Text

South Texas Project Units 1 and 2, Annual Financial Reports
	ML043380383
Person / Time
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Issue date:	10/26/2004
From:	Harrison G R; South Texas
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	-RFPFR, NOC-AE-04001814
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{{#Wiki_filter:A $110 51 $629$2.53 $2.86 5 .i3)$$57) = 186$1.65 ~$2.40WS0.5 $3.5 $M27.33$31 $19.93 $08 f0.92)d) fn thousge s)5034758 r~-end) ...22 07 5 ,8 8 prshare PP ..and'sevrneai te craso ~g hr fsti etb 1.U n othe freindsonudoeain ecuigwiedw rt'lo ar holde AIN TlF he company had ongoing earnings per share of $2.53 for the year. Adjusted for discontinued operations excluding impairments, our eamings were $2.21, within our projected range. However, as-reported or "GAAP" earnings were $0.29 per share, reflecting impairments for non-core busi-nesses and losses from discontinued operations. Our share price gained 11.6 percent for the year andi total return tshareholders, including dividends, exceeded 19 percent:* AEP'stradition of accomplishmentrweighed heavilyin mydecisiofn to accept the opportunity to succeed Unn Draperas chairman, president and chief executive officer. But I know we cannot rest On tradition. We have large issues and hard work aead of us.lImortant Progress in 2003 AEP made an extraordinary financial turnaround in 2003, which iwe will build upon this year. Those improvements included a$1 -billion equity offering in the first quarter and our reluctant decision to reduce the quarterly dividend on common stock from$0.60 to $0.35 pershare.In addition, we refinanced more than $2 billion of long-term debt, converted $3 billion of short-term debt into long-term debt and restructured lines of creditto ensure a strong liquidity position. At the end of 2003, the company had approximately $1.2 billion in, cash and cash equivalents on its balance sheet and access to;;almost $3 bili on in creditfacilities.

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Summary Report to Shareholders P ., : 1 ,<t., S _ I Bg~ .ff " s,-. :..Last year the company embarked on a concerted effort to divest assets that are not part of our core utility business -particularly non-core assets that have dragged down earnings. In 2003 we sold our investments in two telecommunications businesses, a distribution company based in Brazil and two U.S.-based independent power projects.Our risk exposure continued to decline in 2003 as we further scaled back our energy marketing and trading activities, focusing only on those areas where we have assets and customers. The average value at risk (VaR) for our overall trading operations declined VVI 7 1M T1I P11 AEP workers also distinguished themselves when they were called upon to restore service following several outbreaks of severe weather. Our assistance to Dominion Virginia Power following Hurricane Isabel's landfall on Sept 18 earned AEP the Edison Electric Institute's Emergency Assistance Award.The year 2003 was not without disappointments, however. Several of our investments continued to lose money throughout the year, hurting our earn-ings. Our United Kingdom operations were especially disappointing, losing S132 million last year excluding impairment charges. Continued unfavorable plant S&P Electric AEP S&P hider Utility Madex 40 percent from 2002, and average VaR for our ongoing U.S.trading business fell 58 percent. We settled claims with several trading counterparties, and we further lowered our risk profile by placing our enterprise security function -including both physical security and 'cyber security -within the risk management organization. We saw continued improvement in ongoing earnings from our utility operations in 2003, despite unfavorable weather. Our plant availability was excellent throughout most of the year and our wholesale power sales were strong, allowing us to overcome rel-atively flat retail demand.Cost control also played a role in improving our financial condi-tion. We reduced our utility segment's operations and mainte-nance expenses in 2003 by $139 million, or almost 5 percent, despite greater storm-damage costs and higher pension and post-retirement benefits costs. Cost containment must be a consistent practice at AEP, but we know it cannot be the basis for growth.Continual earnings improvement comes chiefly from growing the business while controlling costs. We intend to do both.Thanks largely to the measures outlined above, AEP maintained an investment-grade rating with a stable outlook -no small feat in our industry's difficult credit environment AEP's experienced work force carried on our tradition of opera.tional excellence in 2003 with some important accomplishments. It is a point of pride that our people and systems performed prop-erly during the Aug. 14 blackout Thanks to our large and robust transmission system, our substantial generation facilities and the well-considered actions of our employees, AEP's system with-stood the severe power disruptions, preventing the blackout from spreading farther. AEP provided support to the U.S.-Canada task force that investigated the blackout and then developed recom-mendations aimed at preventing a recurrence. and trading margins were factors in the UK losses. We reclassi-fied UK operations and our Louisiana Intrastate Gas business as discontinued during the fourth quarter after finalizing plans to exit these businesses in 2004.In the U.S., sections of our service area, notably in parts of Ohio and Oklahoma, experienced reliability problems. In addition, our D.C. Cook nuclear plant performed below our expectations. We are determined to achieve and maintain operational excellence at Cook, and in 2003 we strengthened our nuclear management team to reach that goal. We also applied to the Nuclear Regulatory Commission to renew the operating licenses for Cook's two units when their present licenses expire in 2014 and 2017. D.C. Cook is an important asset for AEP's customers and shareholders and we will do what is necessary to operate the plant safely and efficiently. We were deeply disappointed when the Commodities Futures Trading Commission filed suit against AEP in September for the reporting of false information to trade publications by several former company gas traders. The inappropriate activity came to light as a result of the company's own investigation in 2002. AEP promptly dismissed the traders, reported the matterto authorities and scaled back gas trading operations sharply, and we have cooperated fully with investigators. It is our hope and intention to bring closure to this matter as soon as possible.Although troubling, all of these disappointments pale next to the fact that four AEP employees lost their lives in job-related acci-dents during 2003. Such an overwhelming loss cannot be dis-missed simply with a few words of sympathy and a pledge to do better. l will accept nothing less than a total commitment to safety and will take that message directly to all employees. Paradoxically, AEP recorded fewer employee safety incidents last year and the overall severity of those incidents was lower.Many work locations marked impressive safety milestones. 0 American Electric Power But we must and will achieve a higher state of safety awareness across the entire company to ensure that our employees are as safe as they can possibly be. -2004 Priorities Despite the significant progressthatwe made last year, we still have plenty of work to do. Our divesti-ture program will accelerate in 2004. In addition to actively pursuing the sale of our UK operations and Louisiana Intrastate Gas, we are making progress on the sale However, ceri of our coal holdings in Ohio and Kentucky, our remaining interests have concert in several independent power projects and our investment in tomers in thei power generation in Mexico. We expect these actions to sub- commitment i stantially reduce the drain on earnings that we have been experi- more RTOs be encing and will use sale proceeds to reduce debt. Ourtarget is to result for AEF reduce our debt ratio to below 60 percent by year-end. states in whic concerns of o In 2004 we expect to sell our 4,500 megawatts of generating AEP and othe capacity owned by AEP Texas Central Company, one of our rounding RTO Texas-based operating companies that was formerly known as Central Power and Light Texas deregulation legislation allows for At the state IC the sale of assets to determine stranded costs, or the amount by and sharehol which the book value of assets exceeds market value. Pursuant range of regu to a final order by the Public Utility Commission of Texas, the that have und difference between the plants' sale proceeds and book value can In some jurisd then be securitized, providing cash for debt reduction and other ate under tra, purposes. The loss of this generating capacity will not compro- -rate agreeme mise our system reliability in any way due to the sale of a large without undul part of our Texas retail business to Centrica. ery of expenc ment and allo We will continue to sharpen our focus on our traditional utility energy forthe operations. In particular, we will move aggressively to, address service quality concerns in Ohio and Oklahoma. We have ear- AEP is the lar marked substantial resources for capital costs and operation and 75 million ton!maintenance expenses to boostthe reliability of our energy distri- of our gener, bution system. In Ohio, we are embarking on a two-year program power, wind X aimed at improving the performance of our least-reliable circuits tricity supply1 by an average of 40 percent Actions already taken in Oklahoma have sharply reduced the number of complaints filed with that We recognize state's regulatory commission. environmenta lion in pollutic We expect 2004 ongoing earnings in the range of $2.20 to $2.40 and we look per share, a reachable target assuming modest growth in utility the coming y operations and continued focus on controlling costs.Wewill seek ' our plants so opportunities to increase revenues, reduce costs and improve the cost-effective return on your investment as much as we can. plant trees ar Environmental and Regulatory Opportunities Among our most important priorities in 2004 Will be the drive toward solutions for the significant regulatory and envi-ronmental opportunities facing AER The Federal Energy Regulatory Commission (FERC) strongly advocates that utilities join regional transmission organizations, or RTOs.rain states, including some in AEP's service territory, is about the potential short-term impact on cus-ir respective jurisdictions. AEP intends to honor the we made as part of the CSW merger to join one or!cause we believe significant long-term benefits will I's customers, shareholders, and -therefore -the ch we provide energy. But we will be sensitive to the ur states. Earnest dialogue among FERC, the states,!r companies is the best way to resolve issues sur-participation, and we will promote that dialogue.ivel, we will be working to ensure that our customer der interests are balanced as we address a wide latory issues. The 11 states we serve include some lertaken utility restructuring and some that haven't lictions our rates are capped and in others we oper-ditional regulation. In all cases, we will pursue fair nts that provide a reasonable return to shareholders y burdening customers. We will also pursue recov-litures for equipment that will improve the environ-w our power plants to continue to provide low-cost benefit of our stakeholders. gest consumer of coal in America, using more than s a year on average. Coal and lignite fuel 70 percent ating capacity. We also use natural gas, nuclear and hydro, but coal remains the backbone of elec-for AEP and for America.e that our reliance upon coal brings with it important Il responsibilities. AEP has invested more than $2 bil-in control equipment at our power plants since 1990, forward to investing several billion dollars more in ears to improve the environmental performance of that they can continue to serve our customers with energy. We have also spent millions of dollars to id preserve forests to sequester carbon dioxide and 0 Summary Report to Shareholders ' ' ,.to research and develop ways to burn coal more cleanly and effi-ciently. In 2003 AEP became a founding member of the Chicago Climate Exchange, the first voluntary program for trading green-house gas emission credits. We believe that creating a market in carbon dioxide credits will provide financial incentive for compa-nies to reduce emissions in a way that is more efficient and flexi-ble, just as it did for sulfur dioxide ( SO 2) and nitrogen oxide ( NOx).AEP supports reasonable multi-emission legislation to further reduce SO 2 , NOx and mercury emissions. In addition, we have pledged to reduce greenhouse gas emissions by 4 percent by 2006.While the environmental compliance requirements ahead of us may seem daunting to some, we see an opportunity to make strate-gic investments that will keep our generating facilities productive and profitable for many years to come while helping further clean the environment Our customers will continue to enjoy reliable electricity at very attractive rates compared with our neighbors, even with these environmental investments. And shareholders can be assured that we expect to achieve a reasonable return for them while also improving air qualityto benefit the communities in which our facilities are located.A New Era I am honored to have the opportunity to succeed Linn Draper and carry on the proud tradition of achievement atAER We are indebted to Linn for his many contributions to the company and the industry, and we wish him a long and enjoyable retirement We also bid farewell to Linda Stuntz, who is leaving the AEP Board after 11 years of dedicated service. Linda's sharp intellect and sound judg-ment have been invaluable as AEP has navigated one of the most tumultuous periods in the history of the electric utility industry.We now embark upon a new era for AEP in which we will deliver value to shareholders by doing what we do best: electric utility operations. Through careful use of our substantial assets, a respectful, productive relationship with government and regulatory officials, and the hard work of a talented, diverse, ethical and safe-ty-conscious work force, AEP's future achievements can exceed those of its remarkable past Michael G. Morris Chairman, President and Chief Executive Officer March 5, 2004

Dear Fellow Shareholders:

As I begin my retirement, I want to tell you what an honor it has been to serve as your chairman for nearly 11 years. During that time there have been substantial accomplishments and difficult challenges, but we have never wavered from our goal of moving AEP forward and providing the highest possible return on your investment Today AEP is considered an industry leader by almost any meas-ure.We have one of the largest and most efficient generating fleets in America, an unparalleled transmission system and distribution operations that range from Michigan to the Mexican border. But even assets as rich as ours pale in value compared to our talented and experienced work force. Truly, the people of AEP are extraordinary and I can never thank them enough for the support they have given me.I want to express my most heartfelt thanks to the AEP Board of Directors for their guidance and counsel. It was my good fortune to be associated with such a dedicated and insightful group of indi-viduals. To the many regulators and elected officials with whom I had the pleasure to work, I am grateful for our constructive part-nership that enabled so many of our achievements. And I'd like to say thanks as well to the many environmental and public interest groups with whom we worked to advance our business in a socially responsible manner.To our customers, the millions of people and businesses we are so proud to serve, it has been rewarding to join you in helping to bring growth and prosperity to our communities. And, finally, my sincere thanks to our loyal shareholders. Many of you have expressed your support when we needed it most and I will always be grateful.AEP is certain to continue its leadership under the direction of Mike Morris. With his knowledge, deep experience and leadership skills, there is really no telling how much AEP can grow. We have every reason to expect a bright future.Thank you for your support and for your belief in AEP.Sincerely,' E. Linn Draper, Jr.Past Chairman March 5, 2004 I0 American Electric Power Condensed Consolidated Balance Sheets At December 31 (in Millions)Assets Cash and Cash Equivalents Accounts Receivable 2003' ' ' , ,. I. :i , -$1,J82: I, ..1,71 0.2002 F: $1,199 -, 2,089 Other Current Assets 2,005 2,030 Property, Plant and Equipment 36,033 34,127 Accumulated Depreciation and Amortization ( 14.004) 'i 3.539)Net Property, Plant and Equipment __22,029 ['588..Regulatory Assets -, 3,548 -2,688.Assets Held for Sale 3,082 -L 3,601.Assets of Discontinued Operations ' ' 15'Other Non-Current Assets Total Capitalization and Liabilities Accounts Payable Short-Term Debt and Long-Term Debt Due within One Year Other Current Liabilities Long-Term Debt Deferred Income Taxes Regulatory Liabilities and Deferred Investment Tax Credits Liabilities Held for Sale Liabilities of Discontinued Operations Other Non-Current Liabilities Total Liabilities Cumulative Preferred Stocks of Subsidiaries Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such Subsidiaries Minority Interest in Financing Subsidiary Common Shareholders' Equity Total 3,188': a-$36,744, :$i,337'2,105 2,540'12,322' ', 3,957 2,.259 1,876 .2,413.r.28,80-7,874: 35.74 '6'4'.[ -3,680 i$35,890 g S1.892 ..;4.066* 2,698-, B ,863 , A"':" 939'; ,[ 1,279 12 4 JY.-'3,936 -, 27,601[&il45_321_ :759 l .7_064: A$35,890 .1 Full disclosure of all financial information Is Included in the Appendix A to the Proxy Statement. .. Summary Report to Shareholders

" ;. *'.Condensed Consolidated Statements of Operations Year Ended December31 (In Millions-Except Per-Share Amountsl 2003 2002 Variance Revenues $1s4.5i5, $13,308 $1,237 Expenses

[ -Fuel and Purchased Energy 6,610 5.055 1. 1.555 .Maintenance and Other Operation V_3,673; 4,065 <(; 1392)Asset Impairments and Other Related Charges 650. 318 F .332 Depreciation and Amortization [ 1,299 .- 1,348 (.49)Taxes Other than Income Taxes 1 681 718 1. (37)Total Expenses j 12,913 11.504 j. .1,409 Other Income 387, 461 i, (74)Investment Value Losses 70 r 321 1251)Other Expenses 227 .323 .196)Income Before Interest, Preferred Dividends, Minority Interest and Income Taxes 1 7j2

1,621 101 ;Interest, Preferred Dividends and Minority Interest J: 842 821 21 Income Taxes 358 315 .43.Income Before Discontinued Operations and Cumulative Effect 522 485 .37 Discontinued Operations

-Loss (net of tax) (605) .(654) [ 49 Cumulative Effect of Accounting Changes (net of tax) 193 (350) , 543 Net Income (Loss) ' $110 :. S(519) : .$629'i Average Number of Shares Outstanding 1 332 53 Earnings Per Share: ---: Income Before Discontinued Operations and Cumulative Effect l:$1.35 $1.46 $(0.11)Discontinued Operations -[ (1.57) -(197) -0.40 Cumulative Effect 0.51 (1.06) 1.57, Net Income (Loss) -0.;29:.. $(1.57) ' $1.86 --Cash Dividends Paid Per Share .$ 1.65 $2.40 $[S0.75)-0 American Electric Power Condensed Consolidated Statements of Cash Flows Year Ended December 31 (In Millions)2003 2002 Operating Activities Net Income (Lossl Plus: Discontinued Operations Loss Net Income from Continuing Operations Depreciation and Amortization Cumulative Effect of Accounting Changes Asset and Investment Value Impairments and Other Related Charges Adjustments for Other Noncash Items and Working Capital Net Cash Flows from Operating Activities Investing Activities Construction Expenditures Investment in Discontinued Operations (net)Proceeds from Sale of Assets Other Net Cash Flows Used for Investing Activities Financing Activities Issuance of Common Stock Issuance of Equity Unit Senior Notes Change in Long-Term Debt (net)Retirement of Cumulative Preferred Stock Retirement of Minority Interest Change in Short-Term Debt (net)Dividends Paid on Common Stock Net Cash Flows Used for Financing Activities Effect of Exchange Rate Changes on Cash Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents from Continuing Operations -Beginning of Period Cash and Cash Equivalents from Continuing Operations -End of Period g .-$110 -$(519L 605 654 : 715 i l -135 1,299. 1,375 (193) 350 720 [ 639;(233) J 4321 2,308 .L 2,067 ;.to(1,358) '* ~- (615):.i -82 3 (- 1.888)i 1,142 g 2,054: 'Hi *a:(9):-[ ( 225).-;-(2.781)-(17),,'1.199.:- -$1,182' s .;: 'i .--: (O)X if $ 13-'X (1,685) .1,263 i of -.656;F -..334.,-380:. L(793L)(;~ 681) -.4' 1,005.-$1,199, 1 j 139 :-Net Decrease in Cash and Cash Equivalents from Discontinued Operations Cash and Cash Equivalents from Discontinued Operations -Beginning of Per Cash and Cash Equivalents from Discontinued Operations -End of Period 0 44 4 4 *.444, -_4.:- --.-~ .---__ ---.~ -r -1 ?-~, -., -.,~-- ,-- -, ,-I444 ,I: 4. .7_1 -T -..,- Summar Reor to. Shareholders ...444 4~ :, f, -' ~~444 4 'I,- -I .: : --, ~ , I,> 4,:, " ". , . 4 4 .44~.~. ., -.4~I~:.~ l.~:~ndepe.nd'ent-- Auditors'

., Report -,,.-~ , ..: --41 ..~`I.- .~ ~ -~ :..-, ,, ~ '..~44 4":, :- ,: To te Sareoldes ad Bardof Drecorsof merian lecricPowe Copan In We have audited( .the; , ,cnoiae blneset of America Elect-i PowerCompan Inc an sbsdiresasofDeebe 3.20 an 202 ad hereatdcosoidte satmet ofI eat Icmmnsaehles ec..:q.IIntIy

.,I ,. andcopreeniv .incm and cah flow for ech ofthe hree ears` n th perio enedDeeme 31,, 2003. Such cnoiae iacalsaeet n u reportthereo dae .4 March 5,-,204epesn nuqaiidoiinadicuigepaaoyprgah referin totheadotio ofSFA 14 GoodIl and...- -e'Othrlnanibl Ases FA 143:~ Acontn fo se-Rtrrtbiai , EIF0 susIvovdi.cutn 44,-. ,,, .. ,- ,. , ., ,, '~ _ ,._ _ .1 41S m a y' e o tt .-I4 4 4 , 4 .4 4- .4 44 ~ ~ .~ '~..I ., -...-, -..4 4 4' 4 44..- 4,~ .. I 4 44I 4 4 complet-e:-o;s6!idated fin i.!c!iIt statements. 44.4' 4 444 , --- -.-, ! ~ ..4!In our- opii -, teif'rainse-ot n h comayn cnesdcosldte aaceset s fDcmbr32'ad202an er te ~nese onoidtd tteetso oeatos n of.- cash flows for,. th.eastenedd sfirysatdi 4 4 .. .4 44- , ~ ::~ r. , ~ -,. -:.PI -.-'4 , .", ~ , 7, ,., ,, -" ,..~ ...I 4 .4I ' .4 4 4 .f 4 4 :. ... V .4 4 4 4 4 ...4 :I. ; -.I I. *, .,.4 444 4II 4 , 4 .jI..4I... 4 4 4 4 ..4 , , , I .1.~.4 4 44I , 4449 1 : 1 .~ I :-,, : -' : 44 4444I 4-~ , The Management -,: of American..-,_ Elecric owe Comany ,.Inc. i epn ibe for th integrity representat.Ionsandobectvit-o th ifomain n heCopn smmr anua reorIad odese cnsldaedfianil taemnt hecodese onoldae finncil tatmets rederve frrn heosold.ed inncil tatmets ncude i Apenix t th poxysttemntwhih as ee 4 4 ... -~ ;Z I.4 4 4 4 4 44 4; ~,~., ~ ..; ~ : ",:~ 4, 44c -prpre n ofomtywt gnral acptdaconing pricipes sin inormd etimte wher appoprat torelec th Cmpay g_-., I., '.1 ~~~~.I I ... I- .1 ., ,.444 44 I4 4,. -I I ..., ~ :: ~ I -.,.~-~ , , .... I ~ -finanial cnditon an reslts o opeation. Th infomatin in thersectins o ths um ar annual report -~, ~ is cnsiten with, these state metsTe osoidtd iania taenetshvebenauiedb Dlite ouh LP rm hchths cnenedcnsldae fiancal 4 ta~ensha/eb~nd~ie ~~ ~hoereotapaio~tispge.X< , 444 4,444 4 44 4I*,44 4 44 4444 4 444 444 4 4444 444--~ ".4.4 e e In 4.44-A4d4444 4 4 4 4 4 44444 4 44 4 44 4 4 44444444 4" 4*4 44 44 4 4 .4 44 4 4 4 4 44.I444 .44-o r 4 .4_4 4 44 4444 '4 4 44 4 444 44 444 44.4.4_ 4 44 94 4 4~', 44 *44,4I44t.Lor4,4 I. I Z.I .1. ,. I ~ :. r. i ' " t :" , ~ ~ .44444 , -, :, " ,I _~ _ , ,_" :: --~ -4 4 4: Chairman.~~-~ .Preidntan ChefExcuiv Oficr hif inacil ffce--., ~ , ,I!44 ~- 44,, _,.,, .t "!:%.., ~ ~ , -II I .~ ; ,]r,, , -~ : .: ._ .~ II I 1, .I -.; " ,,4 " 44 4 --44 4 4 4 4 4 44 4 4 4 w I. ,~. , :. 4. ~ _. , ...; : , . American Electric Power Board of Directors Donald G. Smith Michael G. Moris Lester k Hudson, Jr. E.R. Brooks John P. DesBarres Richard L Sandor a ','0' ., :~William F Howell Kathryn D. Sullivan Donald M. Carton Leonard J. Kujawa Linda Gillespe Stuntz Robert W Fri Dr. E. Linn Draper, Jr.. 62 Past Chairman (1992)(Is not standing for re-election) Michael G. Morris, 57 Chairman, President and Chief Executive Officer (2004) E E.R. Brooks, 66 Retired Chairman and Chief Executive Officer, Central & Southwest Corp.Granbury, Texas (2000) F K I Dr. Donald M. Carlton, 66 Retired President and Chief Executive Officer, Radian International. LUC Austin, Texas (2000) A& E 4 P John P. DesBarres, 64 Investor Park City, Utah (1 9 9 7) .KNP Robert W. Fri; 68 Visiting Scholar.Resources for the Future Washington, D.C.(11995) K William R. Howell, 68 Chairman Emeritus, J.C. Penney Company, Inc.Dallas, Texas (2000)° A.K Dr. Lester A. Hudson, Jr., 64 Professor, McColl Graduate School of Business.Queens University of Charlotte Charlotte. North Carolina (1987) A.D.t P Leonard J. Kujawa, 71 International Energy Consultant Atlanta, Georgia (1997) A 0. P Dr. Richard L. Sandor. 62 Chairman and Chief Executive Officer, Chicago Climate Exchange, Inc.Chicago, Illinois (2000) Fa P Thomas V. Shockley, III, 58 Vice Chairman (2000)(Is not standing for re-election) Donald G. Smith, 68 Chairman, President and Chief Executive Officer, Roanoke Electric Steel Corp.Roanoke, Virginia (1994) P Linda Gillespie Stuntz, 49 Partner, Stuntz, Davis & Staffier, P.C.Washington, D.C.(1 9 9 3)D.E.F.P fisnorstanding forre-elec6onJ Dr. Kathryn D. Sullivan, 52 President and Chief Executive Officer, Center of Science & Industry Columbus, Ohio (1 997)AL P Committees of the Board: The chairman is listed in 1.A Audit (Carlton), D Directors and Corporate Governance (Hudson), Executive (Morris).F Finance (Stuntz).H Human Resources (DesBarres), N Nuclear Oversight ISullivan). PPolicy (Fri)0 SummaryReport to, Shareholders

t. U Af M, V ; Ao Executive Council Susan Tonasky Henry W Fayne Thomas M. Hagan Thomas V Shockley.

IIl Holly K. Koeppel Michael G. Morris Rober P. Powers Officers Thomas M. Hagan Jeffrey D. Cross Armando A. Pefia Executive Vice President -Senior Vice President. Senior Vice President -American Electric Power Shared Services General Counsel and Financial Policy Company, Inc. Assistant Secretary Michael G. Morris Chairman, President and Chief Executive Officer Thomas V. Shockley, IlI Vice Chairman Henry W. Fayne Vice President Stephen P Smith Treasurer Susan Tomasky Vice President. Secretary and Chief Financial Officer Joseph M. Buonaluto Controller and Chief Accounting Officer American Electric Power Service Corporation Michael G. Morris Chairman. President and Chief Executive Officer Thomas V. Shockley, Ill Vice Chairman and Chief Operating Officer Henry W. Fayne Executive Vice President-Energy Delivery Holly K. Koeppel Executive Vice President-Commercial Operations Robert P. Powers Executive Vice President -Generation SusanTomasky Executive Vice President -Policy, Finance and Strategic Planning, and Assistant Secretary Melinda S. Ackerman Senior Vice President -Human Resources Nicholas J. Ashooh Senior Vice President -Corporate Communications J. Craig Baker Senior Vice President -Regulation and Public Policy, C.R. Boyle, Ill Senior Vice President -Commercial Business Services Joseph M. Buonaluto Senior Vice President, Controller and Chief Accounting Officer Glenn M. Files Senior Vice President -Distribution Joseph Hamrock Senior Vice President and Chief Information Officer Dale E. Heydlauff Senior Vice President -Governmental and Environmental Affairs Michelle S. Kalnas Senior Vice President -Supply Chain Mark W. Marano Senior Vice President -Generation Business Services Richard E. Munczinski Senior Vice President -Corporate Planning and Budgeting. Mano K. Nazar Senior Vice President and Chief Nuclear Officer Andrew W. Patterson Senior Vice President -Planning and Business Development Michael W. Renchack Senior Vice President -Engineering, Technical and Environmental Services Marsha P Ryan Senior Vice President -Customer Operations* William L Sigmon, Jr.Senior Vice President -Fossil and Hydro Generation Scott N. Smith Senior Vice President and Chief Risk Officer Stephen P Smith Treasurer and Senior Vice President -.:.Corporate Accounting, Planning and Strategy Brian X.Tierney Senior Vice President -Energy Marketing Administration Richard P. Verret Senior Vice President -Transmission Charles E. Zebula Senior Vice President -Fuel, Emissions and Logistics (D American Electric Power Shareholder Information Corporate Headquarters 1 Riverside Plaza Columbus, OH 43215-2373 614-716-1000 www.aep.com AEP is incorporated in the State of New York.Annual Meeting -The 97th annual meeting of shareholders of American Electric Power Company will be held at 9:30 a.m. Tuesday, April 27. 2004, at The Ohio State University's Fawcett Center, 2400 Olentangy River Road, Columbus. Ohio. Admission is by ticket only. To obtain a ticket, please note the instructions in the Notice of Annual Meeting mailed to shareholders or call the Company. If you hold your shares through a broker, please bring proof of share ownership as of the record date.Inquiries Regarding Your Stock Holdings -Registered share-holders (shares owned by you, in your name) should contact the Company's transfer agent, listed below, if you have questions about your account, address changes, stock transfer, lost certificates, direct deposits, dividend checks and other administrative matters. You should have your Social Security number or account number ready, the transfer agent will not speak to third parties about an account without the shareholders approval or appropriate documents. Transfer Agent and Registrar EquiServe Trust Company. N.A.(formerly First Chicago Trust Company of New York)P.O. Box 43069 Providence, RI 02940-3069 Telephone Response Group: 1-800-328-6955; Internet address: vwew.equiserve.com Hearing Impaired I: TDD: 1-800-952-9245 Baneficial Holders -(Stock Held in a Bank or Brokerage Account, some-times referred to as 'Street Name") -When you purchase stock and it is held for you by your broker, it is listed with the Company in the brokerls name, and this is sometimes referred to as 'street name' or a 'beneficial owner." AEP does not know the identity of individual shareholders who hold their shares in this manner, we simply know that a broker holds a certain number of.shares which may be for any number of customers. If you hold your stock in street name, you receive all dividend payments, annual reports and proxy materials through your broker. Therefore, if your shares are held in this man-ner, any questions you may have about your account should be directed to your broker.Internet Access to Your Account -If you are a registered share-holder, you can access your account information'through the Internet at www.equiserve.com. Information about obtaining a password is available toll-free at 1-877-843-9327. Dividend Reinvestment and Direct Stock Purchase Plan -A Dividend Reinvestment and Direct Stock Purchase Plan is available to all investors. It is an economical and convenient method of purchasing shares of AEP common stock, through initial cash investments, cash dividends, and/or additional optional cash purchases. You may obtain the Plan prospectus and enrollment authorization form by contacting the transfer agent.'Stock Exchange Listing -The Company's common stock is traded principally on the New York Stock Exchange under the ticker symbol AEP.AEP stock has been traded on the NYSE for 55 years.Dividends -The Company paid $1.65 in cash dividends on common stock in 2003, all of which are taxable for federal income tax purposes. 60 cents per share was paid in the first quarter, and 35 cents per share was paid in each quarter thereafter in 2003. AEP normally pays dividends on common stock fourtimes ayear, generallyaround the 15th of March,June, September and December. AEP has paid 375 consecutive quarterly dividends on common stock beginning in 1910.Quarterly Stock Price Information 2003 2002 Quarter First Second Third Fourth Year-end High$30.63 31.51 30.00 30.59 30.51 Low$19.01* 22.56 26.58 26.69 High$47.08 48.80 40.37 30.55 27.33 Low$39.70 39.00 22.74 15.10 Number of Shareholders As of December 31, 2003, there were approximately 150,000 registered shareholders, and approximately 240,000 individual shareholders holding stock in 'street name" through a bank or broker. There were 395,016,421 shares outstanding at December 31, 2003.Internet Home Page -Information about AEP, including financial docu-ments, SEC filings, news releases, investor presentations, shareholder infor-mation and customer service information, is available on the Company's home page on the Internet at www.aep.com. Financial and Other Information -Earnings and other financial results, corporate news and company information are available from Share-holder Direct at 1-800-551-1AEP (1237) anytime day or night. Hard copies of information can be obtained via fax or mail. Requests for annual reports, 10-K's, 10-0's, Proxy Statements and Summary Annual Reports should be made through Shareholder.com. This same information is also available on our website at www.aep.com. Financial Community Inquiries -Institutional investors or securities analysts who have questions about the Company should direct inquiries to Julie Sloat, 614-716-2885, jsloatgaep.comor Bette Jo Rozsa, 614-716-2840, birozsagaep.com; individual shareholders should contact Kathleen Kozero, .614-716-2819, klkozero~aep.com, or April Dawson, 614-716-2591, addawsongaep.com. Independent Auditors Deloitte and Touche 155 East Broad St.Columbus, OH 43215 Receive Annual Reports and Proxy Materials Electronically -You can receive future annual reports, proxy statements and proxies electronically rather than by mail; if you are a registered holder, log on to www.econsent.com/aep. If you hold your shares in street name, contact your broker.0

