4) 34Dedesignated Risk Management Contracts (g) - - - 39 39 TOTAL RISK MANAGEMENT ASSETS 67 2,445 86 -- ----- -- (1,987) 611 ------- --- SPENT NUCLEAR FUEL AND DECOMMISSIONING TRUSTS Cash and Cash Equivalents (h) - 6 - ----------------------------- 12 18Debt Securities (i) - 773 - - 773Equity Securities (e) 469 - - - 469 TOTAL SPENT NUCLEAR FUEL AND DECOMMISSIONING TRUSTS 469 --- 779 - 12 1,260 --- - -- ----- TOTAL ASSETS $ 1,141 $ 3,271 $ 86 $ (1,889) $ 2,609 LIABILITIES: RISK MANAGEMENT LIABILITIES Risk Management Contracts (f) $ 77 $ 2,213 $ ----------------------------- 37 $ (2,054) $ 273 Cash Flow and Fair Value Hedges (f) 1 34 - (4) 31TOTAL RISK MANAGEMENT LIABILITIES $ 78 $ 2,247 $ - -- - ----- - 37 $ (2,058) $ 304 -- - ------- - --- (a) Amounts in "Other" column primarily represent cash deposits in bank ======================================================================== accounts with financial institutions. Level 1 amounts primarily represent================================================================================ investments in money market funds.======================================(b) Amount represents commercial paper investments with maturities of lessthan ninety days.(c) Amounts in "Other" column primarily represent cash deposits with thirdparties. Level 1 amounts primarily represent investments in money market funds.(d) Amounts represent debt-based mutual funds.(e) Amount represents publicly traded equity securities and equity-basedmutual funds.(f) Amounts in "Other" column primarily represent counterparty netting ofrisk management contracts and associated cash collateral under FSP FIN 39-1.(g) "Dedesignated Risk Management Contracts" are contracts that wereoriginally MTM but were subsequently elected as normal under SFAS 133. At thetime of the normal election, the MTM value was frozen and no longer fair valued.This will be amortized into Utility Operations Revenues over the remaining lifeof the contract.(h) Amounts in "Other" column prima rily represent accrued interestreceivables from financial institutions. Level 2 amounts primarily representinvestments in money market funds.(i) Amounts represent corporate, municipal and treasury bonds. The following table sets forth a reconciliation of changes in the fair value ofnet trading derivatives and other investments classified as level 3 in the fairvalue hierarchy: YEAR ENDED DATEMONTH12DAY31YEAR2008DECEMBER 31, 2008 NET RISK -------- MANAGEMENT ASSETS (LIABILITIES) OTHER TEMPORARY INVESTMENTS ------------------------------- --------------------------- INVESTMENTS IN DEBT SECURITIES ------------------------------ (IN MILLIONS) -------------BALANCE AS OF DATEMONTH1DAY1YEAR2008JANUARY 1, 2008 $ 49 $ - $ -Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) - - -Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)Relating to Assets Still Held at the Reporting Date (a) 12 - -Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income - - - Purchases, Issuances and Settlements (b) - (118) (17)Transfers in and/or out of Level 3 (c) (36) 118 17 Changes in Fair Value Allocated to Regulated Jurisdictions (d) 24 - -BALANCE AS OF DATEMONTH12DAY31YEAR2008DECEMBER 31, 2008 $ 49 - -- $ - $ - - - - - (a) Included in revenues on our Consolidated Statements of Income.(b) Includes principal amount of securities settled during the period.(c) "Transfers in and/or out of Level 3" represent existing assets orliabilities that were either previously categorized as a higher level for whichthe inputs to the model became unobservable or assets and liabilities that werepreviously classified as level 3 for which the lowest significant input becameobservable during the period.(d) "Changes in Fair Value Allocated to Regulated Jurisdictions" relates tothe net gains (losses) of those contracts that are not reflected on theConsolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities. 3. GOODWILL AND OTHER INTANGIBLE ASSETS Goodwill The changes in our carrying amount of goodwill for the years ended December 31, 2008 and 2007 by operating segment are as follows: Utility Operations AEP RiverOperations AEPConsolidated (in millions)Balance at December 31, 2006 $ 37 $ 39 $ 76 Impairment Losses - - - Balance at December 31, 2007 37 39 76 Impairment Losses - - - Balance at December 31, 2008 $ 37 $ 39 $ 76 In the fourth quarters of 2008 and 2007, we performed our annual impairment tests. The fair values of the operations with goodwill were estimated using cash flow projections and other market value indicators. There were no goodwill impairment losses. Other Intangible Assets Acquired intangible assets subject to amortization were $12.8 million and $15.2 million at December 31, 2008 and 2007, respectively, net of accumulated amortization and are included in Deferred Charges and Other on our Consolidated Balance Sheets. The amortization