AVON M UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One)[XI ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31,2003[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission File Number 1-3525 0-18135 0-346 0-340 1-3457 1-2680 1-3570 1-6858 1-6543 0-343 1-3146 Registrants; States of Incorporation; Address and Telephone Number AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation) AEP GENERATING COMPANY (An Ohio Corporation) AEP TEXAS CENTRAL COMPANY (A Texas Corporation) AEP TEXAS NORTn COMPANY (A Texas Corporation) APPALAcIHAN POWER COMPANY (A Virginia Corporation) COLUMBUS SOUTIERN POWER COMPANY (An Ohio Corporation) INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) KENrUCKY POWER COMPANY (A Kentucky Corporation) 01 Ho POWER COMPANY (An Ohio Corporation) PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation) SOUrH WESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) I Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 716-1000 I.R.S. Employer Identification Nos.13-4922640 31-1033833 74-0550600 75-0646790 54-0124790 31-4154203 35-0410455 61-0247775 31-4271000 73-0410895 72-0323455 Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes [X]. No. [ I Indicate by check mark if disclosure of delinquent filers with respect to American Electric Power Company, Inc. pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form I0-K. [ I Indicate by check mark if disclosure of delinquent filers with respect to Appalachian Power Company, Indiana Michigan Power Company or Ohio Power Company pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements of Appalachian Power Company or Ohio Power Company incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]Indicate by check mark whether American Electric Power Company, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X1 No [ I Indicate by check mark whether AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are accelerated filers (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [ I No [X] AEP Generating Company, AEP Texas North Company, Columbus Southern Power Company, Kentucky Power Company and Public Service Company of Oklahoma meet the conditions set forth in General Instruction l(l)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction 1(2) to such Form 10-K.Securities registered pursuant to Section 12(b) or the Act: Reektrant AEP Generating Company AEP Texas Central Company AEP Texas North Company American Electric Power Company, Inc.Appalachian Power Company Columbus Southern Power Company CPL Capital I Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma PSO Capital I Southwestern Electric Power Company Title of each class None None None Common Stock, $6.50 par value...................................... 9.25% Equity Units.................................................................. None None 8.00% Cumulative Quarterly Income Preferred Securities, Series A, Liquidation Preference $25 per Preferred Security ..................................... 6% Senior Notes, Series D, Due 2032 ..................................... None 7 3/8% Senior Notes, Series A, Due 2038 ............................... 6% Senior Notes, Series B, Due 2032 ..................................... 8.00% Trust Originated Preferred Securities, Series A, Liquidation Preference $25 per Preferred Security ..................................... None Name of each exchange on which registered New York Stock Exchange New York Stock Exchange New York Stock Exchange New York Stock Exchange New York Stock Exchange New York Stock Exchange New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: Reoistrant AEP Generating Company AEP Texas Central Company AEP Texas North Company American Electric Power Company, Inc.Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company Title of each class None 4.00% Cumulative Preferred Stock, Non-Voting, $100 par value 4.20% Cumulative Preferred Stock, Non-Voting, $100 par value None None 4.50% Cumulative Preferred Stock, Voting, no par value None 4.125% Cumulative Preferred Stock, Non-Voting, $100 par value None 4.50% Cumulative Preferred Stock, Voting, $100 par value None 4.28% Cumulative Preferred Stock, Non-Voting, $100 par value 4.65% Cumulative Preferred Stock, Non-Voting, $100 par value 5.00% Cumulative Preferred Stock, Non-Voting, S100 par value AEP Generating Company AEP Texas Central Company AEP Texas North Company American Electric Power Company, Inc.Aggregate market value orvoting and non-voting common equity held by non-a filiates of the registrants at June 30,2003 None None None$11,782,905,274 Appalachian Power Company None Number of shares of common stock outstanding of the registrants at December31,2003 1,000 ($1,000 par value)2,211,678 ($25 par value)5,488,560 ($25 par value)395,016,421 ($6.50 par value)13,499,500 (no par value)16,410,426 (no par value)1,400,000 (no par value)1,009,000 ($50 par value)27,952,473 (no par value)9,013,000 ($15 par value)7,536,640 ($18 par value)Columbus Southern Power Company None Indiana Michigan Power Company None Kentucky Power Company None Ohio Power Company None Public Service Company of Oklahoma None Southwestern Electric Power Company None NOTE ON MARKET VALUE OF COMMON EQUITY HELD BY NON-AFFILIATES American Electric Power Company, Inc. owns, directly or indirectly, all of the common stock of AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan. Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company (see Item. 12 herein). DOCUMENTS INCORPORATED BY REFERENCE Descrintion Portions of Annual Reports of the following companies for the fiscal year ended December 31,2003: AEP Generating Company AEP Texas Central Company AEP Texas North Company American Electric Power Company, Inc.Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company Portions of Proxy Statement of American Electric Power Company, Inc. for 2004 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 2003 Portions of Information Statements of the following companies for 2004 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 2003: Part or Form 10-K Into Which Document Is Incorporated Part II Part III Part III Appalachian Power Company Ohio Power Company This combined Form 10-K is separately filed by AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, American Electric Power Company, Inc., Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Except for American Electric Power Company, Inc., each registrant makes no representation as to information relating to the other registrants. You can access financial and other information at AEP's website, including AEP's Principles of Business Conduct (which also serves as a code of ethics applicable to Item 10 of this Form 10-K), certain committee charters and Principles of Corporate Governance. The address is www.aep.com. AEP makes available, free of charge on its website, copies of its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. TABLE OF CONTENTS Glossary of Terms ........................................................................................................................................................................ Forward-Looking Information....................................................................................................................................................... PART I Item 1. Business........................................................................................................................................................... Item 2. Properties......................................................................................................................................................... Item 3. Legal Proceedings. Item 4. Submission of Matters to a Vote of Security Holders.Executive Officers of the Registrants ........................................................................................................................................ PART 11 Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. Item 6. Selected Financial Data .Item 7. Management's Financial Discussion and Analysis and Financial Condition. Item 7A. Quantitative and Qualitative Disclosures About Market Risk.Item 8. Financial Statements and Supplementary Data.Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .Item 9A. Controls and Procedures. PART III Item 10. Directors and Executive Officers of the Registrants. Item 11. Executive Compensation. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters .Item 13. Certain Relationships and Related Transactions. Item 14. Principal Accountant Fees and Services.PART IV Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K .Signatures ..................................................................................................................................................................................... Index to Financial Statement Schedules....................................................................................................................................... Independent Auditors' Report...................................................................................................................................................... Exhibit Index................................................................................................................................................................................ Page Number I 2 26 29 29 30 31 31 32 32 32 32 32 33 34 34 36 36 37 39 S-I S-2 E-I GLOSSARY OF TERMS The following abbreviations or acronyms used in this Formn I -K are defined below: Abbreviation or Acronym AEGCo....................................................... AEP............................................................. AEPES ........................................................ AEP Power Pool ......................................... AEPR.......................................................... AEPSC or Service Corporation .................. AEP System or the System ......................... AEP Utilities............................................... AFUDC....................................................... A U ............................................................. APCo.......................................................... Btu .............................................................. Buckeye ...................................................... CAA............................................................ CAAA......................................................... Cardinal Station.......................................... Centrica....................................................... CERCLA..................................................... CG& E ......................................................... Cook Plant .................................................. CSPCo........................................................ CSW Operating Agreement........................ DOE............................................................ DP& L.......................................................... East zone public utility subsidiaries............ ECOM ......................................................... EM F............................................................ EPA............................................................. ERCOT....................................................... EW G ........................................................... FERC .......................................................... Fitch ............................................................ FPA............................................................. FUCO.......................................................... I&M ............................................................ I&M Power Agreement .............................. Interconnection Agreement......................... IURC........................................................... KPCo.......................................................... KPSC.......................................................... LLW PA....................................................... LPSC........................................................... M ECPL....................................................... M EW TU ..................................................... M ISO .......................................................... M oody's...................................................... M TM ........................................................... M W ............................................................ NOx ............................................................ Definition AEP Generating Company, an electric utility subsidiary of AEP American Electric Power Company, Inc.AEP Energy Services, Inc., a subsidiary of AEP APCo, CSPCo, I&M, KPCo and OPCo, as parties to the Interconnection Agreement AEP Resources, Inc., a subsidiary of AEP American Electric Power Service Corporation, a service subsidiary of AEP The American Electric Power System, an integrated electric utility system, owned and operated by AEP's electric utility subsidiaries AEP Utilities, Inc., subsidiary of AEP, formerly, Central and South West Corporation Allowance for funds used during construction. Defined in regulatory systems of accounts as the net cost of borrowed funds used for construction and a reasonable rate of return on other funds when so used.Administrative law judge Appalachian Power Company, an electric utility subsidiary of AEP British thermal unit Buckeye Power, Inc., an unaffiliated corporation Clean Air Act Clean Air Act Amendments of 1990 Generating facility co-owned by Buckeye and OPCo Centrica U.S. Holdings, Inc., and its affiliates collectively, unaffiliated companies Comprehensive Environmental Response, Compensation and Liability Act of 1980 The Cincinnati Gas & Electric Company, an unaffiliated utility company The Donald C. Cook Nuclear Plant, owned by I&M, located near Bridgman, Michigan Columbus Southern Power Company, a public utility subsidiary of AEP Agreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing generating capacity allocation United States Department of Energy The Dayton Power and Light Company, an unaffiliated utility company APCo, CSPCo, I&M, KPCo and OPCo Excess cost over market Electric and Magnetic Fields United States Environmental Protection Agency Electric Reliability Council of Texas Exempt wholesale generator, as defined under PUHCA Federal Energy Regulatory Commission Fitch Ratings, Inc.Federal Power Act Foreign utility company as defined under PUHCA Indiana Michigan Power Company, a public utility subsidiary of AEP Unit Power Agreement Between AEGCo and I&M, dated March 31, 1982 Agreement, dated July 6, 1951, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants Indiana Utility Regulatory Commission Kentucky Power Company, a public utility subsidiary of AEP Kentucky Public Service Commission Low-Level Waste Policy Act of 1980 Louisiana Public Service Commission Mutual Energy CPL, L.P., a Texas REP and former AEP affiliate Mutual Energy WTU, L.P., a Texas REP and former AEP affiliate Midwest Independent Transmission System Operator Moody's Investors Service, Inc.Marked-to-market Megawatt Nitrogen oxide i Abbreviation or Acronym NPC ............................................................ NRC ............................................................ OASIS......................................................... OATT .......................................................... OCC ............................................................ Ohio Act...................................................... OPCo.......................................................... OVEC ......................................................... PJM ............................................................. Pro Serv ...................................................... PSO............................................................. PTB............................................................. PUCO.......................................................... PUCT.......................................................... PUBCA....................................................... QF............................................................... RCRA ......................................................... REP............................................................. Rockport Plant............................................ RTO ............................................................ SEC............................................................. S&P............................................................. S02 .............................................................. SO 2 Allowance............................................ SPP .............................................................. STPNOC..................................................... SWVEPCo..................................................... TCA ............................................................ TCC ............................................................ TEA ............................................................ Texas Act.................................................... TNC ............................................................ TVA............................................................ Virginia Act ................................................ VSCC.......................................................... W VPSC....................................................... West zone public utility subsidiaries .......... Definition National Power Cooperatives, Inc., an unaffiliated corporation Nuclear Regulatory Commission Open Access Same-time Information System Open Access Transmission Tariff, filed with FERC Corporation Commission of the State of Oklahoma Ohio electric restructuring legislation Ohio Power Company, a public utility subsidiary of AEP Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo together own a 44.2% equity interest PJM Interconnection, L.L.C.AEP Pro Serv, Inc., a subsidiary of AEP Public Service Company of Oklahoma, a public utility subsidiary of AEP Price to beat, as defined by the Texas Act The Public Utilities Commission of Ohio Public Utility Commission of Texas Public Utility Holding Company Act of 1935, as amended Qualifying facility, as defined under the Public Utility Regulatory Policies Act of 1978 Resource Conservation and Recovery Act of 1976, as amended Retail electricity provider A generating plant, consisting of two 1,300,000-kilowatt coal-fired generating units, near Rockport, Indiana Regional Transmission Organization Securities and Exchange Commission Standard & Poor's Ratings Service Sulfur dioxide An allowance to emit one ton of sulfur dioxide granted under the Clean Air Act Amendments of 1990 Southwest Power Pool STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of its joint owners, including TCC Southwestern Electric Power Company, a public utility subsidiary of AEP Transmission Coordination Agreement dated January 1, 1997 by and among, PSO, SWEPCo, TCC, TNC and AEPSC, which allocates costs and benefits in connection with the operation of the transmission assets of the four public utility subsidiaries AEP Texas Central Company, formerly Central Power and Light Company, a public utility subsidiary of AEP Transmission Equalization Agreement dated April 1, 1984 by and among APCo, CSPCo, I&M, KPCo and OPCo, which allocates costs and benefits in connection with the operation of transmission assets Texas electric restructuring legislation AEP Texas North Company, formerly W~est Texas Utilities Company, a public utility subsidiary of AEP Tennessee Valley Authority Virginia electric restructuring legislation Virginia State Corporation Commission West Virginia Public Service Commission PSO, SWEPCo, TCC and WNC ii FORWARD-LOOKING INFORMATION These reports made by AEP and its registrant subsidiaries contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and its registrant subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:* Electric load and customer growth.* Weather conditions.

Available sources and costs of fuels.* Availability of generating capacity and the performance of AEP's generating plants.* The ability to recover regulatory assets and stranded costs in connection with deregulation.

.New legislation and government regulation including requirements for reduced emissions of sulfur, nitrogen, carbon and other substances.

Resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery for environmental compliance).
Oversight and/or investigation of the energy sector or its participants.
Resolution of litigation (including pending Clean Air Act enforcement actions and disputes arising from the bankruptcy of Enron Corp.)* AEP's ability to reduce its operation and maintenance costs.* The success of disposing of investments that no longer match AEP's corporate profile.* AEP's ability to sell assets at attractive prices and on other attractive terms.* International and country-specific developments affecting foreign investments including the disposition of any current foreign investments.
The economic climate and growth in AEP's service territory and changes in market demand and demographic patterns.* Inflationary trends.* AEP's ability to develop and execute on a point of view regarding prices of electricity, natural gas, and other energy-related commodities.
Changes in the creditworthiness and number of participants in the energy trading market.* Changes in the financial markets, particularly those affecting the availability of capital and AEP's ability to refinance existing debt at attractive rates.* Actions of rating agencies, including changes in the ratings of debt and preferred stock.* Volatility and changes in markets for electricity, natural gas, and other energy-related commodities.
Changes in utility regulation, including the establishment of a regional transmission structure.
Accounting pronouncements periodically issued by accounting standard-setting bodies.* The performance of AEP's pension plan.* Prices for power that we generate and sell at wholesale.
Changes in technology and other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.I Item 1. Business General Ovserview and Description of Subsidiaries AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a registered public utility holding company under PUHCA that owns, directly or indirectly, all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries.

The service areas of AEP's public utility subsidiaries cover portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. The generating and transmission facilities of AEP's public utility subsidiaries are interconnected, and their operations are coordinated, as a single integrated electric utility system. Transmission networks are interconnected with extensive distribution facilities in the territories served. The public utility subsidiaries of AEP, which do business as "American Electric Power," have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Restructuring legislation in Michigan, Ohio, Texas and Virginia has caused or will cause AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers. The AEP System is an integrated electric utility system and, as a result, the member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The member companies of the AEP System also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC.At December 31,2003, the subsidiaries of AEP had a total of 22,075 employees. AEP, because it is a holding company rather than an operating company, has no employees. The public utility subsidiaries of AEP are: APCo (organized in Virginia in 1926) is engaged in the generation, transmission and distribution of electric power to approximately 929,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2003, APCo and its wholly owned subsidiaries had 2,371 employees. Among the principal industries served by APCo are coal mining, primary metals, chemicals and textile mill products. In addition to its AEP System interconnections, APCo also is interconnected with the following unaffiliated utility companies: Carolina Power & Light Company, Duke Energy Corporation and Virginia Electric and Power Company. APCo has several points of interconnection with TVA and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems.CSPCo (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, transmission and distribution of electric power to approximately 698,000 retail customers in Ohio, and in supplying and marketing electric power at wholesale to other electric utilities, municipalities and other market participants. At December 31, 2003, CSPCo had 1,125 employees. CSPCo's service area is comprised of two areas in Ohio, which include portions of twenty-five counties. One area includes the City of Columbus and the other is a predominantly rural area in south central Ohio. Among the principal industries served are food processing, chemicals, primary metals, electronic machinery and paper products. In addition to its AEP System interconnections, CSPCo also is interconnected with the following unaffiliated utility companies: CG&E, DP&L and Ohio Edison Company.I&M (organized in Indiana in 1925) is engaged in the generation, transmission and distribution of electric power to approximately 575,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants. At December 31, 2003, I&M had 2,634 employees. Among the principal industries served are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and miscellaneous plastic products and chemicals and allied products. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana. In addition to its AEP System interconnections, l&M also is interconnected with the following unaffiliated utility companies: Central Illinois Public Service Company, CG&E, Commonwealth Edison Company, Consumers Energy Company, 2 Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power & Light Company.KPCo (organized in Kentucky in 1919) is engaged in the generation, transmission and distribution of electric power to approximately 175,000 retail customers in an area in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2003, KPCo had 394 employees. In addition to its AEP System interconnections, KPCo also is interconnected with the following unaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc. KPCo is also interconnected with TVA.Kingsport Poswer Company (organized in Virginia in 1917) provides electric service to approximately 46,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. Kingsport Power Company does not own any generating facilities. It purchases electric power from APCo for distribution to its customers. At December 31, 2003, Kingsport Power Company had 57 employees. OPCo (organized in Ohio in 1907 and re-incorporated in 1924) is engaged in the generation, transmission and distribution of electric power to approximately 704,000 retail customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2003, OPCo had 2,153 employees. Among the principal industries served by OPCo are primary metals, rubber and plastic products, stone, clay, glass and concrete products, petroleum refining and chemicals. In addition to its AEP System interconnections, OPCo also is interconnected with the following unaffiliated utility companies: CG&E, The Cleveland Electric Illuminating Company, DP&L, Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power Company.PSO (organized in Oklahoma in 1913) is engaged in the generation, transmission and distribution of electric power to approximately 505,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2003, PSO had 1,067 employees. Among the principal industries served by PSO are natural gas and oil production, oil refining, steel processing, aircraft maintenance, paper manufacturing and timber products, glass, chemicals, cement, plastics, aerospace manufacturing, telecommunications, and rubber goods. In addition to its AEP System interconnections, PSO also is interconnected with Ameren Corporation, Empire District Electric Co., Oklahoma Gas & Electric Co., Southwestern Public Service Co. and Westar Energy Inc.SWVEPCo (organized in Delaware in 1912) is engaged in the generation, transmission and distribution of electric power to approximately 439,000 retail customers in northeastern Texas, northwestern Louisiana and western Arkansas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2003, SWEPCo had 1,351 employees. Among the principal industries served by SWEPCo are natural gas and oil production, petroleum refining, manufacturing of pulp and paper, chemicals, food processing, and metal refining. The territory served by SWEPCo also includes several military installations, colleges, and universities. In addition to its AEP System interconnections, SWEPCo is also interconnected with CLECO Corp., Empire District Electric Co., Entergy Corp.and Oklahoma Gas & Electric Co.TCC (organized in Texas in 1945) is engaged in the generation, transmission and sale of power to affiliated and non-affiliated entities and the distribution of electric power to approximately 711,000 retail customers through REPs in southern Texas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2003, TCC had 1,203 employees. Among the principal industries served by TCC are oil and gas extraction, food processing, apparel, metal refining, chemical and petroleum refining, plastics, and machinery equipment. In addition to its AEP System interconnections, TCC is a member of ERCOT.TNC (organized in Texas in 1927) is engaged in the generation, transmission and sale of power to affiliated and non-affiliated entities and the distribution of electric power to approximately 190,000 retail customers through REPs in west and central Texas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2003, TNC had 472 employees. The principal industry served by TNC is agriculture. The territory served by TNC also includes several military installations and correctional facilities. In addition to its AEP System interconnections, TNC is a member of ERCOT.3 Wheeling Power Company (organized in West Virginia in 1883 and reincorporated in 1911) provides electric service to approximately 41,000 retail customers in northern West Virginia. Wheeling Power Company does not own any generating facilities. It purchases electric power from OPCo for distribution to its customers. At December 31, 2003, Wheeling Power Company had 57 employees. AEGCo (organized in Ohio in 1982) is an electric generating company. AEGCo sells power at wholesale to l&M and KPCo.AEGCo has no employees. Service Company Subsidiary AEP also owns a service company subsidiary, AEPSC. AEPSC provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to the AEP System companies. The executive officers of AEP and its public utility subsidiaries are all employees of AEPSC. At December 31,2003, AEPSC had 6,215 employees. Classes of Service The principal classes of service from which the public utility subsidiaries of AEP derive revenues and the amount of such revenues during the year ended December 31, 2003 are as follows: AEP System(a)Utility Operations: Retail Sales Residential............................................. Commercial ........................................... Industrial ............................................... Other Retail Sales.................................. Total Retail......................................... Wholesale System Sales and Transmission............. Other Wholesale Revenues ................... Risk Management Realized................... Risk Management Mark-to-Market. Total Wholesale.................................. Other Operating Revenues ...................... Sales to Affiliates .................................... Gross Utility Operations..................... Provision for Rate Refund....................... Net Utility Operations ........................ Investments-Gas Operations..................... Investments-Other.................................... Total Revenues................................... $ 3,171,000 2,348,000 1,977,000 173.000 7,669,000 2,554,000 205,000 (198.000)2,561,000 745,000 10,975,000 (104.000)10,871,000 3,097,000 577.000$-14,545,00 APCo S 623,435 321,515 342,593 41.060 1,328,603 311,056 17,391_ (2.249 326,198 79,583 222.793 1,957,177 181 1,957,358$195735 CSPCO (in thousands) $ 509,919 455,304 133,242 17.975 1,116,440 183,490 10,491 (5.134)188,847 42,195 84.369 1,431,851 1,431,851 S$IA1.1 I&MI$ 352,710 272,319 319,783 6.154 950,966 337,275 11,440 348,715 46,712 249.203 1,595,596 1,595,596$ 15915256 KPCo$ 120,001 68,904 94,567 926 284,398 69,451 4,038 73,489 18,775 39,808 416,470 416,470 S-1 OPCo Utility Operations: Retail Sales Residential ............................................ Commercial .......................................... Industrial............................................... Other Retail Sales................................. Total Retail........................................ Wholesale System Sales and Transmission............ Other Wholesale Revenues................... Risk Management Realized.................. Risk Management Mark-to-Market. Total Wholesale................................. $ 474,323 314,526 522,449 8.413 1,319,711. 263,397 13,882 (11.381)265,898 NO$ 402,988 275,852 231,638 83.491 993,969 61,173 3,667 64,840 sumaPCO (in thousands) $ 350,386 291,859 215,805 6.478 864,528 147,885 4,325 3,439 155,649 TCC$ 215,330 158,307 43,469 8.824 425,930 894,509 26,331 2,801 923,641* Mc$ 57,191 28,395 8,199 11.484 105,269 279,973 9,590 911 290,474 4 OPCo MSl SMVEPCo TCC TNC (in Thousands) Other Operating Revenues ...................... 74,766 20,883 66,373 339,696 39,292 Sales to Affiliates.8 ............................. 584.278 23.130 68 .854 141,698 51,625 Gross Utility Operations .................... 2,244,653 1,102,822 1,155,404 1,830,965 486,660 Provision for Rate Refund ...................... --(8.562) (83.454 (20,714 Net Utility Operations ........................ 2,244,653 1,102,822 1,146,842 1,747,511 465,946 Investments-Gas Operations

Investments-Othert.........

Total Revenues.......................................4 $S12,46,842 $.74.511 $ 65X (a) Includes revenues of other subsidiaries not shown. Intercompany transactions have been eliminated, including AEGCo's total revenues of $233,165,000 for the year ended December 31, 2003, all of which resulted from its *wholesale business, including its marketing and trading of power.Holding Company Regulation The provisions of PUHCA, administered by the SEC, regulate many aspects of a registered holding company system, such as the AEP System. PUHCA limits the operations of a registered holding company system to a single integrated public utility system and such other businesses as are incidental or necessary to the operations of the system. In addition, PUHCA governs, among other things, financings, sales or acquisitions of utility assets and intra-system transactions. PUHCA and the rules and orders of the SEC currently require that transactions between associated companies in a registered holding company system be performed at cost with limited exceptions. Over the years, the AEP System has developed numerous affiliated service, sales and construction relationships and, in some cases, invested significant capital and developed significant operations in reliance upon the ability to recover its full costs under these provisions. The Division of Investment Management of the SEC has recommended the conditional repeal of PUHCA. Under its recommendation, certain oversight authority would be transferred to the FERC. Legislation has since been introduced in numerous sessions of Congress that would repeal PUHCA, but such legislation has not passed.AEP-cSI'illerger On June 15, 2000, CSW (now known as AEP Utilities, Inc.) merged with and into a wholly owned merger subsidiary of AEP. As a result, CSW became a wholly owned subsidiary of AEP. The four wholly owned public utility subsidiaries of CSW-PSO, SWEPCo, TCC and TNC-became indirect wholly owned public utility subsidiaries of AEP as a result of the merger. The merger was approved by the FERC and the SEC (with respect to PUHCA).On January 18, 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC failed to properly explain how the merger met the requirements of PUHCA and remanded the case to the SEC for further review. The court held that the SEC had not adequately explained its conclusions that the merger met PIJHCA requirements that the merging entities be "physically interconnected" and that the combined entity was confined to a "single area or region." Management believes that the merger meets the requirements of PUHCA and expects the matter to be resolved favorably. Financing General Companies within the AEP System generally use short-term debt to finance working capital needs, acquisitions and construction. The companies periodically issue long-term debt to reduce short-term debt. Short-term debt has in recent history been-provided by AEP's commercial paper program and revolving credit facilities. Proceeds were made available to subsidiaries under the AEP corporate borrowing program. Throughout 2003, AEP was successful in accessing the commercial paper market. Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity. 5 AEP's revolving credit agreements (which backstop the commercial paper program) include covenants and events of default typical for this type of facility, including a maximum debt/capital test and a $50 million cross-acceleration provision. At December 31, 2003, AEP was in compliance with its debt covenants. With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before termination of the agreements. A voluntary bankruptcy or insolvency would be considered an immediate termination event. See Management 's Financial Discussion and Analysis of Results of Operations, included in the 2003 Annual Reports, under the heading entitled Financial Condition for additional information with respect to AEP's credit agreements. AEP's subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as leasing arrangements, including the leasing of utility assets and coal mining and transportation equipment and facilities. Credit Ratings In 2003, the rating agencies conducted credit reviews of AEP and its registrant subsidiaries. The agencies also reviewed many companies in the energy sector due to issues that impact the entire industry.Moody's completed its review of AEP and its rated subsidiaries in February 2003. The results of that review were downgrades of the following ratings for unsecured debt: AEP from Baa2 to Baa3, APCo from Baal to Baa2, TCC from Baal to Baa2, PSO from A2 to Baal, SWEPCo from A2 to Baal. TNC, which had no senior unsecured notes outstanding at the time of the ratings action, had its mortgage bond debt downgraded from A2 to A3. AEP's commercial paper was also concurrently downgraded from P-2 to P-3. The completion of this review was a culmination of earlier ratings action in 2002 that had included a dovngrade of AEP from Baal to Baa2. With the completion of the reviews, Moody's placed AEP and its rated subsidiaries on stable outlook.S&P completed its review of AEP and its rated subsidiaries in March 2003. The results of that review were downgrades of the ratings for unsecured debt for AEP and its rated subsidiaries from BBB+ to BBB. AEP's commercial paper rating was affirmed at A-2. With the completion of the reviews, S&P placed AEP and its rated subsidiaries on stable outlook.Fitch completed its review of AEP and its rated subsidiaries in March 2003. The result of that review was a downgrade of AEP's unsecured debt rating from BBB+ to BBB. AEP's commercial paper rating was affirmed at F-2. With the completion of the reviews, Fitch placed AEP and its rated subsidiaries on stable outlook.See Management's Financial Discussion and Analysis of Results of Operations, included in the 2003 Annual Reports, under the heading entitled Financial Condition for additional information with respect to AEP's credit ratings, liquidity and specific financing activities. En rvronniental and Oth1er Matters General AEP's subsidiaries are currently subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities. The environmental issues that are potentially material to the AEP system include:* The CAA and CAAA and state laws and regulations (including State Implementation Plans) that require compliance, obtaining permits and reporting as to air emissions. See Management's Financial Discussion and Analysis of Results of Operations under the heading entitled The Current Air Quality Regulatory Framevork. -Litigation with the federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating plants required additional permitting or pollution control technology. See Management's Financial Discussion and Analysis of Results of Operations under the headings entitled The Current Air Quality Regulatory Framework and Newv Source Reviev Litigation and Note 9 to the consolidated financial statements entitled Commitments and Contingencies, included in the 2003 Annual Reports, for further information.

Rules issued by the EPA and certain states that require substantial reductions in SO 2 , mercury and NOx emissions, some of which became effective in 2003. The remaining compliance dates and proposals would take effect periodically through as late as 2018. AEP is installing (or has installed) emission control technology and is taking other measures to comply with required 6 reductions.

See Management's Financial Discussion and Analysis of Results of Operations under the headings entitled Future Reduction Requirementsfor NOx, SO 2 and Hg and EstimatedAir Quality Investments and Note 7 to the consolidated financial statements entitled Commitments and Contingencies, included in the 2003 Annual Reports under the heading entitled NOx Reductions for further information.

CERCLA, which imposes upon owners and previous owners of sites, as well as transporters and generators of hazardous material disposed of at such sites, costs for environmental remediation.

AEP does not, however, anticipate that any of its currently identified CERCLA-related issues will result in material costs or penalties to the AEP System. See Management's Financial Discussion and Analysis of Results of Operations, included in the 2003 Annual Reports, under the heading entitled Superfund and State Remediation for further information.

The Federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits. The EPA recently adopted a new Clean Water Act rule to reduce the number of fish and other aquatic organisms killed at once-through cooled power plants. See Management's Financial Discussion and Analysis of Results of Operations, included in the 2003 Annual Reports, under the heading entitled Clean abater Act Regulation for additional information.
Solid and hazardous waste laws and regulations, which govern the management and disposal of certain wastes. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion byproducts, which the EPA has determined are not hazardous waste governed subject to RCRA.In addition to imposing continuing compliance obligations, these lawvs and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions.

See Management's Financial Discussion and Analysis of Results of Operations, included in the 2003 Annual Reports, under the heading entitled Environmental Matters for information on current environmental issues.If our expenditures for pollution control technologies, replacement generation and associated operating costs are not recoverable from customers through regulated rates (in regulated jurisdictions) or market prices (in deregulated jurisdictions), those costs could adversely affect future results of operations and cash flows, and possibly financial condition. AEP's international operations are subject to environmental regulation by various authorities within the host countries. Under certain circumstances, these authorities may require modifications to these facilities and operations or impose fines and other costs for violations of applicable statutes and regulations. From time to time, these operations are named as parties to various legal claims, actions, complaints or other proceedings related to environmental matters. AEP's UK generation facilities will be subject to additional environmental constraints in 2008 (which become more stringent after 2015) because they are subject to regulation governing large combustion plants. In the fourth quarter of 2002, AEP decided not to install certain emission control technology on its Fiddler's Ferry and Ferrybridge generation facilities in 2008. This decision and its legal and regulatory consequences resulted in a significant reduction in the estimated economic life of those facilities. See also Investments-UK Operations for a discussion of AEP's planned disposition of these assets in 2004.The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System.See Management's Financial Discussion andAnalysis of Results ofOperations under the heading entitled Environmental Matters and Note 7 to the consolidated financial statements entitled Commitments and Contingencies, included in the 2003 Annual Reports, for further information with respect to environmental matters.Environmental Investments Investments related to improving AEP System plants' environmental performance and compliance with air and water quality standards during 2002 and 2003 and the current estimate for 2004 are shown below. Substantial investments in addition to the amounts set forth below are expected by the System in future years in connection with the modification and addition of facilities at generating plants for environmental quality controls in order to comply with air and water quality standards which have been or may be adopted. Future investments could be significantly greater if litigation regarding whether AEP properly installed emission control equipment on its plants is resolved against any AEP subsidiaries or emissions reduction requirements are accelerated or otherwise become more onerous. See Management's Financial Discussion and Analysis of Results of Operations under the headings entitled Future Reduction Requirementsfor NOx, SO 2 and Hg and Estimated Air Quality Investments Note 7 to the consolidated financial 7 statements, entitled Commitments and Contingencies, included in the 2003 Annual Reports, for more information regarding this litigation and environmental expenditures in general.2002 2003 2004 Actual Actual Fstimate.(in thousands) AEGCo ........................... $ 1,200 11,800 9,800 APCo ........................... 108,400 70,600 145,500 CSPCo...................................................... 25,400 31,400 18,000 I&M ....... .................... 1,200 14,900 12,100 KPCo ............................ 110,600 40,500 3,500 OPCo ........................... 110,300 40,000 108,400 PSO .......................... 1,200 1,700 0 SWEPCo .......................... 3,400 3,200 2,700 TCC .......................... 600 500 0 TNC .......................... 1,90 2.600 800 AEP System .............................. $...... 2 S.1.20IQ S.32M Electric and Magnetic Fields EMF are found everywhere there is electricity. Electric fields are created by the presence of electric charges. Magnetic fields are produced by the flow of those charges. This means that EMF are created by electricity flowing in transmission and distribution lines, electrical equipment, household wiring, and appliances. A number of studies in the past several years have examined the possibility of adverse health effects from EMF. While some of the epidemiological studies have indicated some association between exposure to EMF and health effects, none has produced any conclusive evidence that EMF does or does not cause adverse health effects.Management cannot predict the ultimate impact of the question of EMF exposure and adverse health effects. If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that. EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially adversely affected unless these costs can be recovered from customers. SEC Subpoena, CFTC Complaint ant Other Energ Afarket Investigations AEP received data requests, subpoenas and information requests from the SEC, CFTC and other state and federal governmental agencies relating to certain energy market investigations. On September 30, 2003, the CFTC filed a complaint against AEP in federal district court alleging that it provided false or misleading information about market conditions and prices of natural gas in an attempt to manipulate the price of natural gas. See Management's Financial Discussion and Analysis of Results of Operations, included in the 2003 Annual Reports, under the heading Energy Market Investigations. Utility Operations General Utility operations constitute the majority of AEP's business operations. Utility operations include (i) the generation, transmission and distribution of electric power to retail customers and (ii) the supplying and marketing of electric power at wholesale (through the electric generation function) to other electric utility companies, municipalities and other market participants. AEPSC, as agent for AEP's public utility subsidiaries performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities. Electric Generation Facilities AEP's public utility subsidiaries own approximately 38,000 MW of domestic generation. See Deactivation and Planned Disposition oaGenerating Facilities for a discussion of planned sales of certain of AEP's generating facilities. Pursuant to regulatory orders, the AEP public utility subsidiaries operate their generating facilities as a single interconnected and coordinated electric utility system. See Item 2 -Properties for more information regarding AEP's generation capacity.8 AEP Power Pool and CSI Operating Agreement APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (Interconnection Agreement), defining how they share the costs and benefits associated with their generating plants. This sharing is based upon each company's "member-load-ratio." The Interconnection Agreement has been approved by the FERC.The member-load ratio is calculated monthly by dividing such company's highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all east zone operating companies. As of December 31,2003, the member-load ratios were as follows: Peak Demand Member-Load (CNVN Ratio M%)APCo ................................ 6,873 31.7 CSPCo .............................. 3,871 17.9 I&M .................................. 4,243 19.6 KPCo ................................ 1,564 7.2 OPCo ................................ 5,121 23.6 Although the FERC has approved CSPCo's and OPCo's request to withdraw from the AEP Power Pool as part of its order approving the settlement agreements and AEP's FERC restructuring application, CSPCo and OPCo plan to remain functionally separated through at least December 31, 2008 as provided by their rate stabilization plan filed with the PUCO. See Management's Financial Discussion and Analysis and Financial Condition, under the heading entitled Corporate Separation, included in the 2003 Annual Reports and Note 6 to the consolidated financial statements, entitled Customer Choice and Industry Restructuring, included in the 2003 Annual Reports, for a discussion of AEP's corporate separation plan.The following table shows the net (credits) or charges allocated among the parties under the Interconnection Agreement and AEP System Interim Allowance Agreement during the years ended December 31,2001,2002 and 2003: 2001 2002 2003 (in thousands) APCo ................ $ 256,700 $ 127,000 $ 218,000 CSPCo ................ 251,200 267,000 276,800 I&M................................... (166,200) (113,600) (118,800)KPCo ................ 27,600 46,500 38,400 OPCo ................ (369,300) (326,900) (414,400)PSO, SWVEPCo, TCC, TNC, and AEPSC are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement), which has been approved by the FERC. The CSW Operating Agreement requires the west zone public utility subsidiaries to maintain adequate annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other AEP west zone public utility subsidiaries as capacity commitments. Parties are compensated for energy delivered to recipients based upon the deliverer's incremental cost plus a portion of the recipient's savings realized by the purchaser that avoids the use of more costly alternatives. Revenues and costs arising from third party sales are shared based on the amount of energy each west zone public utility subsidiary contributes that is sold to third parties. Upon the sale of its generation assets, TCC will no longer supply generating capacity under the CSW Operating Agreement. The following table shows the net (credits) or charges allocated among the parties under the CSW Operating Agreement during the years ended December 31,2001, 2002 and 2003: 2001 2002 2003 (in thousands) PSO .................. $ 6,500 $ 53,700 S 44,000 SWEPCo .................. (62,300) (67,800) (46,600)TCC ................. 13,500 (15,400) (29,500)TNC ................. 42,300 29,500 32,100 Power generated by or allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any public utility subsidiary is primarily sold to customers (or in the case of the ERCOT area of Texas, REPs) by such public utility subsidiary at 9 rates approved (other than in the ERCOT area of Texas) by the public utility commission in the jurisdiction of sale. In Ohio, Virginia and the ERCOT area of Texas, such rates are based on a statutory formula as those jurisdictions transition to the use of market rates for generation. See Regulation -Rates.Under both the Interconnection Agreement and CSW Operating Agreement, power generated that is not needed to serve the native load of any public utility subsidiary is sold in the wholesale market by AEPSC on behalf of the generating subsidiary. See Risk Management and Trading for a discussion of the trading and marketing of such power.AEP's System Integration Agreement, which has been approved by the FERC, provides for the integration and coordination of AEP's east and west zone operating subsidiaries. This includes joint dispatch of generation within the AEP System and the distribution, between the two zones, of costs and benefits associated with the transfers of power between the two zones (including sales to third parties and risk management and trading activities). It is designed to function as an umbrella agreement in addition to the Interconnection Agreement and the CSW Operating Agreement, each of which controls the distribution of costs and benefits within each zone.Risk Management and Trading AEPSC, as agent for AEP's public utility subsidiaries, sells excess power into the market and engages in power and natural gas risk management and trading activities focused in regions in which AEP traditionally operates. These activities primarily involve the purchase and sale of electricity (and to a lesser extent, natural gas) under physical forward contracts at fixed and variable prices. These contracts include physical transactions, over-the-counter swaps and exchange-traded futures and options. The majority of physical forward contracts are typically settled by entering into offsetting contracts. These transactions are executed with numerous counterparties or on exchanges. Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions. As of December 31, 2003, counterparties have posted approximately $45 million in cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP's public utility subsidiaries. Since open trading contracts are valued based on changes in market power prices, exposures change daily.Fuel Supply The following table shows the sources of power generated by the AEP System: 2001 2002 2003 Coal .............. 74% 78% 80%Natural Gas .............. 12% 8% 7%Nuclear.......................................................... 11% 11% 90/%Hydroelectric and other .............. 3% 3% 4%Variations in the generation of nuclear power are primarily related to refueling and maintenance outages. Variations in the generation of natural gas power are primarily related to the availability of cheaper alternatives to fulfill certain power requirements and the deactivation of certain gas-f ied plants owned by TCC and TNC.Coal and Lignite: AEP's public utility subsidiaries procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations, short-term, and spot agreements with various producers and coal trading firms.Management believes, but cannot provide assurances that, AEP's public utility subsidiaries will be able to secure coal and lignite of adequate quality and in adequate quantities to operate their coal and lignite-fired units. See Investments-Other for a discussion of AEP's coal marketing and transportation operations. The following table shows the amount of coal delivered to the AEP System during the past three years and the average delivered price of spot coal purchased by System companies: 2001 2002 2003 Total coal delivered to AEP operated plants (thousands of tons) ......... 73,889 76,442 76,042 Average price per ton of spot-purchased coal ....................................... $27.30 $27.06 $28.91 The coal supplies at AEP System plants vary from time to time depending on various factors, including customers' usage of electric power, space limitations, the rate of consumption at particular plants, labor issues and weather conditions which may interrupt 10 deliveries. At December 31, 2003, the System's coal inventory was approximately 42 days of normal usage. This estimate assumes that the total supply would be utilized through the operation of plants that use coal most efficiently. In cases of emergency or shortage, system companies have developed programs to conserve coal supplies at their plants. Such programs have been filed and reviewed with officials of federal and state agencies and, in some cases, the relevant state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agency.The FERC has adopted regulations relating, among other things, to the circumstances under which, in the event of fuel emergencies or shortages, it might order electric utilities to generate and transmit electric power to other regions or systems experiencing fuel shortages, and to ratemaking principles by which such electric utilities would be compensated. In addition, the federal government is authorized, under prescribed conditions, to allocate coal and to require the transportation thereof, for the use of power plants or major fuel-burning installations. Natural Gas: AEP, through its public utility subsidiaries, consumed over 138 billion cubic feet of natural gas during 2003 for generating power. A majority of the gas-fired power plants are connected to at least two natural gas pipelines, which provides greater access to competitive supplies and improves reliability. A portfolio of long-term and short-term purchase and transportation agreements (that are entered into on a competitive basis and based on market prices) supplies natural gas requirements for each plant.Nuclear: I&M and STPNOC have made commitments to meet certain of the nuclear fuel requirements of the Cook Plant and STP, respectively. Steps currently are being taken, based upon the planned fuel cycles for the Cook Plant, to review and evaluate l&M's requirements for the supply of nuclear fuel. I&M has made and will make purchases of uranium in various forms in the spot, short-term, and mid-term markets until it decides that deliveries under long-term supply contracts are warranted. TCC and the other STP participants have entered into contracts with suppliers for (i) 100% of the uranium concentrate sufficient for the operation of both STP units through spring 2006 and (ii) 50% of the uranium concentrate needed for STP through spring 2007. See Deactivation and Planned Disposition of Generation Facilities for more information about TCC's interest in STP.For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel storage pool. AEP anticipates that the Cook Plant has storage capacity to permit normal operations through 2012.STP has on-site storage facilities with the capability to store the spent nuclear fuel generated by the STP units over their licensed lives.Nuclear Waste and Decommissioning l&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP, have a significant future financial commitment to safely dispose of spent nuclear fuel and decommission and decontaminate the plants. The ultimate cost of retiring the Cook Plant and STP may be materially different from estimates and funding targets as a result of the:* Type of decommissioning plan selected;* Escalation of various cost elements (including, but not limited to, general inflation);

Further development of regulatory requirements governing decommissioning;
Limited availability to date of significant experience in decommissioning such facilities;
Technology available at the time of decommissioning differing significantly from that assumed in these studies;* Availability of nuclear waste disposal facilities; and* Approval of the Cook Plant's license extension.

Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant and STP will not be significantly different than current projections. 11I See Management's Financial Discussion and Analysis of Results of Operations and Note 7 to the consolidated financial statements, entitled Commitments and Contingencies, included in the 2003 Annual Reports, for information with respect to nuclear waste and decommissioning and related litigation. Low-Level Radioactive Waste: The LLWPA mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. Michigain and Texas do not currently have disposal sites for such waste available. AEP cannot predict when such sites may be available, but South Carolina and Utah operate low-level radioactive waste disposal sites and accept low-level radioactive waste from Michigan and Texas. AEP's access to the South Carolina facility is currently allowed through the end of fiscal year 2008. There is currently no set date limiting AEP's access to the Utah facility.Deactivation and Planned Disposition of Generation Facilities In September 2002, AEP indicated to ERCOT its intent to deactivate 16 gas-fired power plants (8 TCC plants and 8 TNC plants).ERCOT subsequently conducted reliability studies that determined that seven plants (4 TCC plants and 3 TNC plants) would be required to ensure reliability of the electricity grid. As a result of these studies, ERCOT and AEP mutually agreed to enter into reliability must run agreements to continue operation of these seven plants. With ERCOT's approval, AEP deactivated the remaining nine plants. The agreements allowed ERCOT to terminate the agreement with 90 days notice if the facility was no longer needed to ensure reliability of the electricity grid. ERCOT provided such notice with respect to one TNC plant in August 2003 and the plant was deactivated. AEP and ERCOT agreed to new reliability must run contracts at the remaining six plants through December 2004, subject to the same termination provision. TCC is conducting an auction to sell all of its generation facilities in Texas to establish the market value of the assets and TCC's stranded costs in accordance with the Texas Act. See Texas Regulatory Assets and Stranded Cost Recovery and Post-Restructuring Wires Charges. The competitive bidding process began in June 2003 after the PUCT issued a rule confirming TCC's ability to establish the value of its generation assets and amount of stranded costs by selling the generation assets. The PUCT has engaged a consultant and designated a team to monitor the auction and advise TCC on the sale of its generating assets, including requirements of the Texas Act for establishing stranded costs.The assets to be sold have a generating capacity of 4,497 MW and include eight gas-fired generating plants, one coal-fired plant, TCC's interest in Oklaunion Power Station, a hydroelectric facility and TCC's interest in STP. TCC has entered into agreements to sell its 7.8% share of Oklaunion Power Station and 25.2% share in STP and is continuing to evaluate bids for its remaining generation assets. See Note 6 to the consolidated financial statements entitled Customer Choice and Industry Restructuring, included in the 2003 Annual Reports, for more information on the planned disposition of TCC generation facilities. StructuredArrangements Involving Capacity, Energy, andAncillary Services In January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an agreement relating to the construction and operation of a 510 MW gas-fired electric generating peaking facility to be owned by NPC. OPCo is entitled to 100% of the power generated by the facility, and is responsible for the fuel and other costs of the facility through 2005. After 2005, NPC and OPCo will be entitled to 80W and 20%, respectively, of the power of the facility, and both parties will generally be responsible for the fuel and other costs of the facility.Certain Power Agreements AEGCo: Since its formation in 1982, AEGCo's business has consisted of the ownership and financing of its 50% interest in Unit I of the Rockport Plant and, since 1989, leasing of its 50% interest in Unit 2 of the Rockport Plant. The operating revenues of AEGCo are derived from the sale of capacity and energy associated with its interest in the Rockport Plant to I&M and KPCo pursuant to unit power agreements, which have been approved by the FERC.The I&M Power Agreement provides for the sale by AEGCo to I&M of all the capacity (and the energy associated therewith) available to AEGCo at the Rockport Plant. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M). Such amounts, when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power 12 Agreement will continue in effect until the date that the last of the lease terms of Unit 2 of the Rockport Plant has expired unless extended in specified circumstances. Pursuant to an assignment between l&M and KPCo, and a unit power agreement between KPCo and AEGCo, AEGCo sells KPCo 30% of the capacity (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo has agreed to pay to AEGCo the same amounts which l&M would have paid AEGCo under the terms of the l&M Power Agreement for such entitlement. The KPCo unit power agreement expires on December 31, 2004.AEGCo and AEP have entered into a capital funds agreement pursuant to which, among other things, AEP has unconditionally agreed to make cash capital contributions, or in certain circumstances subordinated loans, to AEGCo to the extent necessary to enable AEGCo to (i) maintain such an equity component of capitalization as required by governmental regulatory authorities; (ii) provide its proportionate share of the funds required to permit commercial operation of the Rockport Plant; (iii) enable AEGCo to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party (AEGCo Agreements); and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo Obligations) under the AEGCo Agreements, other than indebtedness, obligations or liabilities owing to AEP. The capital funds agreement will terminate after all AEGCo Obligations have been paid in full.OVEC: AEP, CSPCo and several unaffiliated utility companies jointly own OVEC. The aggregate equity participation of AEP and CSPCo in OVEC is 44.2%. Until September 1, 2001, OVEC supplied from its generating capacity the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the DOE. The sponsoring companies are now entitled to receive and pay for all OVEC capacity (approximately 2,200 MW) in proportion to their power participation ratios. The aggregate power participation ratio of APCo, CSPCo, I&M and OPCo is 42.1%. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and to provide a return on its equity capital. The Inter-Company Power Agreement, which defines the rights of the owners and sets the power participation ratio of each, will expire by its terms on March 12, 2006. The AEP-affiliated owners of OVEC are evaluating the need for environmental investments related to their ownership interests. Buckeye: Contractual arrangements among OPCo, Buckeye and other investor-owned electric utility companies in Ohio provide for the transmission and delivery, over facilities of OPCo and of other investor-owned utility companies, of power generated by the two units at the Cardinal Station owned by Buckeye and back-up power to which Buckeye is entitled from OPCo under such contractual arrangements, to facilities owned by 25 of the rural electric cooperatives which operate in the State of Ohio at 342 delivery points. Buckeye is entitled under such arrangements to receive, and is obligated to pay for, the excess of its maximum one-hour coincident peak demand plus a 15% reserve margin over the 1,226,500 kilowatts of capacity of the generating units which Buckeye currently owns in the Cardinal Station. Such demand, which occurred on January 23,2003, was recorded at 1,409,726 kilowatts. Electric Transmission and Distribution General AEP's public utility subsidiaries (other than AEGCo) own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2-Properties for more information regarding the transmission and distribution lines. Most of the transmission and distribution services are sold, in combination with electric power, to retail customers of AEP's public utility subsidiaries in their service territories. These sales are made at rates established and approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC. See Regulation-Rates. The FERC regulates and approves the rates for wholesale transmission transactions. See Regulation-FERC. As discussed below, some transmission services also are separately sold to non-affiliated companies. AEP's public utility subsidiaries (other than AEGCo) hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the exclusive right to provide electric service. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business. For a discussion of competition in the sale of power, see Competition. 13 AEP Transmission Pool Transmission Equalization Agreement: APCo, CSPCo, I&M, KPCo and OPCo operate their transmission lines as a single interconnected and coordinated system and are parties to the Transmission Equalization Agreement, dated April 1, 1984, as amended (TEA), defining how they share the costs and benefits associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 KV and above) and certain.facilities operated at lower voltages (138 KV and above). The TEA has been approved by the FERC. Sharing under the TEA is based upon each company's "member-load ratio." The member-load ratio is calculated monthly by dividing such company's highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all east zone operating companies. As of December 31, 2003, the member-load ratios were as follows: APCo................................. CSPCo............................... I& M ................................... KPCo................................. OPCo................................. Peak Demand (NINN)6,873 3,871 4,243 1,564 5,121 lMIember-Lzad Ratio M%)31.7 17.9 19.6 72 23.6 The following table shows the net (credits) or charges allocated among the parties to the TEA during the years ended December 31,2001,2002 and 2003: APCo............................................... CSPCo............................................. I&M ................................................. KPCo............................................... OPCo............................................... 2001 2002 (in thousands) $ (3,100) $ (13,400)40,200 42,200 (41,300) (36,100)(4,600) (5,400)8,800 12,700 2003 S 0 38,200 (39,800)(5,600)7,200'Transmission Coordination Agreement: PSO, SWEPCo, TCC, TNC and AEPSC are parties to a Transmission Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA has been approved by the FERC and establishes a coordinating committee, Which is charged with the responsibility of overseeing the coordinated planning of the transmission facilities of the west zone public utility subsidiaries, including the performance of transmission planning studies, the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff.Under the TCA, the west zone public utility subsidiaries have delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the AEP OATT on their behalf. The TCA also provides for the allocation among the west zone public utility subsidiaries of revenues collected for transmission and ancillary services provided under the AEP OATT.The following table shows the net (credits) or charges allocated among the parties to the TCA during the years ended December 31,2001,2002 and 2003: 2001 2002 (in thousands) PSO ........................ $ 4,000 $ 4,200 SWEPCo ......................... 5,400 5,000 TCC ........................ (3,900) (3,600)TNC ........................ (5,500) (5,600)2003$ 4,200 5,000 (3,600)(5,600)Transmission Services for Non-Affiliates: In addition to providing transmission services in connection with their own power sales, AEP's public utility subsidiaries and other System companies also provide transmission services for non-affiliated companies. See Regional Transmission Organizations. AEP's public utility subsidiaries are subject to regulation by the FERC under the FPA in respect of transmission of electric power.14 Coordination of East and West Zone Transmission: AEP's System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP's east and west zone public utility subsidiaries. The System Transmission Integration Agreement functions as an umbrella agreement in addition to the TEA and the TCA. The System Transmission Integration Agreement contains two service schedules that govern: v The allocation of transmission costs and revenues and* The allocation of third-party transmission costs and revenues and System dispatch costs.The System Transmission Integration Agreement contemplates that additional service schedules may be added as circumstances warrant.Regional Transmission Organizations On April 24, 1996, the FERC issued orders 888 and 889. These orders require each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff that reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. In addition, the orders require all transmitting utilities to establish an Open Access Same-time Information System (OASIS), which electronically posts transmission information such as available capacity and prices, and require utilities to comply with Standards of Conduct that prohibit utilities' system operators from providing non-public transmission information to the utility's merchant energy employees. The orders also allow a utility to seek recovery of certain prudently incurred stranded costs that result from unbundled transmission service.In December 1999, FERC issued Order 2000, which provides for the voluntary formation of RTOs, entities created to operate, plan and control utility transmission assets. Order 2000 also prescribes certain characteristics and functions of acceptable RTO proposals. AEP is required, as a condition of FERC's approval in 2000 of AEP's merger with CSW, to transfer functional control of its transmission facilities to one or more RTOs. In May 2002, AEP announced an agreement with PJM to pursue terms for its east zone public utility subsidiaries to participate in PJM, a FERC-approved RTO. In July 2002, the FERC tentatively approved AEP subsidiaries' decision to join PJM, subject to certain conditions being met. The satisfaction of these conditions may only be partially within AEP's control.In December 2002, AEP's public utility subsidiaries filed applications with the state utility commissions of Indiana, Kentucky, Ohio and Virginia requesting approval of the transfer of functional control of transmission assets in those states to PJM. The status of these applications is as follows:* The IURC conditionally approved the transfer of functional control of I&M's transmission assets to an RTO in September 2003, though the satisfaction of these conditions is not fully within I&M's or AEP's control;* In July 2003, the KPSC denied KPCo's request to join PJM based on a lack of evidence that it would benefit Kentucky retail customers, but granted KPCo's request for rehearing. KPCo filed a cost/benefit study in December 2003 and a rehearing has been scheduled for April 2004;* CSPCo and OPCo filed an application seeking approval of their plan to join PJM in December 2002. In addition, a group of complainants have filed a complaint with the PUCO alleging that CSPCo and OPCo have violated Ohio law by not participating in an RTO and seeking (i) a suspension of certain transmission-related charges to customers, (ii) requiring that CSPCo and OPCo continue to offer service at the prices set forth in their 1999 transition plan filing until January 1, 2006 and (iii) a penalty of $25,000 for each day that CSPCo and OPCo do not participate in an RTO. The PUCO consolidated our application with the complaint in February 2003. The PUCO has stayed the matter pending greater clarification with respect to RTO matters at the FERC and elsewhere;

In February 2003, the Virginia legislature enacted legislation that would prohibit the transfer of functional control of transmission assets to an RTO until at least July 2004 and thereafter only with VSCC approval.

The legislation requires a transfer by January 2005. In January 2004, APCo filed a supplement to its application with the VSCC consisting of a is cost/benefit analysis of its participation in PJM and additional information required by the VSCC. A hearing on APCo's Virginia application is scheduled for July 2004.In November 2003, the FERC issued an order (i) proposing to exempt AEP's east zone public utility subsidiaries from Kentucky and Virginia laws requiring state approval of the AEP east zone public utility subsidiaries' transfer of functional control of their transmission assets to an RTO and (ii) directing AEP's east zone public utility subsidiaries to join PJM by October 1, 2004. Several issues, including whether the FERC may exempt AEP's east zone public utility subsidiaries from Kentucky and Virginia law preventing them from joining an RTO, have been heard by an administrative law judge. The FERC has directed that an initial decision be issued by the AU by March 15,2004.SWVEPCo and PSO currently intend to transfer functional control of their transmission assets to SPP subject to receipt of appropriate regulatory approvals. In February 2004, the FERC conditionally approved SPP as an RTO. The Arkansas Public Service Commission and LPSC have required filings related to SWEPCo's and PSO's transfer of functional control of transmission facilities to an RTO. The remaining west zone public utility subsidiaries (TCC and TNC) are members of ERCOT.See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2003 Annual Reports and Management's Financial Discussion and Analysis of Results of Operations under the heading entitled RTO Formation for a discussion of public utility subsidiary participation in RTOs.Regional Through and Out Rates The FERC has proposed to eliminate our ability to collect certain transmission charges associated with the transmission assets of our east zone public utility subsidiaries and implement transitional rates to mitigate the lost revenues for a two-year period commencing May 1, 2004. The FERC did not indicate how or if the lost revenues would be recovered after the expiration of the transitional rates. Management, however, believes that we are entitled to recover costs of owning and operating these facilities, including a reasonable rate of return. See Management's Financial Discussion and Analysis of Results of Operations under the heading entitled FERC Order on Regional Through and Out Rates for more information. Regulation General Except for retail generation sales in Ohio, Virginia and the ERCOT area of Texas, AEP's public utility subsidiaries' retail rates and certain other matters are subject to traditional regulation by the state utility commissions. Retail sales in Michigan, while still regulated, are now made at unbundled rates. Other states in AEP's service territory have also passed restructuring legislation that has not been implemented or has been repealed. See Electric Restructuring and Customer Choice Legislation and Rates. AEP's subsidiaries are also subject to regulation by the FERC under the FPA. I&M and TCC are subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant and STP, respectively. AEP and certain of its subsidiaries are also subject to the broad regulatory provisions of PUHCA administered by the SEC.Rates Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. A utility's cost of service generally reflects its operating expenses, including operation and maintenance expense, depreciation expense and taxes. State utility commissions periodically adjust rates pursuant to a review of (i) a utility's revenues and expenses during a defined test period and (ii) such utility's level of investment. Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time as part of a transition to customer choice of generation suppliers, a state utility commission can review and change rates on its own initiative. Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers. Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.The rates of AEP's public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service). In Ohio, Virginia and the ERCOT area of Texas, rates are transitioning from bundled cost-based rates for electric service to unbundled cost-based rates for transmission and distribution service on the one hand, and market pricing for and/or customer choice of generation on the other.16 Historically, the state regulatory frameworks in the service area of the AEP System reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility's rates and tariffs. Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes. While the historical framework remains in a portion of AEP's service territory, recovery of increased fuel costs is no longer provided for in Ohio. Fuel recovery is also limited in the ERCOT area of Texas, but because AEP sold MECPL and MEWTU, there is little impact on AEP of fuel recovery procedures related to service in ERCOT.The following state-by-state analysis summarizes the regulatory environment of each jurisdiction in which AEP operates. Several public utility subsidiaries operate in more than one jurisdiction. Indiana: I&M provides retail electric service in Indiana at a bundled rate approved by the IURC. While rates are set on a cost-of-service basis, utilities may also generally seek to adjust fuel clause rates quarterly. l&M's base rate is capped through December 31, 2004. Its fuel recovery rate was capped through February 29,2004 but is expected to return to traditional cost recovery.Ohio: CSPCo and OPCo each operates as a functionally separated utility and provides "default" retail electric service to customers at unbundled rates pursuant to the Ohio Act through December 31, 2005. Market-based default retail generation service rates will be determined in accordance with PUCO rules after December 31, 2005, unless the rate stabilization plan filed by CSPCo and OPCo (which, among other things, addresses default retail generation service rates from January 1, 2006 through December 31, 2008) is approved by the PUCO, in which case retail generation rates would be determined consistent with the rate stabilization plan until December 31, 2008. CSPCo and OPCo are and will continue to provide distribution services to retail customers at rates approved by the PUCO. These rates will be frozen from their levels as of December 31, 2005 to (i) December 31, 2008 for CSPCo and (ii)December 31, 2007 (December 31, 2008, if the rate stabilization plan is approved) for OPCo. Transmission services will continue to be provided at rates established by the FERC. See Note 6 to the consolidated financial statements, entitled Customer Choice and Industry Restructuring, included in the 2003 Annual Reports, for more information. Oklahoma: PSO provides retail electric service in Oklahoma at a bundled rate approved by the OCC. PSO's rates are set on a cost-of-service basis. Fuel and purchased energy costs above the amount included in base rates are recovered by applying a fuel adjustment factor to retail kilowatt-hour sales. The factor is adjusted quarterly and is based upon forecasted fuel and purchased energy costs. Over or under collections of fuel costs for prior periods can be recovered when new quarterly factors are established. See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2003 Annual Reports, for information regarding current rate proceedings. Texas: The Texas Act requires the legal separation of generation-related assets from transmission and distribution assets. TCC and TNC currently operate on a functionally separated basis. In January 2002, TCC and TNC transferred all their retail customers in the ERCOT area of Texas to MECPL, MEWTU and AEP Commercial and Industrial REP (an AEP affiliate). TNC's retail SPP customers were ultimately transferred to Mutual Energy SWEPCo L.P. (an AEP affiliate). TCC and TNC provide retail transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules. See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2003 Annual Reports, for information on current rate proceedings. In May 2003, the PUCT delayed competition in the SPP area of Texas until at least January 1, 2007. As such, SWEPCo's Texas operations continue to operate and to be regulated as a traditional bundled utility uvith both base and fuel rates.Virginia: APCo provides unbundled retail electric service in Virginia. APCo's unbundled generation, transmission (which reflect FERC approved transmission rates) and distribution rates as well as its functional separation plan were approved by the VSCC in December 2001.The Virginia Act capped base rates at their mid-1999 levels until the end of the transition period (July 1, 2007), or sooner if the VSCC finds that a competitive market for generation exists in Virginia. The Virginia Act permits APCo to seek a one-time change to its capped non-generation rates after January 1, 2004. The Virginia Act allows adjustments to fuel rites during the transition period and continues to permit utilities to recover their actual fuel costs, the fuel component of their purchased power costs and certain capacity charges. APCo recovers its generation capacity charges through capped base rates.JVest Virginia: APCo and Wheeling Power Company provide retail electric service at bundled rates approved by the WVPSC. A plan to introduce customer choice was approved by the West Virginia Legislature in its 2000 legislative session. However, 17 implementation of that plan was placed on hold pending necessary changes to the state's tax laws in a subsequent session. Those changes have not been made. Management currently believes that implementation of the plan is unlikely.While West Virginia generally allows recovery of fuel costs, the most recent proceeding resulted in the suspension of an active fuel clause for APCo and WPCo (though they continue to recover fuel costs through fixed bundled rates). APCo and Wheeling Power Company are currently unable to change the current level of fuel cost recovery, though this ability could be reinstated in a future proceeding. Other Jurisdictions: The public utility subsidiaries of AEP also provide service at regulated bundled rates in Arkansas, Kentucky, Louisiana and Tennessee and regulated unbundled rates in Michigan.The table below illustrates the current rate regulation status of the states in which the public utility subsidiaries of AEP operate: Percentage Fuel Clau-e Rates OfAEP System Sales System StatuS or Base Rates for Profits Shared Retail Jurisdiction Power Supply Enermv Delivery Statirs Includes w/Ratepavers Revenuei(1) Ohio Frozen through 2005(2) Distribution frozen None Not applicable Not applicable 32%through 2007 for OPCo and 2008 for CSP;Transmission frozen through 2005 Texas- ERCOT (TCC, TNC) See footnote 3 Not capped or frozen Not applicable Not applicable Not applicable 90/o(3)Texas- SPP (SWEPCo, TNC) Not capped or frozen Active Fuel and fuel Yes, above base 5%portion of levels purchased power Oklahoma Not capped or frozen Active Fuel and fuel Yes 13%portion of purchased power Indiana Capped until 1/1/05(4) Active Fuel and fuel No 10 0%portion of purchased power Virginia Capped until as late Capped until as late Active Fuel and fuel No 9%/0 as 7/1/07(5) as 7/1/07(5) portion of purchased power West Virginia Not capped or frozen Suspended(6) Fuel and fuel Yes, but 9%/0 portion of suspended purchased power Louisiana Capped until 6/15/05 Active Fuel and fuel Yes, above base 4%portion of levels purchased power Kentucky(7) Not capped or frozen Active Fuel and fuel Yes, above base 4%portion of levels purchased power Arkansas Not capped or frozen Active Fuel and fuel Yes, above base 2%portion of levels purchased power Michigan Capped until /1/05(8) Capped until /1/05(8) Active Fuel and fuel Yes, in somne 2%portion of areas purchased power Tennessee Not capped or frozen Active Fuel and fuel No 1%portion of purchased power (1) Represents the percentage of revenues from sales to retail customers from AEP utility companies operating in each state to the total AEP System revenues from sales to retail customers for the year ended December 31, 2003.18 (2) CSPCo and OPCo have filed a rate stabilization plan with the PUCO to establish (after the market development period) a rate stabilization period from January 1, 2006 through December 31, 2008 during which their default retail generation rates would be established pursuant to such filing. The rate stabilization plan would also extend OPCo's distribution rate freeze through the end of 2008.(3) Retail electric service in the ERCOT area of Texas is provided to most customers through unaffiliated REPs which must offer PTB rates until January 1,2007.(4) Capped base rates pursuant to a 1999 settlement with base rate freeze extended pursuant to merger stipulation. (5) Base rates are capped until the earlier of July 1, 2007 or a finding by the VSCC that a competitive market for generation exists.One-time change in non-generation rates is allowed in Virginia.(6) Expanded net energy clause suspended in West Virginia pursuant to a 1999 rate case stipulation, but subject to change in a future proceeding. (7) KPCo applied for an environmental surcharge to recover costs incurred in connection with the installation of emission control equipment and in 2003 the KPSC granted recovery of $18 million.(8) Capped base and fuel rates pursuant to a 1999 settlement and base rates extended pursuant to merger stipulation. FERC Under the FPA, FERC regulates rates for interstate sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. FERC regulations require AEP to provide open access transmission service at FERC-approved rates. The transmission service regulated by FERC is predominantly wholesale transmission service, which is service not associated with bundled electricity sales to retail customers. FERC also regulates unbundled transmission service to retail customers. Under the FPA, the FERC regulates the sale of power for resale in interstate commerce by (i) approving contracts for wholesale sales to municipal and cooperative utilities and (ii) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices. AEP has market-rate authority from FERC, under which most of its wholesale marketing activity takes place. In November 2001, the FERC issued an order in connection with its triennial review of AEP's market based pricing authority requiring (i) certain actions by AEP in connection with its sales and purchases within its control area and (ii) posting of information related to generation facility status on AEP's website. AEP has appealed this order, and the FERC has issued an order delaying the effective date of the order. This was done in connection with the FERC's adoption of a new test called supply management assessment (SMA). In December 2003, the FERC issued a staff paper discussing alternatives to SMA and held a technical conference in January 2004. See Note 7 to the consolidated financial statements, entitled Commitments and Contingencies, included in the 2003 Annual Reports, for more information on the current status of this proceeding. Electric Restructuring and Customer Choice Legislation Certain states in AEP's service area have adopted restructuring or customer choice legislation. In general, this legislation provides for a transition from bundled cost-based rate regulated electric service to unbundled cost-based rates for transmission and distribution service and market pricing for the supply of electricity with customer choice of supplier. At a minimum, this legislation allows retail customers to select alternative generation suppliers. Electric restructuring and/or customer choice began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan, Virginia and the ERCOT area of Texas. Electric restructuring in the SPP area of Texas has been delayed by the PUCT until at least 2007. AEP's public utility subsidiaries operate in both the ERCOT and SPP areas of Texas.Implementation of legislation enacted in West Virginia to allow retail customers to choose their electricity supplier is on hold.Before West Virginia's choice plan can be effective, tax legislation must be passed to preserve pre-legislation levels of funding for state and local governments. No further legislation has been passed. Management currently believes that implementation of the plan is unlikely. In February 2003, Arkansas repealed its restructuring legislation. 19 See Note 5 to the consolidated financial statements, entitled Effects of Regulation, included in the 2003 Annual Reports, for a discussion of the effect of restructuring and customer choice legislation on accounting procedures. See Note 6 to the consolidated financial statements entitled Customer Choice and Industry Restructuring and Mfanagement's Financial Discussion and Analysis and Financial Condition, included in the 2003 Annual Reports, under the heading entitled Corporate Separation for a discussion of AEP's corporate separation plan.Michigan Customer Choice Customer choice commenced for I&M's Michigan customers on January 1, 2002. Rates for retail electric service for I&M's Michigan customers were unbundled (though they continue to be regulated) to allow customers the ability to evaluate the cost of generation service for comparison with other suppliers. At December 31, 2003, none of I&M's Michigan customers had elected to change suppliers and no alternative electric suppliers are registered to compete in I&M's Michigan service territory. Ohio Restructuring The Ohio Act requires vertically integrated electric utility companies that offer competitive retail electric service in Ohio to separate their generating functions from their transmission and distribution functions. Following the market development period (which will terminate no later than December 31, 2005), retail customers will receive distribution and, where applicable, transmission service from the incumbent utility whose distribution rates will be approved by the PUCO and whose transmission rates will be approved by the FERC. CSPCo and OPCo have filed a rate stabilization plan with the PUCO that, among other things, addresses default generation service rates from January 1, 2006 through December 31, 2008. See Regulation-FERC for a discussion of FERC regulation of transmission rates and Regulation-Rates-Ohio for a discussion of the impact of restructuring on distribution rates. If the PUCO approves the rate stabilization plan filed by CSPCo and OPCo, they will remain functionally separated through at least December 31,2008.Texas Restructuring Signed into law in June of 1999, the Texas Act substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail electric competition for all customers. Among other things, the Texas Legislation:

gave Texas customers the opportunity to choose their REP beginning January 1, 2002 (delayed until at least 2007 in the SPP portion of Texas), required each utility to legally separate into a REP, a power generation company, and a transmission and distribution utility, and* required that REPs obtain electricity at generally unregulated rates, except that the prices that may be charged to residential and small commercial customers by REPs affiliated with a utility within the affiliated utility's service area are set by the PUCT, at the PTB, until certain conditions in the Texas Legislation are met.The Texas Act provides each affected utility an opportunity to recover its generation related regulatory assets and stranded costs resulting from the legal separation of the transmission and distribution utility from the generation facilities and the related introduction of retail electric competition.