life, gross carrying amount and accumulated amortization by major asset class are as follows: December 31, 2008 2007 Amortization Life Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (in years) (in millions)Patent 5 $ - $ - $ 0.1 $ 0.1 Easements 10 2.2 1.6 2.2 1.4 Purchased Technology 10 10.9 7.5 10.9 6.4 Advanced Royalties 15 29.4 20.6 29.4 19.5 Total $ 42.5 $ 29.7 $ 42.6 $ 27.4 Amortization of intangible assets was $3 million, $4 million and $5 million for 2008, 2007 and 2006, respectively. Our estimated total amortization is $3 million per year for 2009 through 2010, $2 million for 2011 and $1 million per year for 2012 through 2016, when all assets 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, we 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 included in the table above and factored in the estimates noted above for future periods. Other than goodwill, we have no intangible assets that are not subject to amortization. 7000000 0 0 28000000 25000000 19000000 131000000 119000000 80000000 159000000 144000000 99000000 -3000000 -3000000 -3000000 1316000000 642000000 7000000 5000000 14000000 0 82000000 -15000000 -3000000 1368000000 1144000000 992000000 4000000 3000000 3000000 45155000000 40319000000 -452000000 -154000000 2040000000 2108000000 16336246629 American Electric Power Company, Inc. -10000000 0 0 -10000000 0 0 1082000000 1158000000 1024000000 1824000000 1286000000 1946000000 1.64 1.58 1.50 403640708 400198799 396483464 0 -0.20 0 0.03 0.06 0.02 4474000000 3829000000 3817000000 5128000000 4730000000 3741000000 3445000000 569000000 730000000 EX-100.SCH 3 aep-20081231.xsd XBRL TAXONOMY EXTENSION SCHEMA Notes to Financial Statements link:presentationLink EX-100.CAL 4 aep-20081231_cal.xml XBRL TAXONOMY EXTENSION CALCULATION LINKBASE EX-100.DEF 5 aep-20081231_def.xml XBRL TAXONOMY EXTENSION DEFINITION LINKBASE EX-100.LAB 6 aep-20081231_lab.xml XBRL TAXONOMY EXTENSION LABEL LINKBASE Total Accounts Receivable Accrued Taxes Accumulated Other Comprehensive Income (Loss) Accumulated Depreciation and Amortization Paid in Capital Deferred Property Taxes Amortization of Nuclear Fuel Deferred Investment Tax Credits Mark-to-Market of Risk Management Contracts Allowance for Uncollectible Accounts Allowance for Uncollectible Accounts Asset Impairments and Other Related Charges Asset Retirement Obligations Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents Cash and Cash Equivalents at End of Period Customer Deposits Fuel, Materials and Supplies Change in Short-term Debt, Net Accounts Payable Margin Deposits Commitments and Contingencies Common Stock Total Comprehensive Income Construction Work in Progress Fuel and Other Consumables Used for Electric Generation Purchased Electricity for Resale Customer Deposits Deferred Income Taxes Risk Management Assets Long-term Risk Management Assets Risk Management Assets Long-term Risk Management Assets Derivatives, Hedging and Fair Value Measurements Risk Management Liabilities Long-term Risk Management Liabilities Discontinued Operations Equity Earnings of Unconsolidated Subsidiaries Extraordinary Item Gain on Disposition of Assets, Net Gain on Disposition of Assets, Net Investment Value Losses Investment Value Losses Income Before Extraordinary Loss, Per Diluted Share Income Before Extraordinary Loss, Per Basic Share Income Before Discontinued Operations and Extraordinary Loss, Per Diluted Share Income Before Discontinued Operations and Extraordinary Loss, Per Basic Share Income Before Discontinued Operations and Extraordinary Loss Discontinued Operations, Net of Tax, Per Diluted Share Discontinued Operations, Net of Tax, Per Basic Share Less: Discontinued Operations, Net of Tax Discontinued Operations, Net of Tax Extraordinary Loss, Net of Tax, Per Diluted Share Extraordinary Loss, Net of Tax, Per Basic Share Income Taxes Other Current Assets Acquisitions of Nuclear Fuel Acquisitions of Nuclear Fuel Accrued Interest Fuel, Materials and Supplies Fuel Materials and Supplies Interest and Investment Income Long-term Debt Due Within One Year Long-term Debt Margin Deposits Minority Interest Expense Net Cash Flows Used for Investing Activities Net Cash Flows from Operating Activities Net Income Net Increase (Decrease) in Cash and Cash Equivalents New Accounting Pronouncements Operating Income Organization Securities Available for Sale, Net of Tax Pension and OPEB Funded Status, Net of Tax Cash Flow Hedges, Net of Tax Minimum Pension Liability, Net of Tax Minimum Pension Liability, Tax Amortization of Pension and OPEB Deferred Costs, Net of Tax Amortization of Pension and OPEB Deferred Costs, Tax Prepayments and Other Other Investing Activities Other Investing Activities Other Financing Activities Dividends Paid on Common Stock Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Pension Contributions to Qualified Plan Trusts Benefit