Regulatory assets consist of the Texas jurisdictional amount of generation-related regulatory assets and liabilities in the audited financial statements as of December 31, 1998. Stranded costs consist of the positive excess of the net regulated book value of generation assets (as of December 31, 2001) over the market value of those assets, taking specified factors into account, as ultimately determined in a PUCT true-up proceeding (the True-Up Proceeding). For a discussion of (i) regulatory assets and stranded costs subject to recovery by TCC and (ii) rate adjustments made after implementation of restructuring to allow recovery of certain costs by or with respect to TCC and TNC, see Texas Regulatory Asset and Stranded Cost Recovery and Post-Restructuring Wires Charges.Virginia Restructuring The Virginia Act was enacted in 1999 providing for retail choice of generation suppliers to be phased in over the January 1, 2002 to January 1, 2004 period. The Virginia Act required jurisdictional utilities to unbundle their power supply and energy delivery rates and to file functional separation plans by January 1, 2002. APCo filed its plan and, following VSCC approval of a settlement agreement, now operates in Virginia as a functionally separated electric utility charging unbundled rates for its retail sales of 20 electricity. The settlement agreement addressed functional separation, leaving decisions related to legal separation for later VSCC consideration. Texas RegulatoryAssets and Stranded Cost Recovery and Post-Restructuring 1J7res Charges TCC and TNC may recover generation-related regulatory assets and plant-related stranded costs. Regulatory assets consist of the Texas jurisdictional amount of generation-related regulatory assets and liabilities in the audited financial statements as of December 31, 1998. Plant-related stranded costs consist of the positive excess of the net regulated book value of generation assets (as of December 31, 2001) over the market value of those assets, taking specified factors into account. The Texas Act allows alternative methods of valuation to determine the fair market value of generation assets, including outright sale, full and partial stock valuation and asset exchanges, and also, for nuclear generation assets, the ECOM model.The Texas Act further permits utilities to establish a special purpose entity to issue securitization bonds for the recovery of generation-related regulatory assets and, after the 2004 true-up proceeding, the amount of plant-related stranded costs and remaining generation-related regulatory assets not previously securitized. Securitization bonds allow for regulatory assets and plant-related stranded costs to be refinanced with recovery of the bond principal and financing costs ensured through a non-bypassable rate surcharge by the regulated transmission and distribution utility over the life of the securitization bonds. Any plant-related stranded costs or generation-related regulatory assets not recovered through the sale of securitization bonds may be recovered through a separate non-bypassable competitive transition charge to transmission and distribution customers. Generation-Related Regulatory Assets TIn 1999, TCC filed an application with the PUCT to securitize approximately $1.27 billion of its retail generation-related regulatory assets and approximately $47 million in other qualified restructuring costs. On March 27, 2000, the PUCT issued an order authorizing issuance of up to $797 million of securitization bonds including $764 million for recovery of net generation-related regulatory assets and $33 million for other qualified refinancing costs. The securitization bonds were issued in February 2002. TCC has included a transition charge in its distribution rates to repay the bonds over a 14-year period. Another $185 million of regulatory assets are being recovered through distribution rates beginning in January 2002. Remaining generation related regulatory assets of approximately $195 million will be included in TCC's request to recover stranded costs in the True-Up Proceeding. Plant-Related Stranded Costs It is anticipated that TCC will have significant plant-related stranded costs following the planned sale of its generation assets.As noted, stranded costs are ultimately determined in the True-Up Proceeding. The PUCT adopted a rule regarding the timing of the True-Up Proceedings scheduling TNC's filing (which has no generation related stranded costs) in May 2004 and TCC's filing in September 2004 or 60 days after the completion of the sale of TCC's generation assets, if later.2004 True-Up Proceedings The purpose of the True-Up Proceeding is to (i) quantify and reconcile the amount of plant-related stranded costs and generation-related regulatory assets taking into account amounts that have not been securitized; (ii) conduct wholesale capacity auction true-ups; (iii) establish final fuel recovery balances; (iv) determine the retail clavback component; and (v) quantify unrefunded excess earnings (collectively, the True-Up Adjustment). The True-Up Adjustment will be reflected as either additional charges or credits to retail customers through transmission and distribution rates collected by REPs and remitted to the utility.After final determination of True-Up Adjustments by the PUCT, TCC may issue securitization bonds in an amount equal to the sum of (i) its plant-related stranded costs ( vhere applicable) and (ii) generation-related regulatory assets, less its generation-related regulatory assets that have been previously securitized. If securitization bonds are not issued to finance all such amounts, TCC will seek recovery of these amounts as well as the other components of the True-Up Adjustments through non-bypassable competition transition charges in transmission and distribution rates.Plant-Related Stranded Cost Determination: The Texas Legislation authorized the use of several valuation methodologies to quantify plant-related stranded costs in the True-Up Proceeding, including by the sale of assets. TCC intends to sell its generation assets in order to obtain their market value for the purpose of determining plant-related stranded costs for the True-Up Proceeding and comply with the Texas Legislation. In the True-Up Proceeding, the amount of plant-related stranded costs under this market valuation 21 methodology will be the amount by which net book value of TCC's generating assets exceeds the market value of the generation assets as measured by the net proceeds from the sale of the assets.Wholesale Capacity Auction True-Up Component. The PUCT used a computer model or projection, called an ECOM model, to estimate stranded costs related to generation plant assets in the unbundled cost of service proceedings. See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2003 Annual Reports for further. discussion. In connection with using the ECOM model to calculate the stranded cost estimate, the PUCT estimated the market power prices that will be received in the competitive wholesale generation market. Any difference between the ECOM model market prices and actual market power prices as measured by generation capacity auctions required by the Texas Legislation during the period of January 1, 2002 through December 31, 2003 will be a component of the True-Up Proceeding, either increasing or decreasing the amount of recovery for TCC. Actual market prices have been lower than the ECOM model market prices. Therefore, TCC recorded a S480 million regulatory asset and related revenues for 2002 and 2003.Fuel Recovery Balance Determination: The fuel component will be determined by the amount of fuel costs and expenses the PUCT approves based on a final fuel reconciliation that TCC and TNC have filed. In 2002, TNC filed with the PUCT to reconcile fuel costs and to defer any unrecovered portion applicable to retail sales within its ERCOT service area for inclusion in the True-Up Proceeding. In January 2004, the PUCT announced a final ruling in TNC's fuel reconciliation case that established TNC's unrecovered fuel balance, including interest for the ERCOT service territory, at $6.2 million. This balance will be included in TNC's 2004 true-up proceeding. In 2002, TCC filed with the PUCT to reconcile fuel costs and to establish its deferred over-recovery of fuel balance for inclusion in the 2004 True-Up Proceeding. In February 2004, an ALJ issued recommendations finding a $205 million over-recovery in this fuel proceeding. See TCC Fuel Reconciliation and TNC Fuel Reconciliation in Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2003 Annual Reports, for further discussion. Any over-recovery, plus interest thereon, will be credited to customers as a component of the True-Up Proceeding. Retail Clavback Component: The Texas Legislation provides for each price to beat (PTB) retail electricity provider (REP) to refund to its affiliated transmission and distribution utility the excess of the PTB revenues over market prices (subject to certain conditions and a limitation of $150 per customer). This retail clawback applies only to the (i) residential and (ii) small commercial classes of customers. If 40% of the load for such customer class is'served by competitive REPs, the retail clawback is not applied for such class. During 2003, TCC and TNC filed to notify the PUCT that competitive REPs serve over 40% of the load in the small commercial class. The PUCT has ruled that this threshold has been met with respect to the small commercial class for each of TCC and TNC. AEP had accrued a total regulatory liability of approximately $66 million for all obligations related to retail clawback on its REP's books. As a result of the PUCT ruling on the small commercial retail clawback, $9 million of this regulatory liability was no longer required and was reversed.Unrefunded Excess Earnings Component: The Texas Legislation provides, as a component of the True-Up Proceeding, for an earnings test each year from 1999 through 2001. The Texas Legislation requires PUCT approval of the annual earnings test calculation. The PUCT has ruled that each of SWEPCo, TCC and TNC has excess earnings and, in certain instances, has ordered a reduction in distribution rates for the purpose of eliminating such excess earnings. AEP has appealed both the methodology of determining excess earnings and the reduction of distribution rates. See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2003 Annual Reports, for further discussion, including the specific amounts in dispute. The PUCT rulings and the reduction in distribution rates effectively removes unrefunded excess earnings as a component to be determined by the True-Up Proceedings. To the extent AEP prevails in its appeal of the reduction in distribution rates, unrefunded excess earnings, as finally determined, would be included in the True-Up Proceedings and result in a reduction of the True-Up Adjustment. Pursuant to PUCT rules, if total stranded costs determined in the 2004 True-Up Proceeding are less than the amount of previously securitized regulatory assets, the PUCT can implement an offsetting credit to transmission and distribution rates. The Texas Third Court of Appeals ruled in February 2003 that the Texas Legislation does not contemplate the refunding to customers of negative stranded costs. In addition, the Court ruled that negative stranded costs cannot be offset against other true-up adjustments including final under-recovered fuel amounts. Portions of this ruling have been appealed to the Texas Supreme Court. See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2003 Annual Reports, for more information. Further Securitization Bonds and Wires Charges: After final determination of its stranded costs and other true-up adjustments by the PUCT, TCC expects to issue securitization bonds in the amount of its currently non-securitized plant-related stranded costs and generation-related regulatory assets determined in the 2004 true-up proceeding. The bonds can have a maximum term of 15 years. If securitization bonds are not issued to finance all currently non-securitized plant-related stranded costs and generation-related 22 regulatory assets, TCC will seek recovery of these amounts as well as its other true-up adjustments, through a non-bypassable competition transition charge in transmission and distribution rates.For a discussion of recovery of regulatory assets and stranded costs in Ohio and Virginia, see Note 6 to the consolidated financial statements entitled Customer Choice and Industry Restructuring, included in the 2003 Annual Reports.Competition AEP's public utility subsidiaries have the right (which in some cases is exclusive) to sell electric power at retail within their respective service areas in the states of Arkansas, Indiana, Kentucky, Louisiana, Oklahoma, Tennessee, West Virginia and the SPP area of Texas. In Michigan, Ohio and Virginia, AEP's public utility subsidiaries continue to provide service to customers who have not been offered or have not selected alternate service from competing suppliers. In those states, service is currently being provided according to prescribed rules and rates. In the ERCOT area of Texas, TCC and TNC sell power (through December 31, 2004) to Centrica, which provides PTB service to certain former customers of TCC and TNC and must compete for customers. See Regulation -Rates for a description of the setting of rates for power sold at bundled or unbundled state-regulated rates.The public utility subsidiaries of AEP, like many other electric utilities, have traditionally provided electric generation and energy delivery, consisting of transmission and distribution services, as a single product to their retail customers. Legislation has been enacted in Michigan, Ohio, Texas and Virginia that allows for customer choice of generation supplier. Although restructuring legislation has been passed in Oklahoma and West Virginia, it has been delayed indefinitely in Oklahoma and not implemented in West Virginia. In addition, restructuring legislation in Arkansas has been repealed. See Electric Restructuring Legislation. Customer choice legislation generally allows competition in the generation and sale of electric power, but not in its transmission and distribution. See Management's Financial Discussion andAnalysis of Results of Operations and Note 6 to the consolidated financial statements entitled Customer Choice and Industry Restructuring included in the 2003 Annual Reports, for further information with respect to restructuring legislation affecting AEP subsidiaries. The public utility subsidiaries of AEP, like the electric industry generally, face increasing competition in the sale of available power on a wholesale basis, primarily to other public utilities and power marketers. The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale market by creating a generation market with fewer barriers to entry and mandating that all generators have equal access to transmission services. As a result, there are more generators able to participate in this market. The principal factors in competing for wholesale sales are price (including fuel costs), availability of capacity and power and reliability of service.AEP's public utility subsidiaries also compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power. With respect to competing generators and self-generation, the public utility subsidiaries of AEP believe that they generally maintain a favorable competitive position. With respect to alternative sources of energy, the public utility subsidiaries of AEP believe that the reliability of their service and the limited ability of customers to substitute other cost-effective sources for electric power place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy.Significant changes in the global economy in recent years have led to increased price competition for industrial customers in the United States, including those served by the AEP System. Some of these industrial customers have requested price reductions from their suppliers of electric power. In addition, industrial customers that are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power. The public utility subsidiaries of AEP cooperate with such customers to meet their business needs through, for example, providing various off-peak or interruptible supply options pursuant to tariffs filed with the various state commissions. Occasionally, these rates are first negotiated, and then filed with the state commissions. The public utility subsidiaries believe that they are unlikely to be materially adversely affected by this competition. Seasonali' The sale of electric power is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of AEP's facilities and the terms of power sale contracts into which AEP 23 enters. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder.Unusually mild weather in the future could diminish AEP's results of operations and may impact its financial condition. 24 Investments-Gas Onerations AEP, through certain subsidiaries, operates and owns an interest in a significant amount of gas-related assets, including:

6,400 miles of natural gas pipelines between two systems;* 127 billion cubic feet of storage among two facilities;
Five natural gas processing plants; and* Certain gas marketing contracts.

AEP, in operating its natural gas assets, enters into transactions for the purchase and sale of natural gas. These transactions involve (i) purchases of natural gas from producers and subsequent sales to end users and local distribution companies, (ii) physical gas transactions along our natural gas pipelines to maximize revenue, based on price differences between various locations along those assets and (iii) physical (some of which involve purchases of gas that is stored in AEP storage assets) and financial transactions to mitigate price volatility risk. Gas transactions are executed (i) with numerous counterparties, (ii) directly with brokers or (iii) through brokerage accounts with brokers who are registered with the Commodity Futures Trading Commission. Brokers and counterparties may require cash or cash related instruments to be deposited on these transactions as margin against open positions. As of December 31, 2003, counterparties posted approximately $224 million in cash, cash equivalents and letters of credit with AEPES to satisfy the counterparties' obligations in connection with natural gas transactions. AEPES posted approximately $42 million. Since AEP's open gas trading contracts are valued based on changes in gas market prices, our exposures change daily.AEP's trading and marketing operations are generally limited to risk management and are focused in regions in which AEP owns assets.AEP acquired its Bammel storage facility (which has approximately 118 billion cubic feet of storage capacity) from Enron Corporation and certain of its subsidiaries. Because Enron and its relevant subsidiary are now bankrupt, the bankruptcy trustee and other third parties have taken and may take additional positions in the bankruptcy proceedings or litigation that seek to limit or compromise our use of this facility. See Notes 7 and 10 to the consolidated financial statements entitled Commitments and Contingencies and Acquisitions, Dispositions, Discontinued Operations, Impairments, Assets Heldfor Sale and Assets Held and Used, respectively, included in the 2003 Annual Reports for more information. During the third quarter of 2003, we selected an advisor to review our options regarding the assets of our gas operations business.In February 2004, we signed a definitive agreement to sell Louisiana Intrastate Gas (which has approximately 2000 miles of pipeline)and intend to complete the sale of the Jefferson Island storage facility (which has approximately 9 billion cubic feet of storage capacity) in 2004. We are considering our options with respect to our Houston Pipe Line and related assets. See Note 10 to the consolidated financial statements entitled Dispositions, Discontinued Operations, Impairments, Assets Heldfor Sale and Assets Held and Used, included in the 2003 Annual Reports for more information. Investments-UK Operations AEP, through certain subsidiaries, operates and owns 4,000 MW of power generation facilities in the UK and engaged in the following activities throughout 2003:* Selling wholesale power in the UK;* Trading and marketing power transactions, with numerous counterparties, predominantly limited to risk management around assets used or managed by AEP subsidiaries in the UIK. Since AEP's open power trading contracts are valued based on changes in market power prices, our exposures change daily; and* Procuring and transporting coal to fuel AEP's UK generation facilities and for sale to third parties. Its third party transactions exist because transporting coal is more economical in quantities exceeding those required to operate AEP assets. AEP uses financial instruments executed with numerous counterparties to manage the financial risk of these activities. Since AEP's open coal and freight contracts are based on changes in market prices, our exposures change daily.25 AEP expects to sell all its UK operations assets and contracts as a going concern, in one or more transactions, by the end of 2004.During the fourth quarter of 2003, AEP selected an advisor for the disposition of its UK business.Investments-Other General AEP, through certain subsidiaries, conducts certain business operations other than those included in other segments in which it uses and manage a portfolio of energy-related assets. Consistent with its business strategy, AEP intends to dispose of many of these non-core assets. The assets currently used and managed include:* 1,354 MW of domestic and 1,235 MW of international power generation facilities (of which its ownership is approximately 827 MWV and 680 MW, respectively);

Coal mines and related facilities; and* Barge, rail and other fuel transportation related assets.These operations include the following activities:
Entering into long-term transactions to buy or sell capacity, energy, and ancillary services of electric generating facilities, either existing or to be constructed, at various locations in North America and Europe;* Holding and/or operating various properties, coal reserves, mining operations and royalty interests in Colorado, Kentucky, Louisiana, Ohio, Pennsylvania and West Virginia; and* Through MEMCO Barge Line Inc., transporting coal and dry bulk commodities, primarily on the Ohio, Illinois, and Lower Mississippi rivers for AEP, as well as unaffiliated customers.

AEP, through certain subsidiaries, owns or leases 7,000 railcars, 1,800 barges, 37 towboats and two coal handling terminals with 20 million tons of annual capacity.AEP has in the past two years written down the value of certain of these investments. See Management's Financial Discussion and Analysis of Results of Operations and Note 10 to the consolidated financial statements entitled Acquisitions, Dispositions, Discontimied Operations, Impairments, Assets Heldfor Sale andAssets Held and Used, included in the 2003 Annual Reports.Dow Chemical Cogeneration Facility AEP has entered into an agreement with The Dow Chemical Company to construct a 900 MW cogeneration facility at Dow's chemical facility in Plaquemine, Louisiana. AEP's subsidiary, OPCo, is entitled to 100% of the facility's capacity and energy over The Dow Chemical Company's requirements and has contracted to sell the power from this facility for twenty years to Tractebel Energy Marketing, Inc. (Tractebel). The power supply contract with Tractebel is in dispute. See Notes 7 and 10 to the consolidated financial statements, entitled Commitments and Contingencies and Acquisitions, Dispositions, Discontinued Operations, Impairments, Assets Heldfor Sale and Assets Held and Used, respectively, included in the 2003 Annual Reports, for more information. 26 Item 2. Properties Generation Facilities General At December 31, 2003, the AEP System owned (or leased where indicated) generating plants with net power capabilities (east zone public utility subsidiaries-winter rating; west zone public utility subsidiaries-summer rating) shown in the following table: Companv AEGCo................... APCo ...................... CSPCo.................... & M ........................ KPCo ...................... OPCo...................... PSO ......................... SWEPCo................. TCC ........................ TN C........................ Totals: Stations I (a)17(b)6(e)10(a)l 8(bXf)8(c)9 12(cXd)(g) 2(c)84 Coal Natural Gas Hydro NMI NW%'.v Nrw'1,300 5,073 798 2,595 2,295 11 1,060 8,472 48 1,018 3,139 1,848 1,797 686 3,175 6 377 999 24,724 9.110 863 Nu2,er 14 nite Nrov I]MV _2,143 Oil Total Nlw hW.1,300 5,871 2,595 4,449 1,060 8,520 25 4,182 4,487 4,497 10 1,386 35 38.347 842 630 (a) Unit I of the Rockport Plant is owned one-half by AEGCo and one-half by l&M. Unit 2 of the Rock-port Plant is leased one-half by AEGCo and one-half by &,M. The leases terminate in 2022 unless extended.(b) Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by OPCo.(c) PSO, TCC and TNC jointly own the Oklaunion power station. Their respective ownership interests are reflected in this table.(d) Reflects TCC's interest in STP.(e) CSPCo owns generating units in common with CG&E and DP&L. Its ownership interest of 1,330 MW is reflected in this table.(f) The scrubber facilities at the General James M. Gavin Plant are leased. The lease terminates in 2010 unless extended.(g) See Item I -Utility Operations -Electric Generation -Deactivation and Planned Disposition of Generation Facilities for a discussion of TCC's planned disposition of all its generation facilities. In addition to the generating facilities described above, AEP has ownership interests in other electrical generating facilities, both foreign and domestic. Information concerning these facilities at December 31,2003 is listed below.Facility Brush 11 (a) ................................. Desert Sky Wind Farm ............... M ulberry..................................... Orange Cogen............................. Sweeny ....................................... Thermo Cogeneration (a)............ Trent Wind Farm........................ Total U.S.Bajio ........................................... Ferrybridge (b)............................ Fiddler's Ferry (b)....................... Nanyang (a) ................................ Southcoast (a) ............................. Total International Fuel Natural gas Wind Natural gas Natural gas Natural gas Natural gas Wind Natural gas Coal Coal Coal Natural gas Capacity location Total NW`Colorado 68 Texas 161 Florida 120 Florida 103 Texas 480 Colorado 272 Texas 150 1.354 Osynership Interest 47.75%100%46.25%50%50%50%100%50%1/100%100%70%50%Status QF EWG QF QF QF QF EWG FUCO FUCO FUCO FUCO FUCO Mexico United Kingdom United Kingdom China United Kingdom 605 2,000 2,000 250 380 5.235 27 (a) See Note 10 to the consolidated financial statements entitled Acquisitions, Dispositions, Discontinued Operations, Impairments, Assets Heldfor Sale andAssets Held and Used, included in the 2003 Annual Reports, for a discussion of AEP's planned use and/or disposition of independent power producer and foreign generation assets.(b) Ferrybridge and Fiddler's Ferry are properties that have been designated as discontinued operations and. intended to be sold in 2004. See Note 10 to the consolidated financial statements entitled Acquisitions, Dispositions, Discontinued Operations, Impairments, Assets Heldfor Sale and Assets Held and Use4 included in the 2003 Annual Reports, for more information. Cook Nuclear Plant and STP The following table provides operating information relating to the Cook Plant and STP.Cook Plant P(a)Unit 1 UnitR2 Unit I Unit2 Year Placed in Operation ................................ 1975 1978 1988 1989 Year of Expiration of NRC License (b) .............. 2014 2017 2027 2028 Nominal Net Electrical Rating in Kilowatts ....... 1,036,000 1,107,000 1,250,600 1,250,600 Net Capacity Factors 2003 (c).. .............................................................. 73.5% 74.5% 62.0% 81.2%2002 ......................................... 86.6% 80.5% 99.2% 75.0%2001 (d)................................................................ 87.3% 83.4% 94.4% 87.1%(a) Reflects total plant.(b) For economic or other reasons, operation of the Cook Plant and STP for the full term of their operating licenses cannot be assured.(c) The capacity factors for both units of the Cook Plant were reduced in 2003 due to an unplanned maintenance outage to implement upgrades to the traveling water screens system following an alewife fish intrusion.(d) The capacity factor for both units of the Cook Plant was significantly reduced in 2001 due to an unplanned dual maintenance outage in September 2001 to implement design changes that improved the performance of the essential service water system.Costs associated with the operation (excluding fuel), maintenance and retirement of nuclear plants continue to be more significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the construction and operation of nuclear facilities. 1&M and TCC may also incur costs and experience reduced output at Cook Plant and STP, respectively, because of the design criteria prevailing at the time of construction and the age of the plant's systems and equipment. Nuclear industry-wide and Cook Plant and STP initiatives have contributed to slowing the growth of operating and maintenance costs at these plants. However, the ability of l&M and TCC to obtain adequate and timely recovery of costs associated with the Cook Plant and STP, respectively, including replacement power, any unamortized investment at the end of the useful life of the Cook Plant and STP (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured. See Item I -Utility Operations -Electric Generation -Planned Deactivation and Planned Disposition ofGeneration Facilities for a discussion of TCC's planned disposition of its interest in STP.Potential Uninsured Losses Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to the Cook Plant or STP and costs of replacement power in the event of a nuclear incident at the Cook Plant or STP. Future losses or liabilities which are not completely insured, unless allowed to be recovered through rates, could have a material adverse effect on results of operations and the financial condition of AEP; I&M, TCC and other AEP System companies. See Note 7 to the consolidated financial statements entitled Commitments and Contingencies, incorporated by reference in Item 8, for information with respect to nuclear incident liability insurance. 28 Transmnission and Distribution Facilities The following table sets forth the total overhead circuit miles of transmission and distribution lines of the AEP System and its operating companies and that portion of the total representing 765,000-volt lines: AEP System (a)................................................................. APCo............................................................................... CSPCo. (a)...................................................................... I& M ................................................................................ Kingsport Power Com pany............................................. KPCo............................................................................... OPCo............................................................................... PSO ................................................................................. SW EPCo......................................................................... TCC................................................................................. TNC ................................................................................ W heeling Power Com pany ............................................. Total Overhead Circuit Miles of Transmission and Distribution l.ines 216,685(b) 50,969 14,016 21,957 1,338 10,703 30,559 21,531 20,879 29,424 13,622 1,688 Circuit Miles of 765.000-volt lines 2,026 644 615 258 509 (a) Includes 766 miles of 345,000-volt jointly owned lines.(b) Includes 73 miles of transmission lines not identified with an operating company.Trles The AEP System's generating facilities are generally located on lands owned in fee simple. The greater portion of the transmission and distribution lines of the System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority. The rights of AEP's public utility subsidiaries in the realty on which their facilities are located are considered adequate for use in the conduct of their business. Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties affected thereby. AEP's public utility subsidiaries generally have the right of eminent domain whereby they may, if necessary, acquire, perfect or secure titles to or easements on privately held lands used or to be used in their utility operations. Substantially all the fixed physical properties and franchises of the AEP System operating companies, except for limited exceptions, are subject to the lien of the mortgage and deed of trust securing the first mortgage bonds of each such company.System Transmission Lines and Facility Siting Legislation in the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Texas, Tennessee, Virginia, and West Virginia requires prior approval of sites of generating facilities and/or routes of high-voltage transmission lines. Delays and additional costs in constructing facilities have been experienced as a result of proceedings conducted pursuant to such statutes, as well as in proceedings in which operating companies have sought to acquire rights-of-way through condemnation, and such proceedings may result in additional delays and costs in future years.Construction Progrant General The AEP System, with input from its state utility commissions, continuously assesses the adequacy of its generation, transmission, distribution and other facilities to plan and provide for the reliable supply of electric power and energy to its customers. In this assessment process, assumptions are continually being reviewed as new information becomes available, and assessments and plans are modified, as appropriate. Thus, System reinforcement plans are subject to change, particularly with the restructuring of the electric utility industry.29 Proposed Transmission Facilities APCo is proceeding with its plan to build the Wyoming-Jacksons Ferry 765,000-volt transmission line. The WVPSC and the VSCC have issued certificates authorizing construction and operation of the line. On December 31, 2002, the U.S. Forest Service issued a final environmental impact statement and record of decision to allow the use of federal lands in the Jefferson National Forest for construction of a portion of the line. APCo must still receive additional federal permits, but does not expect that obtaining these will negatively affect its ability to complete construction. Construction &penditures The following table shows construction expenditures (including environmental expenditures) during 2001, 2002 and 2003 and current estimates of 2004 construction expenditures, in each case including AFUDC but excluding assets acquired under leases.2001 2002 2003 2004 Actual Actual Actual Estimate (in thousands) AEP System (a) .$ 1,832,000 $ 1,709,800 $ 1,358,400 $ 1,531,300 AEGCo .6,900 5,300 22,200 18,400 APCo .306,000 276,500 288,800 405,900 CSPCo .132,500 136,800 136,300 130,300 I&M............................................... 91,100 159,400 184,600 185,600 KPCo .37,200 178,700 81,700 36,100 OPCo .344,600 354,800 249,700 303,800 PSO .124,900 89,400 86,800 80,100 SWEPCo .112,100 111,800 121,100 99,600 TCC .194,100 151,500 141,800 150,500 TNC .39,800 43,600 46,700 57,800 (a) Includes expenditures of other subsidiaries not shown. Amounts in 2001 and 2002 include construction expenditures related to entities classified in 2003 as discontinued operations. These amounts were $186,500,000 and $24,900,000, respectively. See Note 7 to the consolidated financial statements entitled Commitments and Contingencies, incorporated by reference in Item 8, for further information with respect to the construction plans of AEP and its operating subsidiaries for the next three years.The System construction program is reviewed continuously and is revised from time to time in response to changes in estimates of customer demand, business and economic conditions, the cost and availability of capital, environmental requirements and other factors. Changes in construction schedules and costs, and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, Federal income and other taxes, and other factors affecting cash requirements, may increase or decrease the estimated capital requirements for the System's construction program.Item 3. Legal Proceedings For a discussion of material legal proceedings, see Note 7 to the consolidated financial statements, entitled Commitments and Contingencies, incorporated by reference in Item 8.Item 4. Submission of Matters to a Vote of Security Holders AEP, APCo, I&M, OPCo, SVEPCo and TCC. None.AEGCo, CSPCo, KPCo, PSO and TNC. Omitted pursuant to Instruction I(2)(c).30 Executive Officers of the Registrants AEP. The following persons are, or may be deemed, executive officers of AEP. Their ages are given as of March 1,2004.Name Michael G. Morris....................... Thomas V. Shockley, Ill............. Henry W. Fayne.......................... Thomas M. Hagan....................... Holly K. Koeppel........................ Robert P. Powers......................... Susan Tomasky........................... AEC office (a)57 Chairman of the Board, President and Chief Executive Officer oftAEP and of AEPSC 58 Vice Chairman of AEP and Vice Chairman and Chief Operating Officer of AEPSC 57 Vice President of AEP, Executive Vice President of AEPSC 59 Executive Vice President-Shared Services of AEPSC 45 Executive Vice President of AEPSC 50 Executive Vice President-Generation of AEPSC 50 Vice President of AEP, Executive Vice President-Policy, Finance and Strategic Planning of AEPSC (a) Messrs. Fayne and Powers and Ms. Tomasky have been employed by AEPSC or System companies in various capacities (AEP, as such, has no employees) for the past five years. Prior to joining AEPSC in June 2000 as Senior Vice President-Governmental Affairs, Mr. Hagan was Senior Vice President-External Affairs of CSW (1996-2000). Prior to joining AEPSC in July 2000 as Vice President-New Ventures, Ms. Koeppel was Regional Vice President of Asia-Pacific Operations for Consolidated Natural Gas International (1996-2000). Messrs. Hagan and Powers, Ms. Koeppel and Ms. Tomasky became executive officers of AEP effective with their promotions to Executive Vice President on September 9, 2002, October 24, 2001, November 18, 2002 and January 26, 2000, respectively. Prior to joining AEPSC in his current position upon the merger with CSW, Mr. Shockley was President and Chief Operating Officer of CSW (1997-2000) and Executive Vice President of CSW (1990-1997). Prior to joining AEPSC in his current position in January 2004, Mr. Morris was Chairman of the Board, President and Chief Executive Officer of Northeast Utilities (1997-2003). All of the above officers are appointed annually for a one-year term by the board of directors of AEP, the board of directors of AEPSC, or both, as the case may be.APCo, I&M, OPCo, SNVEPCo and TCC. The names of the executive officers of APCo, l&M, OPCo, SWEPCo and TCC, the positions they hold with these companies, their ages as of March 1, 2004, and a brief account of their business experience during the past five years appear below. The directors and executive officers of APCo, l&M, OPCo, SWEPCo and TCC are elected annually to serve a one-year term.Name Age Position (a)(hl Michael G. Morris (a)(b) ...... 57 Chairman of the Board, President, Chief Executive Officer and Director of AEP Chairman of the Board, Chief Executive Officer and Director of AEPSC, APCo, I&M, OPCo, SWEPCo and TCC Chairman of the Board, President and Chief Executive Officer of Northeast Utilities Thomas V. Shockley, III (a). 58 Director and Vice President of APCo, l&M, OPCo, SWEPCo and TCC Chief Operating Officer of AEPSC Vice Chairman of AEP and AEPSC President and Chief Operating Officer of CSW Executive Vice President of CSW Henry NV. Fayne (a) .............. 57 President of APCo, I&M, OPCo, SWEPCo and TCC Director of SWEPCo and TCC Director of APCo Director of OPCo Director of I&M Vice President of SWEPCo and TCC Vice President of APCo, I&M and OPCo Vice President of AEP Chief Financial Officer of AEP Executive Vice President of AEPSC Period 2004-Present 2004-Present 1997-2003 2000-Present 2001-Present 2000-Present 1997-2000 1990-1997 2001-Present 2000-Present 1995-Present 1993-Present 1998-Present 2000-2001 1998-2001 1998-Present 1998-2001 2001-Present 31 Name Are Position (a)(b)Executive Vice President-Finance and Analysis of AEPSC Executive Vice President-Financial Services of AEPSC Thomas M. Hagan (a) .......... 5 9 Director and Vice President of APCo, l&M, OPCo, SWEPCo and TCC Executive Vice President-Shared Services of AEPSC Senior Vice President-Governmental Affairs of AEPSC Senior Vice President-Extemal Affairs of CSW Holly K. Koeppel ................. 45 Executive Vice President of AEPSC Vice President-New Ventures Regional Vice President of Asia-Pacific Operations for Consolidated Natural Gas International Robert P. Powers (a) ............ 50 Director and Vice President of APCo, ]&M, OPCo, SWVEPCo and TCC Director of l&M Vice President of l&M Executive Vice President-Generation Executive Vice President-Nuclear Generation and Technical Services of AEPSC Senior Vice President-Nuclear Operations of AEPSC Senior Vice President-Nuclear Generation of AEPSC Susan Tomasky (a) ............... 50 Director and Vice President of APCo, l&M, OPCo, SWEPCo and TCC Executive Vice President-Policy, Finance and Strategic Planning of AEPSC Executive Vice President-Legal, Policy and Corporate Communications and General Counsel of AEPSC Senior Vice President and General Counsel of AEPSC Period 2000-2001 1998-2000 2002-Present 2002-Present 2000-2002 1996-2000 2002-Present 2000-2002 1996-2000 2001-Present 2001-Present 1998-Present 2003-Present 2001-2003 2000-2001 1998-2000 2000-Present 2001-Present 2000-2001 1998-2000 (a) Messrs. Fayne, Hagan, Morris, Powers and Shockley and Ms. Tomasky are directors of AEGCo, CSPCo, KPCo, PSO and TNC.Messrs. Morris and Shockley are also directors of AEP.(b) Mr. Morris is a director of Cincinnati Bell, Inc., Spinnaker Exploration Co. and Flint Ink.PART II Item 5. Market for Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities AEP. The information required by this item is incorporated herein by reference to the material under Common Stock and Dividend Information in the 2003 Annual Report.AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC. The common stock of these companies is held solely by AEP. The amounts of cash dividends on common stock paid by these companies to AEP during 2003 and 2002 are incorporated by reference to the material under Statement of Retained Earnings in the 2003 Annual Reports.Item 6. Selected Financial Data AEGCo, CSPCo, KPCo, PSO and TNC. Omitted pursuant to Instruction 1(2)(a).AEP, APCo, I&M, OPCo, SWEPCo and TCC. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 2003 Annual Reports.32 Item 7. Management's Financial Discussion and Analysis and Financial Condition AEGCo, CSPCo, KPCo, PSO and TNC. Omitted pursuant to Instruction 1(2)(a). Management's narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management's Financial Discussion andAnalysis in the 2003 Annual Reports.AEP, APCo, I&M, OPCo, SWEPCo and TCC. The information required by this item is incorporated herein by reference to the material under Management's Financial Discussion andAnalysis in the 2003 Annual Reports.Item 7A. Quantitative and Qualitative Disclosures About Market Risk AEGCo, AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC. The information required by this item is incorporated herein by reference to the material under Management's Financial Discussion andAnalysis in the 2003 Annual Reports.Item 8. Financial Statements and Supplementary Data AEGCo, AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SNNVEPCo, TCC and TNC. The information required by this item is incorporated herein by reference to the financial statements and financial statement schedules described under Item 15 herein.Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure AEGCo, AEP, APCo, CSPCo, 1&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC. None.Item 9A. Controls and Procedures During 2003, AEP's management, including the principal executive officer and principal financial officer, evaluated AEP's disclosure controls and procedures relating to the recording, processing, summarization and reporting of information in AEP's periodic reports that it files with the SEC. These disclosure controls and procedures have been designed to ensure that (a) material information relating to AEP, including its consolidated subsidiaries, is made known to AEP's management, including these officers, by other employees of AEP and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC's rules and forms. AEP's controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met.As of December 31, 2003, these officers concluded that the disclosure controls and procedures in place provide reasonable assurance that the disclosure controls and procedures can accomplish their objectives. AEP continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as events warrant.There have not been any changes in AEP's internal controls over financial reporting (as such term is defined in Rule 13a-15(e) and l5d-15(e) under the Exchange Act) during the fourth quarter of 2003 that have materially affected, or are reasonably likely to affect, AEP's internal control over financial reporting. 33 PART III Item 10. Directors and Executive Officers of the Registrants AEGCo, CSPCo, KPCo, PSO and TNC. Omitted pursuant to Instruction 1(2)(c).AEP. The information required by this item is incorporated herein by reference to the material under Nominees for Director and Section 16(a) Beneficial Oivnership Reporting Compliance of the definitive proxy statement of AEP for the 2004 annual meeting of shareholders, to be filed within 120 days after December 31, 2003. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report.APCo and OPCo. The information required by this item is incorporated herein by reference to the material under Election of Directors of the definitive information statement of each company for the 2004 annual meeting of stockholders, to be filed within 120 days after December 31, 2003. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report.SWVEPCo and TCC. The information required by this item is incorporated herein by reference to the material under Election of Directors of the definitive information statement of APCo for the 2004 annual meeting of stockholders, to be filed within 120 days after December 31, 2003. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report.I&M. The names of the directors and executive officers of I&M, the positions they hold with l&M, their ages as of March 12, 2004, and a brief account of their business experience during the past five years appear below and under the caption Executive OfLicers of the Registrants in Part I of this report.Name K. G. Boyd.................... John E. Ehler................. Patrick C. Hale.............. David L. Lahrman......... Marc E. Lewis............... Susanne M. Moorman... John R Sampson........... Age Pmitinn (a)52 Director Vice President (Appointed) -Fort Wayne Region Distribution Operations Indiana Region Manager 47 Director Manager of Distribution Systems-Fort Wayne District Region Operations Manager 49 Director Plant Manager, Rockport Plant Energy Production Manager, Rockport Plant Energy Production Manager, Mountaineer Plant (APCo)52 Director and Manager, Region Support Fort Wayne District Manager 49 Director Assistant General Counsel of the Service Corporation Senior Counsel of AEPSC Senior Attorney of AEPSC 54 Director and General Manager, Community Services Manager, Customer Services Operations 51 Director and Vice President Indiana State President Indiana & Michigan State President Site Vice President, Cook Nuclear Plant Plant Manager, Cook Nuclear Plant Period 1997-Present 2000-Present 1997-2000 2001-Present 2000-Present 1997-2000 2003-Present 2003-Present 2001-2003 1997-2001 2001-Present 1997-2001 2001-Present 2001-Present 2000-2001 1994-2000 2000-Present 1997-2000 1999-Present 2000-Present 1999-2000 1998-1999 1996-1998 (a) Positions are with I&M unless otherwise indicated. 34 Item 11. Executive Compensation AEGCo, CSPCo, KPCo, PSO and TNC. Omitted pursuant to Instruction 1(2)(c).AEP. The information required by this item is incorporated herein by reference to the material under Directors Compensation and Stock Ownership Guidelines, Executive Compensation and the performance graph of the definitive proxy statement of AEP for the 2004 annual meeting of shareholders to be filed within 120 days after December 31, 2003.APCo and OPCo. The information required by this item is incorporated herein by reference to the material under Executive Compensation of the definitive information statement of each company for the 2004 annual meeting of stockholders, to be filed within 120 days after December 31,2003.I&M, SNN'EPCo and TCC. The information required by this item is incorporated herein by reference to the material under Evecutive Compensation of the definitive information statement of APCo for the 2004 annual meeting of stockholders, to be filed within 120 days after December 31,2003.Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters AEGCo, CSPCo, KPCo, PSO and TNC. Omitted pursuant to Instruction 1(2)(c).AEP. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Ojjicers of the definitive proxy statement of AEP for the 2004 annual meeting of shareholders to be filed within 120 days after December 31,2003.APCo and OPCo. The information required by this item is incorporated herein by reference to the material under Share Owvnership of Directors and Executive Officers in the definitive information statement of each company for the 2004 annual meeting of stockholders, to be filed within 120 days after December 31,2003.I&M. All 1,400,000 outstanding shares of Common Stock, no par value, of l&M are directly and beneficially held by AEP.Holders of the Cumulative Preferred Stock of l&M generally have no voting rights, except with respect to certain corporate actions and in the event of certain defaults in the payment of dividends on such shares.SWEPCo and TCC. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information statement of APCo for the 2004 annual meeting of stockholders, to be filed within 120 days after December 31,2003.The table below shows the number of shares of AEP Common Stock and stock-based units that were beneficially owned, directly or indirectly, as of January 1, 2004, by each director and nominee of I&M and each of the executive officers of l&M named in the summary compensation table, and by all directors and executive officers of I&M as a group. It is based on information provided to I&M by such persons. No such person owns any shares of any series of the Cumulative Preferred Stock of I&M. Unless otherwise noted, each person has sole voting power and investment power over the number of shares of AEP Common Stock and stock-based units set forth opposite his or her name. Fractions of shares and units have been rounded to the nearest whole number.Stock Name Shares (a) Units (b) Total Karl G. Boyd ............................... 12,296 248 12,554 E. Linn Draper, Jr ............................... 822,359(c) 125,233 947,592 John E. Ehler ............................... --Henry NV. Fayne ............ ................... 236,177(d) 13,143 249,320 Thomas M. Hagan ............................... 105,943 149 106,092 Patrick C. Hale ........... .................... 3,025 -3,025 David L. Lahrman .............. ................. 497 -497 Marc E. Lewiis...................................................... 6,364 -6,364 Susanne M. Moorman ............................... 41 -41 Michael G. Morris.- -Robert P. Powers ............................... 139,665 1,378 141,043 John R. Sampson ............................... 1 8,005 -18,005 35 Thomas V. Shockley, III ....................... 345,323(d)(e) -345,323 Susan Tomasky ....................... 231,300(d) 6,502 237,802 All Directors and Executive Officers ................... 1,920,995(dXf) 146,653 2,067,648 (a) Includes share equivalents held in the AEP Retirement Savings Plan in the amounts listed below: AEP Retirement Savings Name Plan (Share Eqnivalents) Mr. Boyd ..................................... 96 Dr. Draper ..................................... 4,938 Mr. Ehler.Mr. Fayne ..................................... 6,152 Mr. Hagan ..................................... 3,617 Mr. Hale ..................................... 25 Mr. Lahrman ..................................... 497 Mr. Lewis ...................................... 1,282 Ms. Moorman .......... ............................ 41 Mr. Momis.Mr. Powers ..................................... 632 Mr. Sampson ..................................... 805 Mr. Shockley ..................................... 7,530 Ms. Tomasky ..................................... 1,967 All Directors and Executive Officers ................................. 27,582 With respect to the share equivalents held in the AEP Retirement Savings Plan, such persons have sole voting power, but the investment/disposition power is subject to the terms of the Plan. Also, includes the following numbers of shares attributable to options exercisable within 60 days: Mr. Boyd, 12,000; Dr. Draper, 816,666; Mr. Hagan, 91,833, Mr. Hale, 3,000; Mr. Lewis, 5,082; Mr. Powers, 139,033; Mr. Sampson, 17,200; Mr. Shockley, 300,000; and Mr. Fayne and Ms. Tomasky, 229,333.(b) This column includes amounts deferred in stock units and held under AEP's officer benefit plans.(c) Includes 661 shares held by Dr. Draper in joint tenancy with a family member.(d) Does not include, for Messrs. Fayne, and Shockley and Ms. Tomasky, 85,231 shares in the American Electric Power System Educational Trust Fund over which Messrs. Fayne and Shockley and Ms. Tomasky share voting and investment power as trustees (they disclaim beneficial ownership). The amount of shares shown for all directors and executive officers as a group includes these shares.(e) Includes 496 shares held by family members of Mr. Shockley over which he disclaimed beneficial ownership.(f) Represents less than 1% of the total number of shares outstanding. 36 Equity Compensation Plan Information The following table summarizes the ability of AEP to issue common stock pursuant to equity compensation plans as of December 31,2003: Number of securities to be issued upon exercise of outstanding options warrants and rights (a)9,094,241 0 9,094,241 Weighted average exercise price of outstanding options, warrants and rights (h)$ 33.0294 N/A$ 33.0294 Number ofsecurities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))(c)4,890,143 0 4,890,143 Plan Catesorv Equity compensation plans approved by security holders(l) ................. Equity compensation plans not approved by security holders ................ Total......................................................................................................(I) Consists of shares to be issued upon exercise of outstanding options granted under the American Electric Power System 2000 Long-Term Incentive Plan, the CSW 1992 Long-Term Incentive Plan (CSW Plan). The CSW Plan was in effect prior to the consummation of the AEP-CSW merger. All unexercised options granted under the CSW Plan were converted into 0.6 options to purchase AEP common shares, vested on the merger date and will expire ten years after their grant date. No additional options will be issued under the CSW Plan.Item 13. Certain Relationships and Related Transactions AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC: None.Item 14. Principal Accountants Fees and Services AEP. The information required by this item is incorporated herein by reference to the definitive proxy statement of AEP for the 2004 annual meeting of shareholders to be filed within 120 days after December 31,2003.APCo and OPCo. The information required by this item is incorporated herein by reference to the definitive information statement of each company for the 2004 annual meeting of stockholders, to be filed within 120 days after December 31, 2003.AEGCo, CSPCo, I&M, KPCo, PSO, SWEPCo, TCC and TNC.Each of the above are wholly-owned subsidiaries of AEP and does not have a separate audit committee. A description of the AEP Audit Committee pre-approval policies, which apply to these companies, is contained in the definitive proxy statement of AEP for the 2004 annual meeting of shareholders to be filed within 120 days after December 31,2003. The following table presents directly billed fees for professional services rendered by Deloitte & Touche LLP for the audit of these companies' annual financial statements for the years ended December 31, 2002 and 2003, and fees directly billed for other services rendered by Deloitte & Touche LLP during those periods. Deloitte & Touche LLP also provides additional professional and other services to the AEP System, the cost of which may ultimately be allocated to these companies though not billed directly to them. For a description of these fees and services, see the definitive proxy statement of AEP for the 2004 annual meeting of shareholders to be filed within 120 days after December 31, 2003.Audit Fees....................................... Audit-Related Fees ......................... Tax Fees.......................................... All Other Fees................................. AEGCo 2003 2002$136,100 126,000 0 0 1,000 1,000 0 0 CSPCo 2003 2002 385,000 269,900 0 155,000 349,000 119,000 0 0 2003 366,900* .0 26,000 0 2002 540,400 0 231,000 0 I&M KPCo 2003 2002 289,000 251,400 0O 0 8,000 34,000 0 0 37 PSO SWEPCo TCC TNC 2003 2002 2003 2002 2003 2002 2003 2002 Audit Fees.................................... $187,300 156,200 212,900 178,700 511,000 446,700 188,900 92,800 Audit-Related Fees ........... 0 0 0 0 0 274,800 0 213,000 Tax Fees ........... 35,000 103,000 89,000 102,000 89,000 125,000 54,000 77,000 All Other Fees ........... 0 0 0 0 0 0 0 0 PART IV Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a) The following documents are filed as a part of this report: 1. FINANCIAL STATEMENTS: The following financial statements have been incorporated herein by reference pursuant to Item 8.pare AEGCo: Statements of Income for the years ended December 31, 2003, 2002, and 2001; Statements of Retained Earnings for the years ended December 31, 2003, 2002, and 2001; Balance Sheets as of December 31, 2003 and 2002; Statements of Cash Flows for the years ended December 31, 2003, 2002, and 2001; Statements of Capitalization as of December 31, 2003 and 2002; Combined Notes to Financial Statements; Independent Auditors' Report.AEP and Subsidiary Companies: Consolidated Statements of Operations for the years ended December 31, 2003, 2002, and 2001; Consolidated Balance Sheets as of December 31, 2003 and 2002; Consolidated Statements of Cash Flows for the years ended December 31,2003, 2002, and 2001; Consolidated Statements of Common Shareholders' Equity and Comprehensive Income for the years ended December 31, 2003, 2002, and 2001; Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries at December 31, 2003 and 2002; Schedule of Consolidated Long-term Debt of Subsidiaries at December 31, 2003 and 2002; Combined Notes to Consolidated Financial Statements; Independent Auditors' Report.APCo, CSPCo, I&M, PSO, SWEPCo and TCC: Consolidated Statements of Income for the years ended December 31, 2003, 2002, and 2001; Consolidated Statements of Comprehensive Income for the years ended December 31, 2003, 2002, and 2001; Consolidated Statements of Retained Earnings for the years ended December 31, 2003, 2002, and 2001; Consolidated Balance Sheets as of December 31, 2003 and 2002; Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002, and 2001; Consolidated Statements of Capitalization as of December 31, 2003 and 2002; Schedule of Long-term Debt as of December 31, 2003 and 2002; Combined Notes to Consolidated Financial Statements; Independent Auditors' Report.KPCo, OPCo and TNC: Statements of Income (or Statements of Operations) for the years ended December 31, 2003, 2002, and 2001; Statements of Comprehensive Income for the years ended December 31, 2003, 2002, and 2001; Statements of Retained Earnings for the years ended December 31, 2003, 2002, and 2001; Balance Sheets as of December 31, 2003 and 2002; Statements of Cash Flows for the years ended December 31, 2003, 2002, and 2001; Statements of Capitalization as of December 31, 2003 and 2002; Schedule of Long-term Debt as of December 31, 2003 and 2002; Combined Notes to Financial Statements; Independent Auditors' Report.2. FINANCIAL STATEMENT SCHEDULES: Financial Statement Schedules are listed in the Index to Financial Statement Schedules (Certain schedules have been S-1 omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable). Independent Auditors' Report 3. EXHIBITS: Exhibits for AEGCo, AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC are listed in the E-l Exhibit Index and are incorporated herein by reference (b) Reports on Forms 8-K: 38 Company Renortinr Date orReport CSPCo............................................................. December 3, 2003 SWEPCo .... October 3, 2003 Item 5. Other Events arnd Regulation FD Disclosure Item 7. Financial Statements and Exhibits Item 5. Other Events and Regulation FD Disclosure Item 7. Financial Statements and Exhibits (c) Exhibits: See Exhibit Index beginning on page E-1.39 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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 ELECrRIC POWER COMPANY, INC.By:/s/ SUSAN TOMASKY (Susan Tomasky, Vice President, Secretary and Chief Financial Officer)Date: March 10,2004 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Title Date (i) Principal Executive Officer:*MIcIAEL G. MORRIS Chairman of the Board, President, Chief Executive Officer And Director March 10,2004 (ii) Principal Financial Officer: Is/ SUSAN TOMASKY (Susan Tomasky)(iii) Principal Accounting Officer: 1sf JOSEPH M. BUONAIUTO (Joseph M. Buonaiuto) Vice President, Secretary and Chief Financial Officer Controller and Chief Accounting Officer March 10, 2004 March 10,2004 (iv) A Majority of the Directors:

E. R. BROOKS*DONALD M. CARLTON*JOHN P. DESBARRES*ROBERT W. FRI*WILLIAM R. HOWELL*LEsTEA. HUDSON, JR.*LEONARDJ.

KWAWA*RICHARD L. SANDOR*THoMAS V. SHOCKLEY, III*DONALD G. SMITH*LINDA GILLESPIE STUNTZ*KAnIRYN D. SULUIVAN*By: As/ SUSAN TOMASKY (Susan Tomasky, Attorney-in-Fact) March 10, 2004 40 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thercunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.AEP GENERATING COMPANY AEP TEXAS CENTRAL COMPANY AEP TEXAS NORTH COMPANY APPALACHIAN POWER COMPANY COLUMBUS SOUrHERN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY PUBLIC SERVICE COMPANY OF OKLAIIONIA SOUHlWESTERN ELECTRIC POWER COMPANY By: Is/ SUSAN TOMASKY (Susan Tomasky, Vice President) Date: March 10,2004 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.Sienature Title Date (i) Principal Executive Officer:*MICHAEL G. MORRIS Chairman of the Board, Chief Executive Officer and Director March 10,2004 (ii) Principal Financial Officer: Is/ SUSAN TOMASKY (Susan Tomasky)(iii) Principal Accounting Officer: Is! JOSEPH M. BUONAUTO (Joseph M. Buonaiuto)(iv) A Majority of the Directors:

JEFFREY D. CROSS*HENRY W. FAYNE*Tliows M. HAGAN*A. A. PENA*ROBERT P. POWERS*THOMAS V. SHOCKLEY, III*STEPHENP.

SMITH*By: /Is SUSAN TOMASKY (Susan Tomasky, Attorney-in-Fact) Vice President, Secretary, Chief Financial Officer and Director Controller and Chief Accounting Officer March 10,2004 March 10,2004 March 10,2004 41 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.INDIANA MICHIGAN POWER COMPANY By: Is! SUSAN TOMASKY (Susan Tomasky, Vice President) Date: March 10,2004 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.Sienature Title Date (i) Principal Executive Officer:*MICHAEL G. MORRIS Chief Executive Officer and Director March 10,2004 (ii) Principal Financial Officer:/s/ SUSAN TOMASKY (Susan Tomasky)(iii) Principal Accounting Officer:/S/ JOSEPH M. BUONAiUTO (Joseph M. Buonaiuto)(iv) A Majority of the Directors:

K. G. BOYD*JolpN E. EHLER*HENRYW. FAYNE*THOMAS M. HAGAN*PATRICK C. HALE*DAVDL. LAHRMAN*MARCE. LENs*SUsANNE M. MOORMAN*ROBERT P. POWERS*JOHN R. SAMPSON*Tlomm V. SIIOCKLEY, III*By: /sf SUSAN TOMASKY (Susan Tomasky, Attorney-in-Fact)

Vice President, Secretary, Chief Financial Officer and Director Controller and Chief Accounting Officer March 10,2004 March 10,2004 March 10,2004 42 INDEX TO FINANCIAL STATEMENT SCHEDULES Paie INDEPENDENT AUDITORS' REPORT............................................................................................................ S-2 The following financial statement schedules are included in this report on the pages indicated AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule 11-Valuation and Qualifying Accounts and Reserves ................................................................ S-3 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY Schedule 11 -Valuation and Qualifying Accounts and Reserves ................................................................. S-3 AEP TEXAS NORTH COMPANY Schedule 11 -Valuation and Qualifying Accounts and Reserves ................................................................. S-3 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Schedule 11-Valuation and Qualifying Accounts and Reserves ................................................................. S4 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Schedule lI-Valuation and Qualifying Accounts and Reserves ................................................................ S4 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule 11 -Valuation and Qualifying Accounts and Reserves ................................................................ S4 KENTUCKY POWER COMPANY Schedule 11-Valuation and Qualifying Accounts and Reserves ................................................................ S-5 OHIO POWER COMPANY CONSOLIDATED Schedule 11-Valuation and Qualifying Accounts and Reserves ................................................................. S-5 PUBLIC SERVICE COMPANY OF OKLAHOMA Schedule 11 -Valuation and Qualifying Accounts and Reserves ................................................................ S-5 SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED Schedule 11-Valuation and Qualifying Accounts and Reserves ................................................................ S-6 S-I INDEPENDENT AUDITORS' REPORT AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARIES: We have audited the consolidated financial statements of American Electric Power Company, Inc. and subsidiaries and the financial statements of certain of its subsidiaries, listed in Item 15 herein, as of December 31, 2003 and 2002, and for each of the three years in the period ended December 31, 2003, and have issued our reports thereon dated March 5, 2004 (which reports express unqualified opinions and include explanatory paragraphs concerning the adoption of new accounting pronouncements in 2002 and 2003); such financial statements and reports are included in the 2003 Annual Reports and are incorporated herein by reference. Our audits also included the financial statement schedules of American Electric Power Company, Inc. and subsidiaries and of certain of its subsidiaries, listed in Item 15. These financial statement schedules are the responsibility of the respective company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the corresponding basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.Is! Deloitte & Touche LLP Columbus, Ohio March 5,2004 S-2 AMERICAN ELECTRIC PONVER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Coltumn C Column D Column E Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End or Descrintion orperiod _Fxpenses Accounts(a) Deductions(h) Period (in thousands) Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31,2003 ........... S-1M10 $ 45, $il23$,2 Year Ended December 31,2002(c) ....... $68,429 $ 87,044 l 59.662 $SL7 Year Ended December 31,2001(c) ...... $-1,460 $ ,20 $-2.92,554 $ 68A29 (a) Recoveries on accounts previously written off.(b) Uncollectible accounts written off.(c) 2002 and 2001 amounts have been adjusted to reflect the treatment of LIG and UK generation assets as discontinued operations in AEP's Consolidated Statements of Operations. AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY SCHEDULE H1-VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End of Description OfPeriod Expenses Accountq(a) Deductinns(b) Period (in thousands) Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31,2003 ..... $.L712 ___ $ 348 SL 1 Year Ended December 31,2002 6..... $ 18 6 $L 162 $-- $ 3 $ 346 Year Ended December31, 2001 ..... $ 1 $5 (a) Recoveries on accounts previously written off.(b) Uncollectible accounts written off.AEP TEXAS NORTH COMPANY SCHEDULE I1-VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End of Description orPeriod Expenses Accounts(a) Deductions(b) Period (in thousands) Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31,2003 ........ X , X 1 SAM $-49175 Year Ended December 31,2002 9..... t196 S.4. $J17 $ "041 YearEnded December31, 2001 ..... &288 S.... $1335 $--Io $A196 (a) Recoveries on accounts previously written off.(b) Uncollectible accounts written off.S-3 APPALACHIAN POWER COMPANY AND SUBSIDIARIES SCHEDULE 11-VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31,2003 .....Year Ended December 31,2002 .....Year Ended December 31,2001 .....Column B Column C ccolumn D Column E Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End of Of Period Exnenses Accouints(a) Deductions(h) Period (in thousands) $113P9 $ 2QZ $ 433 $16,495 $ 2.QB5 1 $3,937 $ J2, $ , $ ,13,$2S-$2.4 $-1 .011.7 (a) Recoveries on accounts previously written off.(b) Uncollectible accounts written off.COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES SCHEDULE 11-VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Additions Balance at Charged to Charged to Beginning Costs and Other Of Period Expenses AccountsNa) Deductions(b)(in thousands) Column E Balance at End of Period srscrlpllzwn Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31,2003 .....Year Ended December 31, 2002.....Year Ended December 31,2001 .....$-745 L=(10)$ 5 $ 331 S$ -$ -=$245 (a) Recoveries on accounts previously written off.(b) Uncollectible accounts written off.INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES SCHEDULE 11-VALUATION AND QUALIFYING ACCOUNTS AND RESERVES 111.1'..m -Column B Column C Column D Additions Balance at Charged to Charged to Beginning Costs and Other Of Period Expenses Accounts(a) Deductions(b)(in thousands) Column E Balance at End of Period Description Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31,2003 .....Year Ended December 31,2002 .....Year Ended December 31,2001..... $Z-i$ -741 SLM-2$A31$578$741 (a) Recoveries on accounts previously written off.(b) Uncollectible accounts written off.S-4 KENTUCKY POWER COMPANY SCHEDULE 11-VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End of Description Of Period Expenses AccouintNa Deduction%(b) Period (in thousands) Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31,2003 ..... $.J9,2 S.-. $912 $ S376 $L736 Year Ended December 31,2002 $2.......... $4 a) -$_4 $-192 Year Ended December31,2001 L282..... $ = $-L4) $1-264 (a) Recoveries on accounts previously written off.(b) Uncollectible accounts written off.OHIO POWER COMPANY CONSOLIDATED SCHEDULE 11-VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column F.Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End of Description Of Period Expenses Accounts-a) Deductions(b) Period (in thousands) Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December31, 2003 ..... $ 909 $A42 __ 1 $189 Year Ended December 31,2002 ..... $ 1, 3 $ -$3 $ 9059 Year Ended December 31,2001 ..... 554 $ _- $524 2X3 (a) Recoveries on accounts previously written off.(b) Uncollectible accounts written off.PUBLIC SERVICE COMPANY OF OKLAHOMA SCHEDULE 11-VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End of Description Of Period Expenses Accounts(a) Deductions(b) Period (in thousands) Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31,2003 L....... $ 84 $L 37 $-_ $S84 $37 Year Ended December 31,2002 $ ..... $4 S1i $ L33 $ S-$ 4 YearEndedDecember31,2001 ..$. 47 $A4 ___ $S67 $A44 (a) Recoveries on accounts previously written off.(b) Uncollectible accounts written off.S-5 SOUTHWESTERN ELECTRIC POWVER COMPANY CONSOLIDATED SCHEDULE 11-VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column F.Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End or Description Of Period Expenies Accountq(a) Deductions(b) Period (in thousands) Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31,2003 $..... S-2B $_J1 $3$ 13 2SQ2 Year Ended December 31,2002 ...... S .89 $- -36 $ A $ J $22 Year Ended December 31,2001 ..... $ 911 $ _89 S -$ 911 $_89 (a) Recoveries on accounts previously wTitten off.(b) Uncollectible accounts written off.S-6 EXHIBIT INDEX Certain of the following exhibits, designated with an asterisk (*), are filed herewith. The exhibits not so designated have heretofore been filed with the Commission and, pursuant to 17 C.F.R. 229.10(d) and 240.12b-32, are incorporated herein by reference to the documents indicated in brackets following the descriptions of such exhibits. Exhibits, designated with a dagger (t), are management contracts or compensatory plans or arrangements required to be filed as an Exhibit to this Form pursuant to Item 14(c) of this report.Fxhibit Nuimber Desrintion AEGCo 3(a) -Articles of Incorporation of AEGCo [Registration Statement on Form 10 for the Common Shares of AEGCo, File No. 0-18135, Exhibit 3(a)].3(b) -Copy of the Code of Regulations of AEGCo (amended as of June 15, 2000) [Annual Report on Form 10-K of AEGCo forthe fiscal year ended December31, 2000, File No. 0-18135, Exhibit 3(b)].10(a) -Capital Funds Agreement dated as of December 30, 1988 between AEGCo and AEP [Registration Statement No. 33-32752, Exhibit 28(a)].10(bXl) -Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended [Registration Statement No. 33-32752, Exhibits 28(bX)()(A) and 28(b)(1)(B)]. 10(bX2) -Unit Power Agreement, dated as of August 1, 1984, among AEGCo, I&M and KPCo [Registration Statement No. 33-32752, Exhibit 28(bX2)].10(c) -Lease Agreements, dated as of December 1, 1989, between AEGCo and Wilmington Trust Company, as amended [Registration Statement No. 33-32752, Exhibits 28(c)(IXC), 28(c)(2)(C), 28(c)(3XC), 28(cX4)(C), 28(cX5)(C) and 28(c)(6)(C); Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1993, File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(cX3)(B), 10(c)(4)(B), 10(c)(5)(B) and I 0(c)(6)(B)].