Plans Preferred Stock Dividend Requirements of Subsidiaries Issuance of Common Stock Issuance of Long-term Debt Proceeds from Sale of Assets Rate Matters Property, Plant and Equipment, Other (including coal mining and nuclear fuel) Property, Plant and Equipment, Electric, Distribution Property, Plant and Equipment, Electric, Production Property, Plant and Equipment, Electric, Transmission Construction Expenditures Construction Expenditures Purchases of Investment Securities Purchases of Investment Securities Regulatory Asset for Under-Recovered Fuel Costs Regulatory Assets Principal Payments for Capital Lease Obligations Principal Payments for Capital Lease Obligations Retirement of Long-term Debt, Total Repurchase of Common Stock Repurchase of Common Stock Company-wide Staffing and Budget Review Retained Earnings Sales of Investment Securities Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 Other Guarantees Acquisitions and Dispositions Securitized Transition Assets Business Segments Short-term Debt Other Temporary Investments Summary of Significant Accounting Policies Goodwill and Other Intangible Assets Taxes Other Than Income Taxes Reissuance of Treasury Shares Weighted Average Number of Basic Shares Outstanding Property, Plant and Equipment Other Liabilities, Current Deferred Credits and Other Stock-Based Compensation Deferred Income Taxes Financial Instruments Cumulative Preferred Stock Not Subject to Mandatory Redemption Unaudited Quarterly Financial Information Net Cash Flows from Financing Activities SFAS 158 Adoption, Net of Tax Deferred Charges and Other Other Current Liabilities Income Before Income Tax Expense, Minority Interest Expense and Equity Earnings Common Stock, Par Value Per Share Foreign Currency Translation Adjustment, Tax Cash Flow Hedges, Tax Securities Available for Sale, Tax Cumulative Preferred Stock Not Subject to Mandatory Redemption Gain on Disposition of Equity Investments, Net Income Tax Expense Extraordinary Loss, Net of Tax Extraordinary Loss, Net of Tax Income Before Extraordinary Loss Cumulative Effect of Accounting Change, Net of Tax Cumulative Effect of Accounting Change, Net of Tax Cumulative Effect of Accounting Change, Net of Tax, Per Basic Share Cumulative Effect of Accounting Change, Net of Tax, Per Diluted Share Cash Dividends Paid Per Share Accounts Receivable, Net Noncash Construction Expenditures Included in Accounts Payable at December 31 Issuance of Common Stock, Value Issuance of Common Stock, Shares FIN 48 Adoption, Net of Tax Utility Operations Repurchase of Common Stock Commitments and Contingencies (Note 6) Other Operation and Maintenance The total amount of other operating expense items that are associated with the entity's normal revenue producing operation. Includes non-fuel expenses incurred in the operation and maintenance of generation facilities, operation and maintenance of transmission assets, operation and maintenance of distribution assets, rental of property used, occupied, or operated in connection with the production facilities, transmission assets or distribution assets, customer service activities, advertising, administrative activities and compensation of employees. Carrying Costs Income Income recorded to accrue a return on certain regulatory assets as granted by a regulator. Carrying Costs Income Allowance for Equity Funds Used During Construction Total increase in earnings in the period representing the cost of equity (rate of return) used to finance construction of regulated assets, which is expected to be recovered through rate adjustments. Interest Expense The aggregate interest expense incurred on long-term debt, commercial paper, deposits, and all other borrowings. Also includes the credits for allowance for borrowed funds used during construction and interest expense related to the over-recovery of fuel. Interest and Preferred Stock Dividend Requirements, Total The sum of Interest Expense and Preferred Stock Dividend Requirements Interest And Preferred Stock Dividend Requirements Accounts Receivable - Customers Amounts due from customers for billed utility services. Accounts Receivable - Accrued Unbilled Revenues Amounts due from customers based upon an estimate of sales of power to customers since the last customer billing. Accounts Receivable - Miscellaneous Miscellaneous receivables not included in A/R - Customers, A/R - Affiliated Companies or A/R - Accrued Unbilled Revenues Public Utilities, Property, Plant and Equipment Employee Benefits and Pension Assets Cumulative employer's contributions in excess of net pension cost recognized. Includes both assets relating to defined benefit plans for use under the recognition provisions of SFAS 158 and other benefit assets not subject to SFAS 158. Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities represent future revenue reductions or refunds to reflect the economic effect of regulation by matching income with its passage to customers through the reduction of regulated revenues. The deferred investment tax credits as of the balance sheet date represent the remaining investment credit, which will reduce the cost of services collected from ratepayers by a ratable portion over the investment's regulatory life. Employee Benefits and Pension Obligations Represents the noncurrent liability for underfunded plans recognized in the balance sheet. Includes both liabilities relating to benefit plans subject to SFAS 158 and other benefit obligations not subject to SFAS 158 such as postemployment benefits and performance share incentive plans. Income Before Discontinued Operations Revenue less expenses and taxes from the entity's ongoing operations and before income (loss) from discontinued operations. Asset Impairments, Investment Value Losses and Other Related Charges The charge against earnings resulting from the aggregate write down of all assets from their carrying value to their fair value. Also includes Investment Value Losses, which represents the amount by which the carrying amount exceeds the fair value of the investment. The amount is charged to income if the decline in fair value is deemed to be other than temporary. Allowance for Equity Funds Used During Construction Total increase in earnings in the period representing the cost of equity (rate of return) used to finance construction of regulated assets, which is expected to be recovered through rate adjustments. Fuel Over/Under-Recovery, Net The net change during the reporting period in the value of the asset (liability) created by an over (under) recovery of fuel costs. An over recovery represents the excess of fuel revenues billed to customers over fuel costs incurred and an under recovery represents excess fuel costs incurred over fuel revenues billed to customers. Gain on Sales of Assets and Equity Investments, Net Gain on Sales of Assets which includes the gains and losses included in earnings resulting from the sale or disposal of tangible assets. Also the Gain on Sales of Equity Investments includes the difference between the carrying value and the sale price of equity securities. Change in Noncurrent Liability for NSR Settlement The change in the noncurrent liability for the New Source Review (NSR) consent decree for civil penalties and environmental mitigation projects coordinated with the federal and state governments. Change in Other Noncurrent Assets The net change during the reporting period in other noncurrent operating assets not otherwise defined in the taxonomy. Change in Other Noncurrent Liabilities The net change during the reporting period in other noncurrent operating liabilities not otherwise defined in the taxonomy. Change in Other Temporary Investments, Net Change in investments which are intended to be sold in the short term (usually less than one year or the normal operating cycle, whichever is longer) including trading securities, available-for-sale securities, held-to-maturity securities, and other short-term investments not otherwise listed in the existing taxonomy. Acquisitions of Assets The cash outflow associated with the acquisition of long-lived, physical assets that are used in the normal conduct of business to produce goods and services and not intended for resale. Proceeds from Nuclear Fuel Sale/Leaseback The gross proceeds received from nuclear fuel sold in connection with the transaction involving the sale of nuclear fuel to another party and the lease of the nuclear fuel back to the seller. Supplemental Information Assumption (Disposition) of Liabilities Related to Acquisitions/Divestures, Net The net value of an asset or business acquired/divested in a noncash (or part noncash) acquisition/divestiture. Noncash is defined as information about all investing and financing activities of an enterprise during a period that affect recognized assets Noncash Acquisition of Nuclear Fuel in Accounts Payable at December 31 Future cash outflow to pay for nuclear fuel expenditures that have occurred. Disposition of Assets Related to Electric Transmission Texas Joint Venture Disposition of Assets Related to Electric Transmission Texas Joint Venture Spent Nuclear Fuel and Decommissioning Trusts Funds to pay for the disposal of spent nuclear fuel and the decontaminating and decommissioning of nuclear facilities through the collection of revenues from rate payers. SFAS 158 Adoption, Tax Accumulated change in equity from transactions and other events and circumstances from nonowner sources at fiscal year-end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, and unrealized gains and losses on certain investments in debt and equity securities as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge: Tax effect related to adjustment