13 -Copy of those portions of the AEGCo 2003 Annual Report (for the fiscal year ended December 31, 2003)which are incorporated by reference in this filing.*24 -Power of Attorney.*31(a) -Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*31(b) -Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*32(a) -Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.*32(b) -Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.AEPt 3(a) -Restated Certificate of Incorporation of AEP, dated October 29, 1997 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1997, File No. 1-3525, Exhibit 3(a)].3(b) -Certificate of Amendment of the Restated Certificate of Incorporation of AEP, dated January 13, 1999[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 3(b)].3(c) -Composite of the Restated Certificate of Incorporation of AEP, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 3(c)].*3(d) -By-Laws of AEP, as amended through December 15,2003.4(a) -Indenture (for unsecured debt securities), dated as of May 1, 2001, between AEP and The Bank of New York, as Trustee [Registration Statement No. 333-86050, Exhibits 4(a), 4(b) and 4(c); Registration Statement No.333-105532, Exhibits 4(d), and 4(e) and 4(f)].4(b) -Forward Purchase Contract Agreement, dated as of June 11, 2002, between AEP and The Bank of New York, as Forward Purchase Contract Agent [Annual Report on Form 10-K of AEP for the fiscal year ended December 31,2002, file No. 1-3525, Exhibit 4(c)].E-l Exhibit Number Dmesripation 10(a) -Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, OPCo and l&M and with AEPSC, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No.1-3525, Exhibit 10(a)(3)].

10(b) -Restated and Amended Operating Agreement, dated as of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2002, file No. 1-3525; Exhibit 10(b)].10(c) -Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(bX2)].10(d) -Transmission Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual Report on Form 1 0-K of AEP for the fiscal year ended December 31, 2002, file No. 1-3525;Exhibit 10(d)].10(e) -Lease Agreements, dated as of December 1, 1989, between AEGCo or l&M and Wilmington Trust Company, as amended [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C), 28(cX2)(C), 28(c)(3XC), 28(cX4)(C), 28(cX5XC) and 28(cX6XC); Registration Statement No. 33-32753, Exhibits 28(a)(lXC), 28(aX2)(C), 28(a)(3XC), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6XC); and Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1993, File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2XB), I 0(cX3XB), I 0(cX4XB), I 0(cX5)(B) and I 0(c)(6XB); Annual Report on Form 10-K of l&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B), 10(e)(4XB), 10(e)(5XB) and 10(eX6XB)]. 10(f) -Lease Agreement dated January 20, 1995 between OPCo and JMG Funding, Limited Partnership, and amendment thereto (confidential treatment requested) [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 10(1X2)].10(g) -Modification No. I to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3 525, Exhibit 10(1)].10(h)(l) -Agreement and Plan of Merger, dated as of December 21, 1997, by and among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South XMest Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)].I 0(h)(2) -Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of AEP dated December 15, 1999, File No. 1-3525, Exhibit 10].t 10(i)(1) -AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December31, 1985, File No. 1-3525, Exhibit 10(e)].tI 0(i)(2) -Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit l0(dX2)].tIO0j) -AEP Accident Coverage Insurance Plan for directors [Annual Report on Form 10-K of AEP for the fiscal year ended December31, 1985, File No. 1-3525, Exhibit 10(g)].*tlO(kXl) -AEP Deferred Compensation and Stock Plan for Non-Employee Directors, as amended December 10,2003.*tlO(kX2) -AEP Stock Unit Accumulation Plan for Non-Employee Directors, as amended December 10,2003.t0o(l)(IXA) -AEP System Excess Benefit Plan, Amended and Restated as of January 1,2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31,2000, File No. 1-3525, Exhibit I 0)(l XA)].tl0(I)(lXB) -Guaranty by AEP of AEPSC Excess Benefits Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit I 0(h)(1)(B)]. t 10(l)(1)(C) -First Amendment to AEP System Excess Benefit Plan, dated as of March 5,2003 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31,2002, file No. 1-3525; Exhibit lO(l)(l)(c)].

f110(l)(2)

-AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2003 (Non-Qualified) E-2 Exhibit Number Descrintion t I 0(l)(3) -Service Corporation Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December31, 1993, File No. 1-3525, Exhibit 10(g)(3)].

tlo(m)(l)

-Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 15,2003.tl0(m)(2) -Memorandum of agreement between Susan Tomasky and AEPSC dated January 3, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31,2000, File No. 1-3525, Exhibit 10(s)].t I 0(m)(3) -Letter Agreement dated June 23, 2000 between AEPSC and Holly K. Koeppel [Annual Report on Form I 0-K of AEP for the fiscal year ended December 31,2002, file No. 1-3525; Exhibit 10(m)(3)(A)]. t I 0(m)(4) -Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31,2002, file No. 1-3525; Exhibit I 0(mX4)].1I0(n) -AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit I0(i)(l)]. tl0(o)(1) -AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30,1998, File No. 1-3525, Exhibit 10].tI 0(o)(2) -First Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 31, 2000[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2002, file No. 1-3525; Exhibit 10(oX2)].tlV(P) -AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective March 1, 1999 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 10(o)].*f 10(q) -AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1,2003.1I0(r) -AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31,2002, file No. 1-3525; Exhibit 10(r)].t10(s) -Nuclear Key Contributor Retention Plan dated May 1, 2000 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2002, file No. 1-3525; Exhibit 10(s)].t10(t) -AEP Change In Control Agreement [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 10(o)].*f10(u) -AEP System 2000 Long-Term Incentive Plan, as amended December 10,2003.tl0(v)(l) -Central and South West System Special Executive Retirement Plan as amended and restated effective July 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998, File No. 1-1443, Exhibit 18].t1 0(v)(2) -Certified CSW Board Resolution of April 18, 1991 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit I 0(rX2)].*tI0(vX3) -Certified AEP Utilities, Inc. (formerly CSW) Board Resolutions of July 16, 1996.t 10(v)(4) -CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW, March 13, 1992].t1 0(v)(5) -Central and South West Corporation Executive Deferred Savings Plan as amended and restated effective as of January 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998, File No.1-1443, Exhibit 24].* 12 -Statement re: Computation of Ratios.* 13 -Copy of those portions of the AEP 2003 Annual Report (for the fiscal year ended December 31, 2003) which are incorporated by reference in this filing.*21 -List of subsidiaries of AEP.*23 -Consent of Deloitte & Touche LLP.*24 -Power of Attorney.*31(a) -Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*31(b) -Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*32(a) -Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.E-3 Exhibit Number Desrintion

32(b) -Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.APCot 3(a) -Restated Articles of Incorporation of APCo, and amendments thereto to November 4, 1993 [Registration Statement No. 33-50163, Exhibit 4(a); Registration Statement No. 33-53805, Exhibits 4(b) and 4(c)].3(b) -Articles of Amendment to the Restated Articles of Incorporation of APCo, dated June 6, 1994 [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1994, File No. 1-3457, Exhibit 3(b)].3(c) -Articles of Amendment to the Restated Articles of Incorporation of APCo, dated March 6, 1997 [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No. 1-3457, Exhibit 3(c)].3(d) -Composite of the Restated Articles of Incorporation of APCo (amended as of March 7, 1997) [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No. 1-3457, Exhibit 3(d)].3(e) -By-Laws of APCo (amended as of October 24, 2001) [Annual Report on Form 10-K of APCo for the fiscal year ended December 31,2001, File No. 1-3457, Exhibit 3(e)].4(a) -Mortgage and Deed of Trust, dated as of December 1, 1940, between APCo and Bankers Trust Company and R. Gregory Page, as Trustees, as amended and supplemented

[Registration Statement No. 2-7289, Exhibit 7(b); Registration Statement No. 2-19884, Exhibit 2(1); Registration Statement No. 2-24453, Exhibit 2(n);Registration Statement No. 2-60015, Exhibits 2(b)(2), 2(b)(3), 2(bX4), 2(b)(5), 2(b)(6), 2(b)(7), 2(b)(8), 2(bX9), 2(b)(10), 2(bX 12), 2(bX14), 2(bXI5), 2(bXI 6), 2(bX17), 2(bX1 8), 2(bXI19), 2(b)(20), 2(bX21), 2(b)(22), 2(b)(23), 2(b)(24), 2(b)(25), 2(bX26), 2(b)(27) and 2(bX28); Registration Statement No. 2-64102, Exhibit 2(b)(29); Registration Statement No. 2-66457, Exhibits (2)(b)(30) and 2(b)(31); Registration Statement No. 2-69217, Exhibit 2(bX32); Registration Statement No. 2-86237, Exhibit 4(b); Registration Statement No. 33-11723, Exhibit 4(b); Registration Statement No. 33-17003, Exhibit 4(a)(ii), Registration Statement No. 33-30964, Exhibit 4(b); Registration Statement No. 33-40720, Exhibit 4(b); Registration Statement No. 33-45219, Exhibit 4(b); Registration Statement No. 33-46128, Exhibits 4(b) and 4(c);Registration Statement No. 33-53410, Exhibit 4(b); Registration Statement No. 33-59834, Exhibit 4(b);Registration Statement No. 33-50229, Exhibits 4(b) and 4(c); Registration Statement No. 33-58431, Exhibits 4(b), 4(c), 4(d) and 4(e); Registration Statement No. 333-01049, Exhibits 4(b) and 4(c); Registration Statement No. 333-20305, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No. 1-3457, Exhibit 4(b); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1998, File No. 1-3457, Exhibit 4(b)].4(b) -Indenture (for unsecured debt securities), dated as of January 1, 1998, between APCo and The Bank of New York, As Trustee [Registration Statement No. 333-45927, Exhibit 4(a); Registration Statement No. 333-49071, Exhibit 4(b); Registration Statement No. 333-84061, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1999, File No. 1-3457, Exhibit 4(c); Registration Statement No. 333-81402, Exhibits 4(b), 4(c) and 4(d); Registration Statement No. 333-100451, Exhibit 4(b);and Annual Report on Form 10-K of APCo for fiscal year ended December 31, 2002, File 1-3457, Exhibit 4(c)].*4(c) -Company Order and Officer's Certificate, dated May 5, 2003, establishing terms of 3.60% Senior Notes, Series G, due 2008 and 5.95% Senior Notes, Series H, due 2033.1 0(aXl) -Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit I0(aXl)(B)]. 10(a)(2) -Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3XB); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No.1-3457, Exhibit 10(a)(2)(B)]. E4 Exhibit Number Dzscription 10(aX3) -Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)].I0(b) -Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, OPCo and l&M and with AEPSC, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(aX3)].10(c) -Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -Modification No. I to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(1)].10(eXI) -Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10 (0].10(e)(2) -Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of APCo dated December 15,1999, File No. 1-3457, Exhibit 10].MAI0((1) -AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)].t10(f)(2) -Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit I0(dX2)].t10(g) -AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit I0(iXI)].f 10(hXl)(A) -AEP System Excess Benefit Plan, Amended and Restated as of January 1,2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31,2000, File No. 1-3525, Exhibit I 00)(1)(A)]. tl0(h)(IXB) -First Amendment to AEP System Excess Benefit Plan, dated as of March 5,2003 [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 2002, File No. 1-3457; Exhibit 10(h)(1)(B)].

¶ I0(h)(2) -AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2003 (Non-Qualified).

t¶I(h)(3) -Service Corporation Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)).

tlo(iXl)

-Employment Agreement betveen AEP, AEPSC and Michael G. Morris dated December 15,2003.t10(i)(2) -Memorandum of agreement between Susan Tomasky and AEPSC dated January 3, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31,2000, File No. 1-3525, Exhibit 10(s)].t10(i)(3) -Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 2002, File No. 1-3457; Exhibit I 0(i)(3)].10(j)(1) -AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10].t¶0(0)(2) -First Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 31, 2000[Annual Report on Form 10-K of APCo for the fiscal year ended December 31,2002, File No. 1-3457; Exhibit I0G)(2)].t1O(k) -AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective March 1, 1999[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 10(o)].t¶0(l) -AEP Change In Control Agreement [Annual Report on Form 10-K of AEP for the fiscal year ended December 31,2001, File No. 1-3525, Exhibit 10(o)].*tlo(m) -AEP System 2000 Long-Term Incentive Plan, as amended December 10,2003.E-5 Exhibit Nulmber Description tlO(n)(l) -Central and South West System Special Executive Retirement Plan as amended and restated effective July 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998, File No. 1-1443, Exhibit 18].tl0(n)(2) -Certified CSW Board Resolution of April 18, 1991 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].

t I0(nX3) -Certified AEP Utilities, Inc. (formerly CSW) Board Resolutions of July 16, 1996.t 10(n)(4) -CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSWV, March 13, 1992].*tl0(o)(1)

-AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1,2003.t I 0(p) -AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998 [Annual Report on Form 10-K of APCo for the fiscal year ended December 31,2002, File No. 1-3457; Exhibit 10(p)].I O(q) -Nuclear Key Contributor Retention Plan dated May 1, 2000 [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 2002, File No. 1-3457; Exhibit 10(q)].* 12 -Statement re: Computation of Ratios.* 13 -Copy of those portions of the APCo 2003 Annual Report (for the fiscal year ended December 31,2003) which are incorporated by reference in this filing.21 -List of subsidiaries of APCo [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2003, File No. 1-3525, Exhibit 21].*23 -Consent of Deloitte & Touche LLP*24 -Power of Attorney.*31(a) -Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*3 1 (b) -Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*32(a) -Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.*32(b) -Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.CSPCo$3(a) -Amended Articles of Incorporation of CSPCo, as amended to March 6, 1992 [Registration Statement No. 33-53377, Exhibit 4(a)].3(b) -Certificate of Amendment to Amended Articles of Incorporation of CSPCo, dated May 19, 1994 [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No. 1-2680, Exhibit 3(b)].3(c) -Composite of Amended Articles of Incorporation of CSPCo, as amended [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No. 1-2680, Exhibit 3(c)].3(d) -Code of Regulations and By-Laws of CSPCo [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1987, File No. 1-2680, Exhibit 3(d)].4(a) -Indenture of Mortgage and Deed of Trust, dated September 1, 1940, between CSPCo and City Bank Farmers Trust Company (now Citibank, N.A.), as trustee, as supplemented and amended [Registration Statement No.2-59411, Exhibits 2(B) and 2(C); Registration Statement No. 2-80535, Exhibit 4(b); Registration Statement No. 2-87091, Exhibit 4(b); Registration Statement No. 2-93208, Exhibit 4(b); Registration Statement No. 2-97652, Exhibit 4(b); Registration Statement No. 33-7081, Exhibit 4(b); Registration Statement No. 33-12389, Exhibit 4(b); Registration Statement No. 33-19227, Exhibits 4(b), 4(e), 4(f), 4(g) and 4(h); Registration Statement No. 33-35651, Exhibit 4(b); Registration Statement No. 33-46859, Exhibits 4(b) and 4(c);Registration Statement No. 33-50316, Exhibits 4(b) and 4(c); Registration Statement No. 33-60336, Exhibits 4(b), 4(c) and 4(d); Registration Statement No. 33-50447, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1993, File No. 1-2680, Exhibit 4(b)].4(b) -Indenture (for unsecured debt securities), dated as of September 1, 1997, between CSPCo and Bankers Trust Company, as Trustee [Registration Statement No. 333-54025, Exhibits 4(a), 4(b), 4(c) and 4(d); Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1998, File No. 1-2680, Exhibits 4(c)and 4(d)].E-6 Exhibit Number DNscriAt ion*4(c) -First Supplemental Indenture betveen CSPCo and Deutsche Bank Trust Company Americas, as Trustee, dated November 25,2003, establishing terms of 4.40% Senior Notes, Series E, due 2010.*4(d) -Indenture (for unsecured debt securities), dated as of February 1, 2003, between CSPCo and Bank One, N.A., as Trustee*4(e) -First Supplemental Indenture, dated as of February 1, 2003, between CSPCo and Bank One, N.A., as trustee, establishing the terms of 5.50% Senior Notes, Series A, due 2013 and 5.50% Senior Notes, Series C, due 2013.*4(f) -Second Supplemental Indenture, dated as of February 1, 2003, between CSPCo and Bank One, N.A.establishing the terms of 6.60% Senior Notes, Series B, due 2033 and 6.60% Senior Notes, Series D, due 2033.°0(aXI) -Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(aXl)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(IXB)]. 10(aX2) -Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No.1-3457, Exhibit 10(a)(2)(B)]. 10(aX3) -Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No.2-60015, Exhibit 5(e)].10(b) -Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, OPCo and I&M and AEPSC, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December31, 1990, File No. 1-3525, Exhibit 10(aX3)].10(c) -Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo, and with AEPSC as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit I 0(b)(2)].10(d) -Modification No. I to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 100)].I0(eXI) -Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)].I 0(e)(2) -Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of CSPCo dated December 15, 1999, File No. 1-2680, Exhibit 10].* 12 -Statement re: Computation of Ratios.*13 -Copy of those portions of the CSPCo 2003 Annual Report (for the fiscal year ended December 31, 2003)which are incorporated by reference in this filing.21 -List of subsidiaries of CSPCo [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2003, File No. 1-3525, Exhibit 21]*23 -Consent of Deloitte & Touche LLP.*24 -Power of Attomey.*31 (a) -Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*31(b) -Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.E-7 Exhibit Nulmber D"cripition

32(a) -Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.*32(b) -Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.I&M: 3(a) -Amended Articles of Acceptance of I&M and amendments thereto [Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1993, File No. 1-3570, Exhibit 3(a)].3(b) -Articles of Amendment to the Amended Articles of Acceptance of l&M, dated March 6, 1997 [Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1996, File No. 1-3570, Exhibit 3(b)].3(c) -Composite of the Amended Articles of Acceptance of I&M (amended as of March 7, 1997) [Annual Report on Form 10-K of l&M for the fiscal year ended December31, 1996, File No. 1-3570, Exhibit 3(c)].3(d) -By-Laws of I&M (amended as of November 28, 2001) [Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 2001, File No. 1-3570, Exhibit 3(d)].4(a) -Mortgage and Deed of Trust, dated as of June 1, 1939, between l&M and Irving Trust Company (now The Bank of New York) and various individuals, as Trustees, as amended and supplemented

[Registration Statement No. 2-7597, Exhibit 7(a); Registration Statement No. 2-60665, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(cX6), 2(c)(7), 2(c)(8), 2(c)(9), 2(c)(1 0), 2(c)( 11), 2(c)( 12), 2(c)(l 3), 2(c)(1 4), 2(c)( 15), (2)(c)(I 6), and 2(c)(17); Registration Statement No. 2-63234, Exhibit 2(b)(18); Registration Statement No. 2-65389, Exhibit 2(aXl9); Registration Statement No. 2-67728, Exhibit 2(b)(20); Registration Statement No. 2-85016, Exhibit 4(b); Registration Statement No. 33-5728, Exhibit 4(c); Registration Statement No. 33-9280, Exhibit 4(b); Registration Statement No. 33-11230, Exhibit 4(b); Registration Statement No. 33-19620, Exhibits 4(a)(ii), 4(aXiii), 4(a)(iv) and 4(a)(v); Registration Statement No. 33-46851, Exhibits 4(b)(i), 4(bXii) and 4(b)(iii); Registration Statement No. 33-54480, Exhibits 4(b)(i) and 4(b)(ii); Registration Statement No. 33-60886, Exhibit 4(b)(i); Registration Statement No. 33-50521, Exhibits 4(b)(i), 4(b)(ii) and 4(b)(iii); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibit 4(b);Annual Report on Form 10-K of l&M for the fiscal year ended December 31, 1994, File No. 1-3570, Exhibit 4(b); Annual Report on Form 10-K of l&M for the fiscal year ended December 31, 1996, File No. 1-3570, Exhibit 4(b)].4(b) -Indenture (for unsecured debt securities), dated as of October 1, 1998, between l&M and The Bank of New York, as Trustee [Registration Statement No. 333-88523, Exhibits 4(a), 4(b) and 4(c); Registration Statement No. 333-58656, Exhibits 4(b) and 4(c); Registration Statement No. 333-108975, Exhibits 4(b), 4(c) and 4(d)].10(aXI) -Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(l)(B); Registration Statement No. 2-66301, Exhibit 5(aXIXC); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit l0(aXl)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(aXl)(B)]. I 0(aX2) -Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(aX3)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No.2-60015, Exhibit 5(e)].I 0(aX4) -Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(aX3)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. E-8 Exhibit Numbher Description 10(b) -Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, I&M, and OPCo and with AEPSC, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No.1-3525, Exhibit 10(a)(3)]. 10(c) -Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(bX2)].10(d) -Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC [Annual Report on Form 10-K of AEP for the fiscal year ended December 1, 1996, File No. 1-3525, Exhibit 10(1)].10(e) -Lease Agreements, dated as of December 1, 1989, between 1&M and Wilmington Trust Company, as amended[Registration Statement No. 33-32753, Exhibits 28(aXl)(C), 28(a)(2XC), 28(a)(3)(C), 28(aX4)(C), 28(a)(5XC) and 28(a)(6)(C); Annual Report on Form 10-K of l&M for the fiscal year ended December 31, 1993, File No.1-3570, Exhibits l0(eXlXB), 10(e)(2XB), 10(eX3)(B), 10(eX4)(B), 10(e)(5)(B) and 10(e)(6XB)]. 10(f)(1) -Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)].10(f)(2) -Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of I&M dated December 15, 1999, File No. 1-3570, Exhibit 10].* 12 -Statement re: Computation of Ratios.* 13 -Copy of those portions of the I&M 2003 Annual Report (for the fiscal year ended December 31, 2003) which are incorporated by reference in this'filing. 21 -List of subsidiaries of I&M [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2003, File No. 1-3525, Exhibit 21].*23 -Consent of Deloitte & Touche LLP.*24 -Power of Attorney.*3 1 (a) -Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*31(b) -Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*32(a) -Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.*32(b) -Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.KPCot 3(a) -Restated Articles of Incorporation of KPCo [Annual Report on Form 10-K of KPCo for the fiscal year ended December 31, 1991, File No. 1-6858, Exhibit 3(a)].3(b) -By-Laws of KPCo (amended as of June 15, 2000) [Annual Report on Forrn 10-K of KPCo for the fiscal year ended December 31, 2000, File No. 1-6858, Exhibit 3(b)].4(a) -Indenture (for unsecured debt securities), dated as of September 1, 1997, between KPCo and Bankers Trust Company, as Trustee [Registration Statement No. 333-75785, Exhibits 4(a), 4(b), 4(c) and 4(d); Registration Statement No. 333-87216, Exhibits 4(e) and 4(f); Annual Report on Form 10-K of KPCo for the fiscal year ended December 31,2002, File No. 1-6858, Exhibits 4(c), 4(d) and 4(e)].*4(b) -Company Order and Officer's Certificate, dated June 13, 2003 establishing certain terms of the 5.625% Senior Notes, Series D, due 2032.10(a) -Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, I&M and OPCo and with AEPSC, as amended [Registration Statement No. 2-52910, Exhibit 5(a);Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No.1-3525, Exhibit 10(a)(3)]. E-9 Exlhibit Number Description 10(b) -Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(bX2)].10(c) -Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(1)].10(d)(1) -Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)].I 0(d)(2) -Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of KPCo dated December 15, 1999, File No. 1-6858, Exhibit 10].* 12 -Statement re: Computation of Ratios.* 13 -Copy of those portions of the KPCo 2003 Annual Report (for the fiscal year ended December 31,2003) which are incorporated by reference in this filing.*23 -Consent of Deloitte & Touche LLP*24 -Power of Attorney.*31(a) -Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*31(b) -Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*32(a) -Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.*32(b) -Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.OPCot 3(a) -Amended Articles of Incorporation of OPCo, and amendments thereto to December 31, 1993 [Registration Statement No. 33-50139, Exhibit 4(a); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, FileNo. 1-6543, Exhibit 3(b)].3(b) -Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated May 3, 1994 [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 3(b)].3(c) -Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated March 6, 1997 [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1996, File No. 1-6543, Exhibit 3(c)].3(d) -Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated June 3, 2002 [Quarterly Report on Form 10-Q of OPCo for the quarter ended June 30,2002, File No. 1-6543, Exhibit 3(d)].3(e) -Composite of the Amended Articles of Incorporation of OPCo (amended as of June 3, 2002) [[Quarterly Report on Form 10-Q of OPCo for the quarter ended June 30, 2002, File No. 1-6543, Exhibit 3(e)].3(f) -Code of Regulations of OPCo [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1990, File No. 1-6543, Exhibit 3(d)].4(a) -Mortgage and Deed of Trust, dated as of October 1, 1938, between OPCo and Manufacturers Hanover Trust Company (now Chemical Bank), as Trustee, as amended and supplemented [Registration Statement No. 2-3828, Exhibit B-4; Registration Statement No. 2-60721, Exhibits 2(c)(2), 2(c)(3), 2(cX4), 2(cX5), 2(c)(6), 2(cX7), 2(c)(8), 2(c)(9), 2(c)(10), 2(cX 1), 2(c)(12), 2(cX13), 2(cX14), 2(c)(l5), 2(c)(16), 2(c)(17), 2(c)(18), 2(c)(19), 2(c)(20), 2(c)(21), 2(cX22), 2(c)(23), 2(c)(24), 2(cX25), 2(cX26), 2(c)(27), 2(c)(28), 2(c)(29), 2(c)(30), and 2(c)(31); Registration Statement No. 2-83591, Exhibit 4(b); Registration Statement No. 33-21208, Exhibits 4(a)(ii), 4(a)(iii) and 4(aXiv); Registration Statement No. 33-31069, Exhibit 4(aXii);Registration Statement No. 33-44995, Exhibit 4(aXii); Registration Statement No. 33-59006, Exhibits 4(a)(ii), 4(aXiii) and 4(aXiv); Registration Statement No. 33-50373, Exhibits 4(aXii), 4(aXiii) and 4(aXiv); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 4(b)].E-10 Exhibit Nulmber Dmesription 4(b) -Indenture (for unsecured debt securities), dated as of September 1, 1997, between OPCo and Bankers Trust Company (now Deutsche Bank Trust Company Americas), as Trustee [Registration Statement No. 33349595, Exhibits 4(a), 4(b) and 4(c); Registration Statement No. 333-106242, Exhibit 4(b), 4(c) and 4(d); Registration Statement No. 333-75783, Exhibits 4(b) and 4(c)].*4(c) -First Supplemental Indenture between OPCo and Deutsche Bank Trust Company Americas, as Trustee, dated July 11,2003, establishing terms of 4.85% Senior Notes, Series H, due 2014.*4(d) -Second Supplemental Indenture between OPCo and Deutsche Bank Trust Company Americas, as Trustee, dated July 11, 2003, establishing terms of 6.375% Senior Notes, Series 1, due 2033.*4(e) -Indenture (for unsecured debt securities), dated as of February 1, 2003, between OPCo and Bank One, N.A., as Trustee*4(f) -First Supplemental Indenture, dated as of February 1, 2003, between OPCo and Bank One, N.A., as Trustee, establishing the terms of 5.50% Senior Notes, Series D, due 2013 and 5.50% Senior Notes, Series F, due 2013.*4(g) -Second Supplemental Indenture, dated as of February 1, 2003, between OPCo and Bank One, N.A., as Trustee, establishing the terms of 6.60% Senior Notes, Series E, due 2033 and 6.60% Senior Notes, Series G, due 2033.1 0(a)(1) -Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1XB); Registration Statement No. 2-66301, Exhibit 5(a)(IXC); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(aXl)(F); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit I 0(aX1IXB)]. 1 0(aX2) -Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the. Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Forrn 10-K of APCo for the fiscal year ended December 31, 1992, File No. I-3457, Exhibit 10(a)(2)(B)]. 10(aX3) -Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)].10(b) -Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, 1&M and OPCo and with AEPSC, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File 1-3525, Exhibit 10(aX3)].10(c) -Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. I-3525, Exhibit 10(bX2)].10(d) -Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(1)].10(e) -Amendment No. 1, dated October 1, 1973, to Station Agreement dated January 1, 1968, among OPCo, Buckeye and Cardinal Operating Company, and amendments thereto [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 10(f)].10(f) -Lease Agreement dated January 20, 1995 between OPCo and JMG Funding, Limited Partnership, and amendment thereto (confidential treatment requested) [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No; 1-6543, Exhibit 10(1)X2)]. 10(gxl) -Agreement and Plan of Merger, dated as of December 21, 1997, by and among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)].E-1 I FExhihit Nuimber Dcscri pt ion 1O(g)(2) -Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of OPCo dated December 15, 1999, File No. 1-6543, Exhibit 10].10(h) -AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit I0(i)(1)]. t I 0(i)(1)(A) -AEP System Excess Benefit Plan, Amended and Restated as of January 1,2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December31, 2000, FileNo. 1-3525, Exhibit I100)(l)(A)]. t lO(i)( l )(B) -First Amendment to AEP System Excess Benefit Plan, dated as of March 5,2003 [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 2002, File No. 1-6543; Exhibit I 0(iX l)(B)].*t1 0(i)(2) -AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2003 (Non-Qualified). f 10(i)(3) -Service Corporation Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)].

t 10i)(1) -Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 15,2003.t 10()(2) -Memorandum of agreement between Susan Tomasky and AEPSC dated January 3, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31,2000, File No. 1-3525, Exhibit I O(s)].Il0(j)(3)

-Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers [Annual Report on Form I0-K of OPCo for the fiscal year ended December31, 2002, File No. 1-6543; Exhibit 100)(3)].f110(k)(1) -AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form I 0-Q of AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 101.t 10(k)(2) -First Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 31, 2000[Annual Report on Form 10-K of OPCo for the fiscal year ended December 31,2002, File No. 1-6543; Exhibit I 0(kX2)].t 1(1) -AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective March 1, 1999[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 10(o)].tO0(m) -AEP Change In Control Agreement [Annual Report on Form I0-K of AEP for the fiscal year ended December 31,2001, File No. 1-3525, Exhibit 10(o)].*t10(n) -AEP System 2000 Long-Term Incentive Plan, as amended December 10, 2003.10(o)(1) -Central and South West System Special Executive Retirement Plan as amended and restated effective July 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998, File No. 1-1443, Exhibit 18].f 10(o)(2) -Certified CSW Board Resolution of April 18, 1991 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit l0(r)(2)].

tI 0(oX3) -Certified AEP Utilities, Inc. (formerly CSW) Board Resolutions of July 16, 1996.tlO(oX4) -CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSNV, March 13, 1992].*tlo(p) -AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1,2003.tl°(q) -AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998 [Annual Report on Form I 0-K of OPCo for the fiscal year ended December 31,2002, File No. 1-6543; Exhibit O(q)].110(r) -Nuclear Key Contributor Retention Plan dated May 1, 2000 [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31,2002, File No. 1-6543; Exhibit 1 0(r)].* 12 -Statement re: Computation of Ratios.* 13 -Copy of those portions of the OPCo 2003 Annual Report (for the fiscal year ended December 31,2003) which are incorporated by reference in this filing.21 -List of subsidiaries of OPCo [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2003, File No. 1-3525, Exhibit 21].*23 -Consent of Deloitte & Touche LLP.*24 -Power of Attorney.E-12 Exhibit Number Description
31(a) -NCertification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*31(b) -Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*32(a) -Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.*32(b) -Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.PSot 3(a) -Restated Certificate of Incorporation of PSO [Annual Report on Form U5S of Central and South West Corporation forthe fiscal year endedDecember31, 1996, File No. 1-1443, Exhibit B-3.1].3(b) -By-Laws of PSO (amended as of June 28, 2000) [Annual Report on Form 10-K of PSO for the fiscal year ended December 31,2000, File No. 0-343, Exhibit 3(b)].4(a) -Indenture, dated July 1, 1945, between and Liberty Bank and Trust Company of Tulsa, National Association, as Trustee, as amended and supplemented

[Registration Statement No. 2-60712, Exhibit 5.03; Registration Statement No. 2-64432, Exhibit 2.02; Registration Statement No. 2-65871, Exhibit 2.02; Form U-1 No. 70-6822, Exhibit 2; Form U-I No. 70-7234, Exhibit 3; Registration Statement No. 33-48650, Exhibit 4(b);Registration Statement No. 33-49143, Exhibit 4(c); Registration Statement No. 33-49575, Exhibit 4(b);Annual Report on Form 10-K of PSO for the fiscal year ended December 31, 1993, File No. 0-343, Exhibit 4(b); Current Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.01; Current Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.02; Current Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.03].4(b) -PSO-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of PSO: (I) Indenture, dated as of May 1, 1997, between PSO and The Bank of New York, as Trustee [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibits 4.6 and 4.7].(2) Amended and Restated Trust Agreement of PSO Capital I, dated as of May 1, 1997, among PSO, as Depositor, The Bank of New York, as Property Trustee, The Bank of New York (Delaware), as Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibit 4.8].(3) Guarantee Agreement, dated as of May 1, 1997, delivered by PSO for the benefit of the holders of PSO Capital I's Preferred Securities [Quarterly Report on Form I0-Q of PSO dated March 31, 1997, File No. 0-343, Exhibits 4.9].(4) Agreement as to Expenses and Liabilities, dated as of May 1, 1997, between PSO and PSO Capital I[Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibits 4.10].4(c) -Indenture (for unsecured debt securities), dated as of November 1, 2000, between PSO and The Bank of New York, as Trustee [Registration Statement No. 333-100623, Exhibits 4(a) and 4(b); [Annual Report on Form 10-K of PSO for the fiscal year ended December 31,2002, File No. 0-343; Exhibit 4(c)].*4(d) -Third Supplemental Indenture, dated as of September 15, 2003, between PSO and The Bank of New York, as Trustee, establishing terms of the 4.85% Senior Notes, Series C, due 2010.10(a) -Restated and Amended Operating Agreement, dated as of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual Report on Form 10-K of PSO for the fiscal year ended December 31, 2002, File No. 0-343; Exhibit 10(a)].10(b) -Transmission Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual Report on Form 10-K of PSO for the fiscal year ended December 31, 2002, File No. 0-343;Exhibit 10(b)].* 12 -Statement re: Computation of Ratios.* 13 -Copy of those portions of the PSO 2003 Annual Report (for the fiscal year ended December 31, 2003) which are incorporated by reference in this filing.*23 -Consent of Deloitte & Touche LLP.*24 -Power of Attorney.E-13 Exhibit Number Dewoription

3h1 (a) -Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*31 (b) -Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*32(a) -Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.*32(b) -Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.SWVEPCot 3(a) -Restated Certificate of Incorporation, as amended through May 6, 1997, including Certificate of Amendment of Restated Certificate of Incorporation

[Quarterly Report on Form 10-Q of SWEPCo for the quarter ended March 31, 1997, File No. 1-3146, Exhibit 3.4].3(b) -By-Laws of SWVEPCo (amended as of April 27, 2000) [Quarterly Report on Form 10-Q of SWEPCo for the quarter ended March 31, 2000, File No. 1-3146, Exhibit 3.3].4(a) -Indenture, dated February 1, 1940, between SWVEPCo and Continental Bank, National Association and M. J.Kruger, as Trustees, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.04;Registration Statement No. 2-61943, Exhibit 2.02; Registration Statement No. 2-66033, Exhibit 2.02;Registration Statement No. 2-71126, Exhibit 2.02; Registration Statement No. 2-77165, Exhibit 2.02; Form U-I No. 70-7121, Exhibit 4; Form U-I No. 70-7233, Exhibit 3; Form U-I No. 70-7676, Exhibit 3; Form U-1 No.70-7934, Exhibit 10; Form U-I No. 72-8041, Exhibit 10(b); Form U-I No. 70-8041, Exhibit 10(c); Form U-I No. 70-8239, Exhibit 10(a)].*4(b) -SWEPCO-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of SWVEPCo: (1) Subordinated Indenture, dated as of September 1, 2003, between SWEPCo and The Bank of New York, as Trustee.(2) Amended and Restated Trust Agreement of SWEPCo Capital Trust 1, dated as of September 1, 2003, among SWEPCo, as Depositor, The Bank of New York, as Property Trustee, The Bank of New York (Delaware), as Delaware Trustee, and the Administrative Trustees.(3) Guarantee Agreement, dated as of September 1, 2003, delivered by SWEPCo for the benefit of the holders of SWEPCo Capital Trust I's Preferred Securities. (4)First Supplemental Indenture dated as of October 1, 2003, providing for the issuance of Series B Junior Subordinated Debentures between SWEPCo, as Issuer and The Bank of New York, as Trustee (5)Agreement as to Expenses and Liabilities, dated as of October 1, 2003 between SWEPCo and SWEPCo Capital Trust I (included in Item (4) above as exhibit 4(f)(i)(A). 4(c) -Indenture (for unsecured debt securities), dated as of February 4, 2000, betveen SWVEPCo and The Bank of New York, as Trustee [Registration Statement No. 333-87834, Exhibits 4(a) and 4(b); Registration Statement No. 333-100632, Exhibit 4(b); Registration Statement No. 333-108045 Exhibit 4(b)].*4(d) -Third Supplemental Indenture, betwveen SWEPCo and The Bank of New York, as Trustee, dated April 11, 2003, establishing terms of 5.375% Senior Notes, Series C, due 2015.10(a) -Restated and Amended Operating Agreement, dated as of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual Report on Form 10-K of SWEPCo for the fiscal year ended December 31,2002, File No.1-3146; Exhibit 10(a)].10(b) -Transmission Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual Report on Form 10-K of SWEPCo for the fiscal year ended December 31, 2002, File No. 1-3146; Exhibit 10(b)].* 12 -Statement re: Computation of Ratios.* 13 -Copy of those portions of the SWEPCo 2003 Annual Report (for the fiscal year ended December 31, 2003)which are incorporated by reference in this filing.21 -List of subsidiaries of SWEPCo [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2003, File No. 1-3525, Exhibit 21]*23 -Consent of Deloitte & Touche LLP.E-14 Exhibit Number Descripltion

24 -Power of Attorney.*31(a) -Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*31(b) -Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*32(a) -Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.*32(b) -Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.TCCt 3(a) -Restated Articles of Incorporation Without Amendment, Articles of Correction to Restated Articles of Incorporation Without Amendment, Articles of Amendment to Restated Articles of Incorporation, Statements of Registered Office and/or Agent, and Articles of Amendment to the Articles of Incorporation

[Quarterly Report on Form I0-Q of TCC for the quarter ended March 31, 1997, File No. 0-346, Exhibit 3.1].3(b) -Articles of Amendment to Restated Articles of Incorporation of TCC dated December 18, 2002 [Annual Report on Form 10-K of TCC for the fiscal year ended December 31,2002, File No. 0-346; Exhibit 3(b)].3(c) -By-Laws of TCC (amended as of April 19, 2000) [Annual Report on Form 10-K of TCC for the fiscal year ended December 31, 2000, File No. 0-346, Exhibit 3(b)].4(a) -Indenture of Mortgage or Deed of Trust, dated November 1, 1943, between TCC and The First National Bank of Chicago and R. D. Manella, as Trustees, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.01; Registration Statement No. 2-62271, Exhibit 2.02; Form U-I No. 70-7003, Exhibit 17;Registration Statement No. 2-98944, Exhibit 4 (b); Form U-I No. 70-7236, Exhibit 4; Form U-1 No. 70-7249, Exhibit 4; Form U-1 No. 70-7520, Exhibit 2; Form U-I No. 70-7721, Exhibit 3; Form U-I No. 70-7725, Exhibit 10; Form U-I No. 70-8053, Exhibit 10 (a); Form U-1 No. 70-8053, Exhibit 10 (b); Form U-I No. 70-8053, Exhibit 10 (c); Form U-l No.70-8053, Exhibit 10 (d); Form U-I No. 70-8053, Exhibit 10 (e); Form U-I No. 70-8053, Exhibit 10 (f)].4(b) -TCC-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of TCC: (I) Indenture, dated as of May 1, 1997, between TCC and The Bank of New York, as Trustee [Quarterly Report on Form I0-Q of TCC dated March 31, 1997, File No. 0-346, Exhibits 4.1 and 4.2].(2) Amended and Restated Trust Agreement of TCC Capital 1, dated as of May 1, 1997, among TCC, as Depositor, the Bank of New York, as Property Trustee, The Bank of New York (Delaware), as Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form 10-Q of TCC dated March 31, 1997, File No. 0-346, Exhibit 4.3].(3) Guarantee Agreement, dated as of May 1, 1997, delivered by TCC for the benefit of the holders of TCC Capital l's Preferred Securities [Quarterly Report on Form I0-Q of TCC dated March 31, 1997, File No. 0-346, Exhibit 4.4].(4) Agreement as to Expenses and Liabilities dated as of May 1, 1997, between TCC and TCC Capital I[Quarterly Report on Form 10-Q of TCC dated March 31, 1997, File No. 0-346, Exhibit 4.5].4(c) -Indenture (for unsecured debt securities), dated as of November 15, 1999, between TCC and The Bank of New York, as Trustee, as amended and supplemented [Annual Report on Form 10-K of TCC for the fiscal year ended December 31, 2000, File No. 0-346, Exhibits 4(c), 4(d) and 4(e)].*4(d) -Indenture (for unsecured debt securities), dated as of February 1, 2003, between TCC and Bank One, N.A., as Trustee*4(e) -First Supplemental Indenture, dated as of February 1, 2003, between TCC and Bank One, N.A., as Trustee, establishing the terms of 5.50% Senior Notes, Series A, due 2013 and 5.50% Senior Notes, Series D, due 2013.*4(f) -Second Supplemental Indenture, dated as of February 1, 2003, between TCC and Bank One, NA., as Trustee, establishing the terms of 6.65% Senior Notes, Series B, due 2033 and 6.65% Senior Notes, Series E, due 2033.*4(g) -Third Supplemental Indenture, dated as of February 1, 2003, between TCC and Bank One, N.A., as Trustee, establishing the terms of 3.00%/c Senior Notes, Series C, due 2005 and 3.00% Senior Notes, Series F, due 2005.E-15 Exhibit Number Description

4(h) -Fourth Supplemental Indenture, dated as of February 1, 2003, between TCC and Bank One, N.A., as Trustee, establishing the terms of Floating Rate Notes, Series A, due 2005 and Floating Rate Notes, Series B, due 2005.10(a) -Restated and Amended Operating Agreement, dated as of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual Report on Form 10-K of TCC for the fiscal year ended December 31, 2002, File No. 0-346; Exhibit 10(a)].10(b) -Transmission Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual Report on Form 1 0-K of TCC for the fiscal year ended December 31, 2002, File No. 0-346;Exhibit 10(b)].* 12 -Statement re: Computation of Ratios.* 13 -Copy of those portions of the TCC 2003 Annual Report (for the fiscal year ended December 31, 2003) which are incorporated by reference in this filing.21 -List of subsidiaries of TCC [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2003, File No. 1-3525, Exhibit 21]*23 -Consent of Deloitte & Touche LLP.*24 -Power of Attorney.*31(a) -Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*31(b) -Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*32(a) -Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.*32(b) -Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.TNCt 3(a) -Restated Articles of Incorporation, as amended, and Articles of Amendment to the Articles of Incorporation

[Annual Report on Form 10-K of TNC for the fiscal year ended December 31, 1996, File No. 0-340, Exhibit 3.51.3(b) -Articles of Amendment to Restated Articles of Incorporation of TNC dated December 17, 2002 [Annual Report on Form 10-K of TNC for the fiscal year ended December 31,2002, File No. 0-340; Exhibit 3(b)].3(c) -By-Laws of TNC (amended as of May 1,2000) [Quarterly Report on Form 10-Q of TNC for the quarter ended March 31,2000, File No. 0-340, Exhibit 3.4].4(a) -Indenture, dated August 1, 1943, between TNC and Harris Trust and Savings Bank and J. Bartolini, as Trustees, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.05; Registration Statement No. 2-63931, Exhibit 2.02; Registration Statement No. 2-74408, Exhibit 4.02; Form U-I No. 70-6820, Exhibit 12; Form U-i No. 70-6925, Exhibit 13; Registration Statement No. 2-98843, Exhibit 4(b); Form U-I No. 70-7237, Exhibit 4; Form U-I No. 70-7719, Exhibit 3; Form U-I No. 70-7936, Exhibit 10; Form U-i No. 70-8057, Exhibit 10; Formn U-I No. 70-8265, Exhibit 10; Form U-I No. 70-8057, Exhibit 10(b); Form U-I No. 70-8057, Exhibit 10(c)].*4(b) -Indenture (for unsecured debt securities), dated as of February 1, 2003, between TNC and Bank One, N.A., as Trustee*4(c) -First Supplemental Indenture, dated as of February 1, 2003, between TNC and Bank One, N.A., as Trustee, establishing the terms of 5.50% Senior Notes, Series A, due 2013 and 5.50% Senior Notes, Series D, due 2013.10(a) -Restated and Amended Operating Agreement, dated as of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual Report on Form 10-K of TNC for the fiscal year ended December 31, 2002, File No. 0-340; Exhibit 10(a)].10(b) -Transmission Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual Report on Form 10-K of TNC for the fiscal year ended December 31, 2002, File No. 0-340;Exhibit 10(b)].* 12 -Statement re: Computation of Ratios.E-16 Exhibit Number bmsriptinn

13 -Copy of those portions of the TNC 2003 Annual Report (for the fiscal year ended December 31, 2003) which are incorporated by reference in this filing.*24 -Power of Attorney.*31(a) -Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*31(b) -Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*32(a) -Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.*32(b) -Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.$ Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants.

The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request.E-17 EXHIBIT 3(d)AMERICAN ELECTRIC POWER COMPANY, INC.(Formerly American Gas & Electric Company)BY-LAWS As Amended December 15, 2003 As of 12/15/03 AMERICAN ELECTRIC POWER COMPANY, INC.(Formerly American Gas and Electric Company)BY-LAWS Section 1. The annual meeting of the stockholders of the Company shall be held on the fourth Wednesday of April in each year, or on such other date as determined by the Board of Directors, at an hour and place within or without the State of New York designated by the Board of Directors. (As amended January 28,1998.)Section 2. Special meetings of the stockholders of the Company may be held upon call of the Board of Directors or of the Executive Committee, or of stockholders holding one-fourth of the capital stock, at such time and at such place within or without the State of New York as may be stated in the call and notice. (As amended July 26, 1989.)Section 3. Notice of time and place of every meeting of stockholders shall be mailed at least ten days previous thereto to each stockholder of record who shall have furnished a written address to the Secretary of the Company for the purpose. Such further notice shall be given as may be required by law. But meetings may be held without notice if all stockholders are present, or if notice is waived by those not present.Section 4. Except as otherwise provided by law, the holders of a majority of the outstanding capital stock of the Company entitled to vote at any meeting of the stockholders of the Company must be present in person or by proxy at such meeting of the stockholders of the Company to constitute a quorum. If, however, such majority shall not be represented at any meeting of the stockholders of the Company regularly called, the holders of a majority of the shares present or represented and entitled to vote thereat shall have power to adjourn such meeting to another time without notice other than announcement of adjournment at the meeting, and there may be successive adjournments for like cause and in like manner until the requisite amount of shares entitled to vote at such meeting shall be represented. (As amended May 20, 1952.)Section 5. As soon as may be after their election in each year, the Board of Directors or the Executive Committee shall appoint three inspectors of stockholders' votes and elections to serve until the final adjournment of the next annual stockholders' meeting. If they fail to make such appointment, or if their appointees, or any of them, fail to appear at any meeting of stockholders, the Chairman of the meeting may appoint inspectors, or an inspector, to act at that meeting.Section 6. Meetings of the stockholders shall be presided over by the Chairman of the Board, or if he is not present, by the President, or, if neither the Chairman of the Board nor the President is present, by a Vice President, and in his absence, by a Chairman to'be elected at the meeting. The Secretary of the Company shall act as Secretary of such meetings, if present. (As amended January 23,1979.)2 Section 7. The Board of Directors shall consist of such number of directors, not less than nine (9) nor more than seventeen (17), as shall be determined from time to time as herein provided.Directors shall be elected at each annual meeting of stockholders and each director so elected shall hold office until the next annual meeting of stockholders and until his successor is elected and qualified. The number of directors to be elected at any annual meeting of stockholders shall, except as otherwise provided herein, be the number fixed in the latest resolution of the Board of Directors adopted pursuant to the authority contained in the next succeeding sentence and not subsequently rescinded. The Board of Directors shall have power from time to time and at any time when the stockholders are not assembled as such in an annual or special meeting, by resolution adopted by a majority of the directors then in office, or such greater number required by law, to fix, within the limits prescribed by this Section 7, the number of directors of the Company. If the number of directors is increased, the additional directors may, to the extent permitted by law, be elected by a majority of the directors in office at the time of the increase, or, if not so elected prior to the next annual meeting of stockholders, such additional directors shall be elected at such annual meeting.If the number of directors is decreased, then to the extent that the decrease does not exceed the number of vacancies in the Board then existing, such resolution may provide that it shall become effective forthwith, and to the extent that the decrease exceeds such number of vacancies such resolution shall provide that it shall not become effective until the next election of directors by the stockholders. If the Board of Directors shall fail to adopt a resolution which fixes initially the number of directors, the number of directors shall be twvelve (12). If, after the number of directors shall have been fixed by such resolution, such resolution shall cease to be in effect other than by being superseded by another such resolution, or it shall become necessary that the number of directors be fixed by these By-Laws, the number of directors shall be that number specified in the latest of such resolutions, whether or not such resolution continues in effect. (As amended April 23, 1997.)Section 8. Vacancies in the Board of Directors may be filled by the Board at any meeting.Section 9. Meetings of the Board of Directors shall be held at times fixed by resolution of the Board, or upon the call of the Executive Committee, the Chairman of the Board, the President or the Presiding Director and the Secretary or officer performing his duties shall give reasonable notice of all meetings of directors; provided, that a meeting may be held without notice immediately after the annual election at the same place, and notice need not be given of regular meetings held at times fixed by resolution of the Board. Meetings may be held at any time without notice if all the directors are present, or if those not present waive notice either before or after the meeting. The number of directors necessary to constitute a quorum for the transaction of business shall be any number, which may be less than a majority of the Board but not less than one-third of its number, duly assembled at a meeting of such directors. Any one or more members of the Board or of any committee thereof may participate in a meeting of the Board or such committee by means of a conference telephone or similar communications equipment alloi ing all persons participating in the meeting to hear each other at the same time. Participation by such means constitutes presence in person at a meeting. (As amended December 10, 2003.)Section 10. The Board of Directors, by resolution adopted by a majority of the entire Board, may designate among its members an Executive Committee and one or more other committees, each consisting of three (3) or more directors, and each of which, to the extent provided in such resolution, shall have all the authority of the Board. However, no such committee shall have authority as to any of the following matters: 3 (a) The submission to shareholders of any action as to which shareholders' authorization is required by law;(b) The filling of vacancies in the Board of Directors or in any committee;(c) The fixing of compensation of any director for serving on the Board or on any committee;(d) The amendment or repeal of these By-Lalvs or the adoption of new By-Laws; or (c) The amendment or repeal of any resolution of the Board which by its terms shall not be so amendable or repealable. The Board of Directors shall have the power at any time to increase or decrease the number of members of any committee (provided that no such decrease shall reduce the number of members to less than three), to fill vacancies on it, to remove any member of it, and to change its functions or terminate its existence. Each committee may make such rules for the conduct of its business as it may deem necessary. A majority of the members of a committee shall constitute a quorum.The Board of Directors shall also have the power to designate or appoint at any time and from time to time one or more individuals who have acquired as a former director or officer of the Company substantial experience with the Company's affairs as an Honorary Director, such individual or individuals to meet with the Board of Directors, or certain of the directors, at the invitation of the Chairman of the Board, from time to time for the purpose of rendering advice to the Board of Directors or such directors with respect to the Company's affairs for such compensa-tion as shall be payable to directors of the Company who are not serving, at the time in question, as officers or employees of the Company or of American Electric Power Service Corporation; provided, however, that under no circumstances shall such individual or individuals be authorized or empowered to participate in the management or direction of the affairs of the Company or to perform the functions of a director or officer of the Company (as each such term is defined by the provisions of Rule 70 promulgated by the Securities and Exchange Commission under the provisions of Section 17(c) of the Public Utility Holding Company Act of 1935, as such definition shall be in effect at any time in question) or any similar function. (As amended April 26, 1978.)Section 11. The Board of Directors, as soon as may be after the election each year, shall appoint one of their number Chairman of the Board and one of their number President of the Company, and shall appoint one or more Vice Presidents, a Secretary and a Treasurer, and from time to time shall appoint such other officers as they deem proper. The same person may be appointed to more than one office. (As amended January 23, 1979.)Section 12. The term of office of all officers shall be one year, or until their respective successors are elected but any officer may be removed from office at any time by the Board of Directors, unless otherwise agreed by agreement in writing duly authorized by the Board of Directors. (As amended December 15,2003.)Section 13. The officers of the Company shall have such powers and duties as generally pertain to their offices, respectively, as well as such powers and duties as from time to time shall be conferred by the Board of Directors or the Executive Committee. 4 Section 14. The stock of the Company shall be transferable or assignable only on the books of the Company by the holders, in person or by attorney, on the surrender of the certificate therefor. The Board of Directors may appoint such Transfer Agents and Registrars of stock as to them may seem expedient. Section 15. To the fullest extent permitted by law, the Company shall indemnify any person made, or threatened to be made, a party to any action or proceeding (formal or informal), whether civil, criminal, administrative or investigative and whether by or in the right of the Company or otherwise, by reason of the fact that such person, such person's testator or intestate, is or was a director, officer or employee of the Company, or of any subsidiary or affiliate of the Company, or served any other corporation, partnership, joint venture, trust, employee benefit plan or other enterprise in any capacity at the request of the Company, against all loss and expense including, without limiting the generality of the foregoing, judgments, fines (including excise taxes), amounts paid in settlement and attorneys' fees and disbursements actually and necessarily incurred as a result of such action or proceeding, or any appeal therefrom, and all legal fees and expenses incurred in successfully asserting a claim for indemnification pursuant to this Section 15; provided, however, that no indemnification may be made to or on behalf of any director, officer or employee if a judgment or other final adjudication adverse to the director, officer or employee establishes that such person's acts were committed in bad faith or w ere the result of active and deliberate dishonesty and were material to the cause of action so adjudicated, or that such person personally gained in fact a financial profit or other advantage to which such person was not legally entitled.In any case in which a director, officer or employee of the Company (or a representative of the estate of such director, officer or employee) requests indemnification, upon such person's request the Board of Directors shall meet within sixty days thereof to determine whether such person is eligible for indemnification in accordance with the standard set forth above. Such a person claiming indemnification shall be entitled to indemnification upon a determination that no judgment or other final adjudication adverse to such person has established that such person's acts were committed in bad faith or were the result of active and deliberate dishonesty and were material to the cause of action so adjudicated, or that such person personally gained in fact a financial profit or other advantage to which such person was not legally entitled. Such determination shall be made: (a) by the Board of Directors acting by a quorum consisting of directors who are not parties to the action or proceeding in respect of which indemnification is sought; or (b) if such quorum is unobtainable or if directed by such quorum, then by either (i)the Board of Directors upon the opinion in writing of independent legal counsel that indemnification is proper in the circumstances because such person is eligible for indemnification in accordance avith the standard set forth above, or (ii) by the stockholders upon a finding that such person is eligible for indemnification in accordance with the standard set forth above. Notiiithstanding the foregoing, a determination of eligibility for indemnification may be made in any manner permitted by law.To the fullest extent permitted by law, the Company shall promptly advance to any person made, or threatened to be made, a party to any action or proceeding (formal or informal), whether civil, criminal, administrative or investigative and whether by or in the right of the Company or otherwise, by reason of the fact that such person, such person's testator or intestate, is or was a 5 director, officer or employee of the Company, or of any subsidiary or affiliate of the Company, or served any other corporation or any partnership, joint venture, trust, employee benefit plan or other enterprise in any capacity at the request of the Company, expenses incurred in defending such actions or proceedings, upon request of such person and receipt of an undertaking by or on behalf of such director, officer or employee to repay amounts advanced to the extent that it is ultimately determined that such person was not eligible for indemnification in accordance with the standard set forth above.The foregoing provisions of this Section 15 shall be deemed to be a contract between the Company and each director, officer or employee of the Company, or its subsidiaries or affiliates, and any modification or repeal of this Section 15 or such provisions of the New York Business Corporation Law shall not diminish any rights or obligations existing prior to such modification or repeal ' ith respect to any action or proceeding theretofore or thereafter brought; provided, however, that the right of indemnification provided in this Section 15 shall not be deemed exclusive of any other rights to which any director, officer or employee of the Company may now be or hereafter become entitled apart from this Section 15, under any applicable law including the New York Business Corporation Law. Irrespective of the provisions of this Section 15, the Board of Directors may, at any time or from time to time, approve indemnification of directors, officers, employees or agents to the full extent permitted by the New York Business Corporation Law at the time in effect, ,s'hether on account of past or future actions or transactions. Not-iithstanding the foregoing, the Company shall enter into such additional contracts providing for indemnification and advancement of expenses w ith directors, officers or employees of the Company or its subsidiaries or affiliates as the Board of Directors shall authorize, provided that the terms of any such contract shall be consistent with the provisions of the New York Business Corporation Law.As used in this Section 15, the term "employee" shall include, without limitation, any employee, including any professionally licensed employee, of the Company. Such term shall also include, without limitation, any employee, including any professionally licensed employee, of a subsidiary or affiliate of the Company who is acting on behalf of the Company.The indemnification provided by this Section 15 shall be limited with respect to directors, officers and controlling persons to the extent provided in any undertaking entered into by the Company or its subsidiaries or affiliates, as required by the Securities and Exchange Commission pursuant to any rule or regulation of the Securities and Exchange Commission now or hereafter in effect.If any action with respect to indemnification of directors or officers is taken by way of amendment to these By-Laws, resolution of the Board of Directors, or by agreement, then the Company shall give such notice to the stockholders as is required by law.The Company may purchase and maintain insurance on behalf of any person described in this Section 15 against any liability which may be asserted against such person whether or not the Company would have the power to indemnify such person against such liability under the provisions of this Section 15 or otherwise. If any provision of this Section 15 shall be found to be invalid or limited in application by reason of any law, regulation or proceeding, it shall not affect any other provision or the validity of the remaining provisions hereof.6 The provisions of this Section 15 shall be applicable to claims, actions, suits or proceedings made, commenced or pending after the adoption hereof, whether arising from acts or omissions to act occurring before or after the adoption hereof. (As amended October 29, 1986.)Section 16. These By-Lawvs may be amended or added to at any meeting of the Board of Directors by affirmative vote of a majority of all of the directors, if notice of the proposed change has been delivered or mailed to the directors five days before the meeting, or if all the directors are present, or if all not present assent in writing to such change; provided, however, that the provisions of Section 7 relating to the number of directors constituting the Board of Directors may be amended only by the affirmative vote, in person or by proxy, of the holders of a majority of the outstanding shares of capital stock entitled to vote at any meeting of the stockholders of the Company; and provided further that the provisions of Section 7 other than those relating to the number of directors constituting the Board of Directors, and the provisions of this Section 16 may be amended or added to only by the affirmative vote, in person or by proxy, of the holders of two-thirds of the outstanding shares of capital stock entitled to vote at any meeting of the stockholders of the Company; and provided further, in the event of any such amendment or addition pursuant to vote by the stockholders of the Company, that such amendment or addition, or a summary thereof, shall have been set forth or referred to in the notice of such meeting. (As renumbered and amended October29, 1986.)7 EXHIBIT lO(k)(1)American Electric Power Company, Inc.Deferred Compensation and Stock Plan For Non-Employee Directors (As Amended December 10, 2003)Article 1 Purpose The purposes of this American Electric Power Company, Inc. Deferred Compensation and Stock Plan For Non-Employee Directors (the "Plan") are to enable the Company to attract and retain qualified persons to serve as Non-Employee Directors, to provide Non-Employee Directors with an opportunity to defer some or all of their Retainer as a means of saving for retirement or other purposes, to solidify the common interests of its Non-Employee Directors and shareholders by enhancing the equity interest of Non-Employee Directors in the Company, and to encourage the highest level of Non-Employee Director performance by providing such Non-Employee Directors with a proprietary interest in the Company's performance and progress by permitting Non-Employee Directors to receive all or a portion of their Retainer in Common Stock and/or to defer all or a portion of their Retainer in Stock Units.Article 2 Effective Date The Plan shall be effective as of January 1, 1997.Article 3 Definitions Whenever used in the Plan, the following terms shall have the respective meanings set forth below: 3.1 "Account" means, with respect to each Participant, the Participant's separate individual account established and maintained for the exclusive purpose of accounting for the Participant's deferred Retainer which is accrued in terms of Stock Units.3.2 "Beneficiary" means, with respect to each Participant, the recipient or recipients designated by the Participant who are, upon the Participant's death, entitled in accordance with the Plan's terms to receive the benefits to be paid with respect to the Participant. 3.3 "Board" means the Board of Directors of the Company.3.4 "Committee" means the Committee on Directors and Corporate Governance of the Board.3.5 "Common Stock" means the common stock, $6.50 par value, of the Company. 3.6 "Company" means American Electric Power Company, Inc., a New York corporation, and any successor thereto.3.7 "Director" means an individual who is a member of the Board.3.8 "Market Value" means the closing price of the Common Stock, as published in The Wall Street Journal report of the New York Stock Exchange -Composite Transactions on the date in question or, if the Common Stock shall not have been traded on such date or if the New York Stock Exchange is closed on such date, then the first day prior thereto on which the Common Stock was so traded.3.9 "Non-Employee Director" means any person who serves on the Board and who is not an officer of the Company or employee of its Subsidiaries. 3.10 "Participant" means any Non-Employee Director who has made an election to defer payment of all or a portion of such person's Retainer in Stock Units.3.11 "Retainer" means the designated annual cash retainer, currently paid quarterly, for Non-Employee Directors established from time to time by the Board as annual compensation for services rendered, exclusive of compensation for service as a member of any committee designated by the Board or in connection with any meeting of the Board or special assignment, and exclusive of reimbursements for expenses incurred in performance of service as a Director.3.12 "Stock Unit" means a measure of value, expressed as a share of Common Stock, credited to a Participant under this Plan. No certificates shall be issued with respect to such Stock Units, but the Company shall maintain a bookkeeping Account in the name of the Participant to which the Stock Units shall relate.3.13 "Subsidiary" means any corporation in which the Company owns directly or indirectly through its Subsidiaries, at least 50 percent of the total combined voting power of all classes of stock, or any other entity (including, but not limited to, partnerships and joint ventures) in which the Company owns at least 50 percent of the combined equity thereof.3.14 "Termination" means retirement from the Board or termination of services as a Director for any other reason.Article 4 Election to Defer Retainer in Stock Units 4.1 Election On or before December 31 of any year, for calendar years subsequent to 1997, a Non-Employee Director may elect, by filing with the Company an election, to defer receipt of all or a specified portion of the Director's Retainer in Stock Units until the Director's Termination or for a period that results in payment commencing not later than five years thereafter as elected by the 2 Participant. The election to defer payment beyond the Participant's Termination must be made at least one year prior to such Termination. Notwithstanding the foregoing, a Non-Employee Director may choose to participate in the Plan beginning with the Retainer payable on June 30, 1997, by filing an election to so participate on or before March 31, 1997. A Non-Employee Director elected to fill a vacancy on the Company's Board and Who was not a Director on the preceding December 31, or whose term of office did not begin until after that date, may file an election to defer, for all or a specified portion of the Director's Retainer, commencing not less than three months after the date of the election.4.2 Revocation of Election An effective election pursuant to Section 4.1 may not be revoked or modified (except as otherwise stated herein) with respect to the Retainer payable for a calendar year or portion of a calendar year for which such election is effective. An effective election may be terminated or modified for any subsequent calendar year by the filing of an election, on or before December 31 of the preceding calendar year for which such modification or termination is to be effective.