of ac cumulated other comprehensive income to reflect the application of SFAS 158 recognition provisions. It excludes the adjustment to other comprehensive income to eliminate additional minimum pension liability (AML), as well as related intangible assets. SFAS 158 Adoption Costs Established as a Regulatory Asset for the Reapplication of SFAS 71, Net of Tax SFAS 158 adoption costs established as a regulatory asset for the reapplication of SFAS 71 due to the re-regulation of certain operations. SFAS 158 Adoption Costs Established as a Regulatory Asset for the Reapplication of SFAS 71, Tax Tax effect of SFAS 158 adoption costs established as a regulatory asset for the reapplication of SFAS 71 due to the re-regulation of certain operations. Pension and OPEB Funded Status, Tax Accumulated change in equity from transactions and other events and circumstances from nonowner sources at fiscal year-end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, and unrealized gains and losses on certain investments in debt and equity securities as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge: Tax effect of changes to accumulated comprehensive income during the period related to benefit plans. Effects of Regulation Detailed information about regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) recorded on the Balance Sheet. Nuclear Disclosures of obligations related to spent nuclear fuel and the generation of nuclear energy including decommissioning obligation which describes the utility's legal obligations to perform retirement activities. This footnote also includes a disclosure of the related long-lived assets and information related to nuclear insurance coverage. Leases Disclosures related to both capital and operating leases including rental costs, property, plant and equipment under capital leases and future minimum lease payments. Financing Activities Disclosures related to debt arrangements, common stock, preferred stock and factoring of accounts receivable. Debt arrangements include amounts of borrowings under each line of credit, note payable, commercial paper issued, bond indentures, debentures issued, and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancings and noncompliance with debt covenants. Disclosures of common stock and preferred stock include issuances, repu rchases and amounts outstanding at the beginning and end of the period. Disclosure also includes discussion of factoring arrangements. Paid-in Capital, Other Excess of issue price over par or stated value of the entity's capital stock and amounts received from other transactions involving the entity's stock or stockholders: Amount, as of the Statement of Equity date, of Paid-in Capital not separately disclosed in the Statement of Equity due to materiality considerations. Notes to Financial Statements Accrued Taxes The net change during the reporting period in the aggregate amount of obligations incurred and payable for statutory income, sales, use, payroll, excise, real, property and other taxes. Minimum Pension Liability Elimination, Net of Tax Elimination of AOCI related to the recording of additional minimum pension liability due to the adoption of SFAS 158. Minimum Pension Liability Elimination, Tax Effect Tax effect related to elimination of AOCI related to the recording of additional minimum pension liability due to the adoption of SFAS 158. Subtotal - Common Shareholders' Equity Subtotal - Common Shareholders' Equity Provision for Revenue Refund Discloses the amount of regulatory liabilities related to revenues subject to refund. Accrued Interest Change in Carrying value as of the balance sheet date of interest payable on all forms of debt, including trade payables, that has been incurred and is unpaid EITF 06-10 Adoption, Net of Tax Cumulative effect of initial adoption of EITF 06-10 "Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements" on beginning retained earnings, net of tax. EITF 06-10 Adoption, Tax Tax effect of initial adoption of EITF 06-10 "Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements" on beginning retained earnings. SFAS 157 Adoption, Tax Tax effect of initial adoption of SFAS 157 "Fair Value Measurements" on beginning retained earnings. SFAS 157 Adoption, Net of Tax Cumulative effect of initial adoption of SFAS 157 "Fair Value Measurements" on beginning retained earnings, net of tax. EX-100.PRE 7 aep-20081231_pre.xml XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE EX-100.REF 8 aep-20081231_ref.xml XBRL TAXONOMY EXTENSION REFERENCE LINKBASE SFAS 158 SFAS 158 SFAS 158 SFAS 158 SFAS 130 14, 17, 22, 26 SFAS 71 FASB Statement of Financial Accounting Standard (FAS) 71 11, 44, 45, 46, 47 AICPA Accounting Research Bulletin (ARB) 43 3 A 7 SEC Regulation S-X (SX) 210 02 20 5 EITF 06-10 EITF 06-10 SFAS 158 EITF 06-10 -----END PRIVACY-ENHANCED MESSAGE-----