4.3 Deferred

Retainer Election When a Participant elects pursuant to Section 4.1 to defer all or a portion of the Participant's Retainer in Stock Units, the number of whole and fractional Stock Units, computed to three decimal places, to be credited to the Participant's Account, on the date the deferred Retainer would otherwise have been payable to the Participant, shall be equal to the dollar amount of the deferred Retainer which otherwise would have been payable to the Participant divided by the Market Value on such date.Article 5 Dividends and Adjustments

5.1 Reinvestment

of Dividends On each dividend payment date with respect to the Common Stock, the Account of a Participant, with Stock Units held pursuant to Article 4, shall be credited with an additional number of whole and fractional Stock Units, computed to three decimal places, equal to the product of the dividend per share then payable, multiplied by the number of Stock Units then credited to such Account, divided by the Market Value on the dividend payment date.5.2 Adjustments The number of Stock Units credited to a Participant's Account pursuant to Article 4 shall be appropriately adjusted for any change in the Common Stock by reason of any merger, reclassification, consolidation, recapitalization, stock dividend, stock split or any similar change affecting the Common Stock.3 Article 6 Payment of Stock Units 6.1 Manner of Payment Upon Termination In accordance with the Participant's election, filed with the Company, all Stock Units held in a Participant's Account shall be paid to the Participant either as (a) a lump sum distribution within 10 days after the Participant's deferred distribution date, or (b) up to 10 annual installments commencing within 10 days after the Participant's deferred distribution date. This election shall be made at the same time the Participant makes a deferral election as provided in Section 4.1.6.2 Manner of Payment Upon Death Notwithstanding the Participant's election, if a Participant dies while Stock Units are held in the Participant's Account, such Stock Units will be paid in a lump sum in cash within 90 days from the date of the Participant's death to the Beneficiary or the Participant's estate, as the case may be. Upon application by the Beneficiary or the legal representative for the Participant's estate, the lump sum payment may be deferred beyond 90 days for good cause if the Committee consents to such deferral.6.3 Determination Any cash payments of Stock Units shall be calculated on the basis of the average of the Market Value of the Common Stock for the last 20 trading days prior to the Participant's Termination, deferred distribution date, respective installment payment dates or the date of the Participant's death, as the case may be.Article 7 Beneficiary Designation Each Participant shall be entitled to designate a Beneficiary or Beneficiaries (which may be an entity other than a natural person) who, following the Participant's death, will be entitled to receive any payments to be made under Section 6.2. At any time, and from time to time, any designation may be changed or cancelled by the Participant without the consent of any Beneficiary. Any designation, change, or cancellation must be by written notice filed with the Company and shall not be effective until received by the Company. Payment shall be made in accordance with the last unrevoked written designation of Beneficiary that has been signed by the Participant and delivered by the Participant to the Company prior to the Participant's death.If the Participant designates more than one Beneficiary, any payments under Section 6.2 to the Beneficiaries shall be made in equal shares unless the Participant has designated otherwise, in which case the payments shall be made in the proportions designated by the Participant. If no Beneficiary has been named by the Participant or if all Beneficiaries predecease the Participant, payment shall be made to the Participant's estate.4 Article 8 Transferability Rcstrictions The Plan shall not in any manner be liable for, or subject to, the debts and liabilities of any Participant or Beneficiary. No payee may assign any payment due such party under the Plan.No benefits at any time payable under the Plan shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, attachment, garnishment, levy, execution, or other legal or equitable process, or encumbrance of any kind.Article 9 Funding Policy The Company's obligations under the Plan shall be totally unfunded so that the Company or any Subsidiary is under merely a contractual duty to make payments when due under the Plan. The promise to pay shall not be represented by notes and shall not be secured in any way.Article 10 Change in Control Notwithstanding any provision of this Plan to the contrary, if a "Change in Control" (as defined below) of the Company occurs, Stock Units held in a Participant's Account will be paid in a lump sum in cash, to the Participant, not later than 15 days after the date of the Change in Control. For this purpose, the balance in the Account shall be determined by the higher of (a) the average of the Market Value of the Common Stock for the last 20 trading days prior to such Change in Control or (b) if the Change in Control of the Company occurs as a result of a tender or exchange offer or consummation of a corporate transaction, then the highest price paid per share of Common Stock pursuant thereto. Any consideration other than cash forming a part or all of the consideration for the Common Stock to be paid pursuant to the applicable transaction shall be valued at the valuation price thereon determined by the Board.In addition, the Company shall reimburse a Participant for the legal fees and expenses incurred if the Participant is required to seek to obtain or enforce any right to distribution. In the event that it is determined that such Participant is properly entitled to a cash distribution hereunder, such Participant shall also be entitled to interest thereon at the prime rate of interest as published in The Wall Street Journal plus ttwo percent from the date such distribution should have been made to and including the date it is made. Notwithstanding any provisions of this Plan to the contrary, the provisions of this Article may not be amended by an amendment effected within three years following a Change in Control.A "Change in Control" of the Company shall be deemed to have occurred if (a) any "person" or"group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended ("Exchange Act")), other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, becomes the "beneficial owner" (as defined in Rule l3d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Company; (b) during any period of two consecutive years, 5 individuals wvho at the beginning of such period constitute the Board, together with any new Directors whose election or nomination for election was approved by a vote of at least two-thirds of the Directors then still in office who were either Directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board; or (c) the Company's shareholders approve a merger or consolidation of the Company with any other corporation, other than a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 75 percent of the total voting power represented by the voting securities of the Company or such surviving entity outstanding immediately after such merger or consolidation; or (d) the shareholders of the Company approve a plan of complete liquidation of the Company, or an agreement for the sale or disposition by the Company (in one transaction or a series of transactions) of all or substantially all of the Company's assets.Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of any event described in (a) or (c) above, if Directors who were a majority of the members of the Board prior to such event and who continue to serve as Directors after such event determine that the event shall not constitute a Change in Control.Article 11 Administration The Plan shall be administered by the Committee. The Committee shall have authority to interpret the Plan, and to prescribe, amend and rescind rules and regulations relating to the administration of the Plan, and all such interpretations, rules and regulations shall be conclusive and binding on all Participants. The Committee may employ agents, attorneys, accountants, or other persons (who also may be employees of a Subsidiary) and allocate or delegate to them powers, rights and duties, all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan.Article 12 Amendment and Termination The Company, by resolution duly adopted by the Board, shall have the right, authority and power to alter, amend, modify, revoke, or terminate the Plan; except as provided in Article 10; and provided further, that no amendment or termination of the Plan shall adversely affect the rights of any Participant with respect to any Stock Units held in such Participant's Account, unless the Participant shall consent thereto in writing.6 Article 13 Miscellaneous 13.1 No Right to Continue as a Director Nothing in this Plan shall be construed as conferring upon a Participant any right to continue as a member of the Board.13.2 No Interest as a Shareholder Stock Units do not give a Participant any rights whatsoever with respect to shares of Common Stock.13.3 No Right to Corporate Assets Nothing in this Plan shall be construed as giving the Participant, the Participant's designated Beneficiaries or any other person any equity or interest of any kind in the assets of the Company or any Subsidiary or creating a trust of any kind or a fiduciary relationship of any kind between the Company or any Subsidiary and any person. As to any claim for payments due under the provisions of the Plan, a Participant, Beneficiary and any other persons having a claim for payments shall be unsecured creditors of the Company or any Subsidiary. 13.4 Payment to Legal Representative for Participant In the event the Committee shall find that a Participant is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant be paid to the Participant's duly appointed legal representative, and any such payment so made shall be a complete discharge of the liabilities of the Plan.13.5 No Limit on Further Corporate Action Nothing contained in the Plan shall be construed so as to prevent the Company or any Subsidiary from taking any corporate action which is deemed by the Company or any Subsidiary to be appropriate or in its best interest.13.6 Governing Law The Plan shall be construed and administered according to the laws of the State of New York to the extent that those laws are not preempted by the laws of the United States of America.13.7 Headings The headings of articles, sections, subsections, paragraphs or other parts of the Plan are for convenience of reference only and do not define, limit, construe, or otherwise affect its contents.7 EXHIBIT 10(k)(2)American Electric Power Company, Inc.Stock Unit Accumulation Plan For Non-Employee Directors (As Amended December 10, 2003)Article I Purpose The purposes of this American Electric Power Company, Inc. Stock Unit Accumulation Plan For Non-Employee Directors (the "Plan") are to enable the Company to attract and retain qualified persons to serve as Non-Employee Directors, to solidify the common interests of its Non-Employee Directors and shareholders by enhancing the equity interest of Non-Employee Directors in the Company, and to encourage the highest level of Non-Employee Director performance by providing such Non-Employee Directors with a proprietary interest in the Company's performance and progress by paying a portion of the compensation of the Non-Employee Directors in deferred Stock Units.Article 2 Effective Date The Plan shall be effective as of January 1, 1997.Article 3 Definitions Whenever used in the Plan, the following terms shall have the respective meanings set forth below: 3.1 "Account" means, with respect to each Participant, the Participant's separate individual account established and maintained for the exclusive purpose of accounting for the Participant's award of Stock Units.3.2 "Beneficiary" means, with respect to each Participant, the recipient or recipients designated by the Participant who are, upon the Participant's death, entitled in accordance with the Plan's terms to receive the benefits to be paid with respect to the Participant. 3.3 "Board" means the Board of Directors of the Company.3.4 "Cash Retainer" means the designated annual cash retainer (currently $60,000), paid quarterly, for Non-Employee Directors established from time to time by the Board as annual compensation for services rendered, exclusive of compensation for service as a member of any committee designated by the Board or in connection with any meeting of the Board or special assignment, and exclusive of reimbursements for expenses incurred in performance of service as a Director. 3.5 "Committee" means the Committee on Directors and Corporate Governance of the Board.3.6 "Common Stock" means the common stock, $6.50 par value, of the Company.3.7 "Company" means American Electric Power Company, Inc., a New York corporation, and any successor thereto.3.8 "Director" means an individual who is a member of the Board.3.9 "Market Value" means the closing price of the Common Stock, as published in The WJall Street Journal report of the New York Stock Exchange -Composite Transactions on the date in question or, if the Common Stock shall not have been traded on such date or if the New York Stock Exchange is closed on such date, then the first day prior thereto on which the Common Stock was so traded.3.10 "Non-Employee Director" means any person who serves on the Board and who is not an officer of the Company or employee of its Subsidiaries. 3.11 "Participant" means any Non-Employee Director who has received an award of Stock Units.3.12 "Retainer" means Cash Retainer and Stock Retainer.3.13 "Stock Retainer" means the designated annual stock retainer (currently $60,000), payable quarterly, for Non-Employee Directors established from time to time by the Board as annual stock compensation for services rendered.3.14 "Stock Unit" means a measure of value, expressed as a share of Common Stock, credited to a Participant under this Plan. No certificates shall be issued with respect to such Stock Units, but the Company shall maintain a bookkeeping Account in the name of the Participant to which the Stock Units shall relate.3.15 "Subsidiary" means any corporation in which the Company owns directly or indirectly through its Subsidiaries, at least 50 percent of the total combined voting power of all classes of stock, or any other entity (including, but not limited to, partnerships and joint ventures) in which the Company owns at least 50 percent of the combined equity thereof.3.16 "Termination" means retirement from the Board or termination of service as a Director for any other reason.2 Article 4 Stock Unit Awards 4.1 Annual Awards The Stock Retainer shall be payable quarterly and shall equal the dollar amount of the Stock Retainer payable to the Participant divided by the Market Value on such date. The number of whole and fractional Stock Units vill be computed to three decimal places.4.2 Retirement Program Termination Awards On and as of December 31, 1996, each Non-Employee Director serving as such on such date who makes or has made an irrevocable election by January 31, 1997 to waive participation in, and any and all benefits under, the Company's Retirement Plan for Directors, shall have credited to the Account of such Participant, as of January 1, 1997, the number of vested and nonforfeitable Stock Units as follows: R. M. Duncan 3,000; R. W. Fri 600; A. G. Hansen 3,000;L. A. Hudson, Jr. 3,000; A. E. Peyton 3,000; D. G. Smith 900; L. G. Stuntz 1,200; M.Tanenbaum 2,400; and A. H. Zwinger 3,000.Article 5 Dividends and Adjustments

5.1 Reinvestment

of Dividends On each dividend payment date with respect to the Common Stock, the Account of a Participant, with Stock Units held pursuant to Article 4, shall be credited with an additional number of whole and fractional Stock Units, computed to three decimal places, equal to the product of the dividend per share then payable, multiplied by the number of Stock Units then credited to such Account, divided by the Market Value on the dividend payment date.5.2 Adjustments The number of Stock Units credited to a Participant's Account pursuant to Article 4 shall be appropriately adjusted for any change in the Common Stock by reason of any merger, reclassification, consolidation, recapitalization, stock dividend, stock split or any similar change affecting the Common Stock.3 Article 6 Payment of Stock Units 6.1 Manner of Payment Upon Termination Stock Units held in a Participant's Account shall be paid to the Participant in a lump sum in cash within 10 days after the Participant's Termination unless the Participant has filed an election with the Company to defer such payment as provided in the following sentence. The Participant may elect (a) to defer the lump sum payment for one or more years up to a maximum of five years following Termination or (b) to receive payment of the Stock Units in up to 10 annual installments commencing within 1O days after Termination or the deferred payment date elected by the Participant pursuant to part (a) of this sentence. The election to defer payment beyond the Participant's Termination must be made at least one year prior to such Termination.

6.2 Manner

of Payment Upon Death Notwithstanding the Participant's election, if a Participant dies while Stock Units are held in the Participant's Account, such Stock Units, whether vested or unvested and forfeitable, will be paid in a lump sum in cash within 90 days from the date of the Participant's death to the Beneficiary or the Participant's estate, as the case may be. Upon application of the Beneficiary or the legal representative of the Participant's estate, the lump sum payment may be deferred beyond 90 days for good cause if the Committee consents to such deferral.63 Determination Any cash payments of Stock Units shall be calculated on the basis of the average of the Market Value of the Common Stock for the last 20 trading days prior to the Participant's Termination, deferred distribution date, respective installment payment dates or the date of the Participant's death, as the case may be.Article 7 Beneficiary Designation Each Participant shall be entitled to designate a Beneficiary or Beneficiaries (which may be an entity other than a natural person) who, following the Participant's death, will be entitled to receive any payments to be made under Section 6.2. At any time, and from time to time, any designation may be changed or cancelled by the Participant without the consent of any Beneficiary. Any designation, change, or cancellation must be by written notice filed with the Company and shall not be effective until received by the Company. Payment shall be made in accordance with the last unrevoked written designation of Beneficiary that has been signed by the Participant and delivered by the Participant to the Company prior to the Participant's death.If the Participant designates more than one Beneficiary, any payments under Section 6.2 to the Beneficiaries shall be made in equal shares unless the Participant has designated otherwise, in which case the payments shall be made in the proportions designated by the Participant. If no 4 Beneficiary has been named by the Participant or if all Beneficiaries predecease the Participant, payment shall be made to the Participant's estate.Article 8 Transferability Restrictions The Plan shall not in any manner be liable for, or subject to, the debts and liabilities of any Participant or Beneficiary. No payee may assign any payment due such party under the Plan.No benefits at any time payable under the Plan shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, attachment, garnishment, levy, execution, or other legal or equitable process, or encumbrance of any kind.Article 9 Funding Policy The Company's obligations under the Plan shall be totally unfunded so that the Company or any Subsidiary is under merely a contractual duty to make payments when due under the Plan. The promise to pay shall not be represented by notes and shall not be secured in any way.Article 10 Change in Control Notwithstanding any provision of this Plan to the contrary, if a "Change in Control" (as defined below) of the Company occurs, Stock Units held in a Participant's Account, whether vested or unvested and forfeitable, will be paid in a lump sum in cash to the Participant not later than 15 days after the date of the Change in Control. For this purpose, the balance in the Account shall be determined by the higher of (a) the average of the Market Value of the Common Stock for the last 20 trading days prior to such Change in Control or (b) if the Change in Control of the Company occurs as a result of a tender or exchange offer or consummation of a corporate transaction, then the highest price paid per share of Common Stock pursuant thereto. Any consideration other than cash forming a part or all of the consideration for the Common Stock to be paid pursuant to the applicable transaction shall be valued at the valuation price thereon determined by the Board.In addition, the Company shall reimburse a Participant for the legal fees and expenses incurred if the Participant is required to seek to obtain or enforce any right to distribution. In the event that it is determined that such Participant is properly entitled to a cash distribution hereunder, such Participant shall also be entitled to interest thereon at the prime rate of interest as published in The Mall Street Journal plus two percent from the date such distribution should have been made to and including the date it is made. Notwithstanding any provisions of this Plan to the contrary, the provisions of this Article may not be amended by an amendment effected within three years following a Change in Control.5 A "Change in Control" of the Company shall be deemed to have occurred if (a) any "person" or"group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended ("Exchange Act")), other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Company; (b) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new Directors whose election or nomination for election was approved by a vote of at least two-thirds of the Directors then still in office who were either Directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board; or (c) the Company's shareholders approve a merger or consolidation of the Company with any other corporation, other than a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 75 percent of the total voting power represented by the voting securities of the Company or such surviving entity outstanding immediately after such merger or consolidation; or (d) the shareholders of the Company approve a plan of complete liquidation of the Company, or an agreement for the sale or disposition by the Company (in one transaction or a series of transactions) of all or substantially all of the Company's assets.Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of any event described in (a) or (c) above, if Directors

vho were a majority of the members of the Board prior to such event and who continue to serve as Directors after such event determine that the event shall not constitute a Change in Control.Article 11 Administration The Plan shall be administered by the Committee.

The Committee shall have authority to interpret the Plan, and to prescribe, amend and rescind rules and regulations relating to the administration of the Plan, and all such interpretations, rules and regulations shall be conclusive and binding on all Participants. The Committee may employ agents, attorneys, accountants, or other persons (who also may be employees of a Subsidiary) and allocate or delegate to them powers, rights, and duties, all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan.6 Article 12 Amendment and Termination The Company, by resolution duly adopted by the Board, shall have the right, authority and power to alter, amend, modify, revoke, or terminate the Plan; except as provided in Article 10; and provided further, that no amendment or termination of the Plan shall adversely affect the rights of any Participant with respect to any Stock Units held in such Participant's Account, unless the Participant shall consent thereto in writing.Article 13 Miscellaneous 13.1 No Right to Continue as a Director Nothing in this Plan shall be construed as conferring upon a Participant any right to continue as a member of the Board.13.2 No Interest as a Shareholder Stock Units do not give a Participant any rights whatsoever with respect to shares of Common Stock.13.3 No Right to Corporate Assets Nothing in this Plan shall be construed as giving the Participant, the Participant's designated Beneficiaries or any other person any equity or interest of any kind in the assets of the Company or any Subsidiary or creating a trust of any kind or a fiduciary relationship of any kind between the Company or any Subsidiary and any person. As to any claim for payments due under the provisions of the Plan, a Participant, Beneficiary and any other persons having a claim for payments shall be unsecured creditors of the Company or any Subsidiary. 13.4 Payment to Legal Representative for Participant In the event the Committee shall find that a Participant is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant be paid to the Participant's duly appointed legal representative, and any such payment so made shall be a complete discharge of the liabilities of the Plan.13.5 No Limit on Further Corporate Action Nothing contained in the Plan shall be construed so as to prevent the Company or any Subsidiary from taking any corporate action which is deemed by the Company or any Subsidiary to be appropriate or in its best interest.7 13.6 Governing Lav The Plan shall be construed and administered according to the laws of the State of New York to the extent that those laws are not preempted by the laws of the United States of America.13.7 Headings The headings of articles, sections, subsections, paragraphs or other parts of the Plan are for convenience of reference only and do not define, limit, construe, or otherwise affect its contents.8 EXHIBIT 10(1X2)AMERICAN ELECTRIC POWER SYSTEM SUPPLEMENTAL RETIREMENT SAVINGS PLAN AMENDED AND RESTATED AS OF JANUARY 1, 2003 ARTICLE I Purposes and Effective Date 1.1 The American Electric Power System Supplemental Retirement Savings Plan is established to provide to eligible employees a tax-deferred savings opportunity otherwise not available to them under the terms of the American Electric Power System Retirement Savings Plan because of contribution restrictions imposed by the Internal Revenue Code.1.2 The original effective date of the American Electric PoNver System Supplemental Retirement Savings Plan is January 1, 1994 and the effective date of this Amended and Restated American Electric Power System Supplemental Retirement Savings Plan is January 1, 2003, except as otherwise specified herein.ARTICLE II DEFINITIONS 2.1 "Account" means the separate memo account established and maintained by the Company or the recordkeeper employed by the Company to record Contributions allocated to a Participant's Account and to record any related Investment Income on the Fund or Funds selected by the Participant. 2.2 "Applicable Federal Rate" means 120% of the applicable federal long-term rate, with monthly compounding (as prescribed under Section 1274(d) of the Code), published for the December immediately prior to the Plan Year.2.3 "Code" means the Internal Revenue Code of 1986, as amended from time to time.2.4 "Committee" means the Employee Benefits Trust Committee as established by the Board of Directors of American Electric Power Service Corporation. 2.5 "Compensation" means the sum of a Participant's regular base salary or wage including any salary or wage reductions made pursuant to sections 125 and 402(e)(3) of the Code and contributions to this Plan and incentive compensation paid pursuant to the terms of annual incentive compensation plans up to a maximum of one million dollars ($1,000,000), provided that Compensation shall not include non-annual bonuses (such as but not limited to project bonuses and sign-on bonuses), severance pay, relocation payments, or any other form of additional compensation that is not considered to be part of base salary, base wage or annual incentive compensation. For this purpose, safety focus payouts shall be considered paid pursuant to the terms of an annual incentive plan, although such payouts may be determined and paid on a quarterly basis.2.6 "Company" means the American Electric Power Service Corporation and its subsidiaries and affiliates. 2.7 "Company Contributions" means the matching contributions made by the Company pursuant to section 3.2.2.8 "Contributions" means, as the context may require, Participant Contributions and Company Contributions. 2.9 "Corporation" means the American Electric Power Company, Inc., a New York corporation. 2.10 "Eligible Employee" means, for periods beginning on or after June 1, 2001, an employee of the Company who, as of the first day of November that immediately precedes the applicable Plan Year, either (a) has base salary or base wage, including salary or wage reductions made pursuant to section 125 and 402(e)(3) of the Code, equals or exceeds $100,000, or (b) is employed at a salary grade 26 or higher. To determine an Eligible Employee for periods prior to June 1, 2001, refer to provisions of the Plan as in effect prior to June 1, 2001.2.11 "ERISA" means the Employee Retirement Income Security Act of 1974, as amended from time to time.2.12 "Fund" means the investment options made available to participants in the Savings Plan, as revised from time to time, and the Interest Bearing Account.2.13 "Investment Income" means with respect to Participant Contributions and Company Contributions the earnings, gains and losses that would be attributable to the investment of such Contributions in a Fund or Funds.2.14 "Interest Bearing Account" means an investment option to be made available to Participants in this Plan in which the Contributions attributed to this option are credited with interest at the Applicable Federal Rate.2.15 "Pay Reduction Agreement" means an agreement between the Company and the Participant in which the Participant irrevocably elects to reduce his or her Compensation for the Plan Year and the Company agrees to treat the amount of the Compensation reduction as a Participant Contribution to this Plan.2.16 "Participant Contributions" means contributions made by the Participant pursuant to an executed Pay Reduction Agreement subject to the Participant Contribution limits contained in section 3.1.2.17 "Plan" means this American Electric Power System Supplemental Retirement Savings Plan, as in effect from time to time.2 2.18 "Plan Year" means the twelve-month period commencing each January 1 and ending December 3 1.2.19 "Savings Plan" means the American Electric Power System Retirement Savings Plan, a plan intended to be qualified under section 401 (a) of the Code, as in effect from time to time.ARTICLE III CONTRIBUTIONS 3.1 A Participant may elect to make Participant Contributions by timely submitting an executed Pay Reduction Agreement and such other forms as may be required by the Committee. All Participant Contributions (i) shall be made by payroll deductions from Compensation payable to the Participant during the Plan Year, and (ii) shall commence with the first pay date that falls within the Plan Year to ,which the Pay Reduction Agreement applies. Participant Contributions are to be made in multiples of one (1) whole percentage of Compensation, not to exceed 20 percent of Compensation for any pay date.The maximum Participant Contribution for any pay date shall not exceed the difference between (a)twenty percent (20%) of the Participant's Compensation for the pay date, and (b) the aggregate amount of the Participant's Before-Tax and After-Tax contributions to the Savings Plan for the same pay date.3.2 Subject to the limitation contained in section 3.3, the Company shall credit to the Plan on behalf of each Participant an amount equal to 75% of the amount contributed to the Plan by the Participant, not in excess of 6% of a Participant's Compensation as of each pay date.3.3 The amount of Company Contributions credited to the Plan on behalf of a Participant in combination with the contributions made by the Company to the Savings Plan on behalf of the Participant as of each pay date during a Plan Year, shall, in the aggregate be equal to the lesser of (a)75% of the Participant Contributions made by the Participant to this Plan and the Savings Plan as of that pay date, or (b) 4.5% of the Participant's Compensation paid as of that pay date. If the aggregate contributions exceed the lesser limitation described in the preceding sentence, the Company Contributions credited to the Participant's Account under this Plan shall be reduced until the aggregate Company Contributions made under both the Savings Plan and this Plan do not exceed the limitation. 3.4 An employee who is an Eligible Employee as of the beginning of the enrollment period for a particular Plan Year may participate in the Plan for that Plan Year, provided that he timely submits a Pay Reduction Agreement for that Plan Year. Any Eligible Employee who timely submits a Pay Reduction Agreement for a Plan Year shall become a Participant on the first day of that Plan Year.3.5 Notwithstanding the provisions of Section 3.4, employees who first became Eligible Employees as of June 1, 2001 shall have a special enrollment period (referred to herein as a "2001 Enrollee'). Any 2001 Enrollee who timely submits a Pay Reduction Agreement during the special enrollment period shall eligible to participate in the Plan for the 2001 Plan Year effective for Compensation paid on or after June 29, 2001.3 ARTICLE IV INVESTMENT OF CONTRIBUTIONS

4.1 Participant

Contributions and Company Contributions shall be credited with earnings as if invested in the Funds selected by the Participant. To the extent the Participant fails to select Funds for the investment of Contributions under the Plan, the Participant shall be deemed to have selected the Interest Bearing Account. The Participant may change the selected Funds by providing notification in accordance with the Plan's procedures. Any change in the Funds selected by the Participant shall be implemented in accordance with the Plan's procedures. 4.2 A Participant may elect to transfer all or a portion of the amounts credited to his Account from any Fund or Funds to any other Fund or Funds by providing notification in accordance with the Plan's procedures. Such transfers between Funds may be made in any whole percentage or dollar amounts and shall be implemented in accordance with the Plan's procedures. 4.3 The amount credited to each Participant's Account shall be determined daily based upon the fair market value of the Fund or Funds to which that Account is allocated. The fair market value calculation for a Participant's Account shall be made after all Contributions, vithdrawals, distributions, Investment Income and transfers for the day are recorded. A Participant's Account, as adjusted from time to time, shall continue to be credited with Investment Income until the balance of the Account is zero and no additional Contributions are anticipated from such Participant by the Committee. 4.4 The Plan is an unfunded non-qualified deferred compensation plan and therefore the Contributions credited to a Participant's Account and the investment of those Contributions in the Fund or Funds selected by the Participant are memo accounts that represent general, unsecured liabilities of the Company payable exclusively out of the general assets of the Company.ARTICLE V ELECTION, DISTRIBUTIONS AND BENEFICIARIES 5.1 In order for an election to make Participant Contributions to be effective for any given Plan Year, the Participant must submit an executed irrevocable Pay Reduction Agreement during the applicable enrollment period preceding the period as to which the election is to take effect. Except to the extent specifically provided otherwise in Section 3.5, each Pay Reduction Agreement shall apply to (and only to) the Plan Year next following the applicable annual enrollment period and shall remain in force only as to that Plan Year. No election shall be effective to defer any Compensation that would otherwise be paid to the Participant before the period for which the Pay Reduction Agreement is effective. The Pay Reduction Agreement shall be in such form as may reasonably be required by the Committee and shall be executed at the time and in the manner prescribed by the Committee. 4 5.2 (a) No earlier than a Participant's termination of employment for any reason other than death, all amounts that are credited to the Participant's Account shall be distributed to the Participant in one of the following optional forms as selected by the Participant: (1) a single lump-sum payment, or (2) in approximately equal annual or semi-annual installment payments over not less than two nor more than ten years.(b) Payment in the form of distribution selected by the Participant pursuant to section 5.2(a) shall commence within 60 days after the date elected by the Participant on an effective distribution election form. Such commencement date shall be either (1) the date of the Participant's termination of employment or (2) the first, second, third, fourth or fifth anniversary of the Participant's termination of employment, as selected by the Participant.(c) Each Participant shall select the form of distribution [as set forth in section 5.2(a)]and benefit commencement date [as set forth in section 5.2(b)] when the Participant first elects to participate in the Plan. The Participant may amend his or her distribution election at any time prior to the ninetieth (90th) day preceding the Participant's termination of employment by submitting a distribution election form in accordance with the Plan's procedures; provided that a modification to the Participant's distribution election submitted after such 90o" day will be effective if submitted no later than the first to occur of (i) December 13, 2002, or (ii) the beginning of the one year period preceding the date when the Participant's distributions would commence if the modification would not be given effect. If the Participant has not submitted an effective distribution election at the time of his termination of employment, his distribution shall be in the form of a single lump sum payment made within 60 days after the Participant's termination of employment. 5.3 Each Participant may designate a beneficiary or beneficiaries who shall receive the balance of the Participant's Account if the Participant dies prior to the complete distribution of the Participant's Account. Any designation, or change or rescission of a beneficiary designation shall be made by the Participant's completion, signature and submission to the Committee of the appropriate beneficiary form prescribed by the Committee. A beneficiary form shall take effect as of the date the form is signed provided that the Committee receives it before taking any action or making any payment to another beneficiary named in accordance with this Plan and any procedures implemented by the Committee. If any payment is made or other action is taken before a beneficiary form is received by the Committee, any changes made on a form received thereafter will not be given any effect. If a Participant fails to designate a beneficiary, or if all beneficiaries named by the Participant do not survive the Participant, the Participant's Account will be paid to the Participant's estate. Unless clearly specified otherwise in an applicable court order presented to the Committee prior to the Participant's death, the designation of a Participant's spouse as a beneficiary shall be considered automatically revoked as to that spouse upon the legal termination of the Participant's marriage to that spouse.5.4 Distribution to a Participant's beneficiary shall be in the form of a single lump-sum payment within 60 days after the Committee makes a final determination as to the beneficiary or beneficiaries entitled to receive such distribution. 5 ARTICLE VI TAXES AND TAX TREATMENT 6.1 Each Participant agrees that as a condition of participation in the Plan, the Company may withhold from any distribution hereunder all amounts detennined by the Company as required by law or otherwise as determined by the Company to be then due and payable by the Participant or his beneficiary to the Company.6.2 The Company intends the following with respect to this Plan: (1) Section 451(a) of the Code would apply to the Participant's recognition of gross income as a result of participation herein; (2)the Participants will not recognize gross income as a result of participation in the Plan unless and until and then only to the extent that distributions are received; (3) the Company will not receive a deduction for amount credited to any Account unless and until and then only to the extent that amounts are actually distributed; and (4) the provisions of Parts 2, 3, and 4 of Subtitle B of Title I of ERISA shall not be applicable. However, no Eligible Employee, Participant, beneficiary or any other person shall have any recourse against the Corporation, the Company, the Committee or any of their affiliates, employees, agents, successors, assigns or other representatives if any of those conditions are determined not to be satisfied. ARTICLE VII ADMINISTRATION 7.1 The Committee shall have full discretionary power and authority (i) to administer and interpret the terms and conditions of the Plan; (ii) to establish reasonable procedures with which Participants must comply to exercise any right or privilege established hereunder; and (iii) to be permitted to delegate its responsibilities or duties hereunder to any person or entity. The rights and duties of the Participants and all other persons and entities claiming an interest under the Plan shall be subject to, and bound by, actions taken by or in connection with the exercise of the powers and authority granted under this Article.7.2 The Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan.7.3 The Company shall maintain, or cause to be maintained, records showing the individual balances of each Participant's Account. Statements setting forth the value of the amount credited to the Participant's Account as of a particular date shall be made available to each Participant no less often than quarterly. 6 ARTICLE VIII AMENDMENT OR TERMINATION 8.1 The Company intends to continue the Plan indefinitely but reserves the right, in its sole discretion, to modify the Plan from time to time, or to terminate the Plan entirely or to direct the permanent discontinuance or temporary suspension of Contributions under the Plan; provided that no such modification, termination, discontinuance or suspension shall reduce the benefits accrued for the benefit of any Participant or beneficiary under the Plan as of the date of such modification, termination, discontinuance or suspension. ARTICLE IX MISCELLANEOUS

9.1 Nothing

in the Plan shall (i) interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time; nor (ii) confer upon a Participant any right to continue in the employ of the Company.9.2 In the event the Committee, in its sole discretion, shall find that a Participant or beneficiary is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant or the beneficiary be paid to the duly appointed personal representative of the Participant or beneficiary, and any such payment so made shall be a complete discharge of the liabilities of the Plan and the Company with respect to such Participant or beneficiary. 9.3 The Plan shall be construed and administered according to the applicable provisions of ERISA and the laws of the State of Ohio.ARTICLE X CLAIMS PROCEDURE Section 10.1 The following procedures shall apply with respect to claims for benefits under the Plan.(a) Any Participant or beneficiary who believes he or she is entitled to receive a distribution under the Plan which he or she did not receive or that amounts credited to his or her Account are inaccurate, may file a written claim signed by the Participant, beneficiary or authorized representative with the Company's Director -Compensation and Executive Benefits, specifying the basis for the claim.The Director -Compensation and Executive Benefits shall provide a claimant with written or electronic notification of its determination on the claim within ninety days after such claim was filed; provided, however, if the Director -Compensation and Executive Benefits determines special circumstances require an extension of time for processing the claim, the claimant shall receive within the initial ninety-7 day period a written notice of the extension for a period of up to ninety days from the end of the initial ninety day period. The extension notice shall indicate the special circumstances requiring the extension and the date by which the Plan expects to render the benefit determination.(b) If the Director -Compensation and Executive Benefits renders an adverse benefit determination under Section 10.1 (a), the notification to the claimant shall set forth, in a manner calculated to be understood by the claimant: (1) the specific reasons for the denial of the claim;(2) specific reference to the provisions of the Plan upon which the denial of the claim was based;(3) a description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary, and (4) an explanation of the review procedure specified in Section 10.2, and the time limits applicable to such procedures, including a statement of the claimant's right to bring a civil action under section 502(a) of the Employee Retirement Income Security Act of 1974, as amended, following an adverse benefit determination on review.Section 10.2 The following procedures shall apply with respect to the review on appeal of an adverse determination on a claim for benefits under the Plan.(a) Within sixty days after the receipt by the claimant of an adverse benefit determination, the claimant may appeal such denial by filing with the Committee a written request for a review of the claim. If such an appeal is filed within the sixty day period, the Committee, or a duly appointed representative of the Committee, shall conduct a full and fair review of such claim that takes into account all comments, documents, records and other information submitted by the claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The claimant shall be entitled to submit written comments, documents, records and other information relating to the claim for benefits and shall be provided, upon request and free of charge, reasonable access to, and copies of all documents, records and other information relevant to the claimant's claim for benefits. If the claimant requests a hearing on the claim and the Committee concludes such a hearing is advisable and schedules such a hearing, the claimant shall have the opportunity to present the claimant's case in person or by an authorized representative at such hearing.(b) The claimant shall be notified of the Committee's benefit determination on review within sixty days after receipt of the claimant's request for review, unless the Committee determines that special circumstances require an extension of time for processing the review. If the Committee detennines that such an extension is required, written notice of the extension shall be furnished to the claimant within the initial sixty-day period. Any such extension shall not exceed a period of sixty days from the end of the initial period. The extension notice shall indicate the special circumstances requiring the extension and the date by which the Plan expects to render the benefit determination. 8 (c) The Committee shall provide a claimant with written or electronic notification of the Plan's benefit determination on review. The determination of the Committee shall be final and binding on all interested parties. Any adverse benefit determination on review shall set forth, in a manner calculated to be understood by the claimant: (1) the specific reason(s) for the adverse determination; (2) reference to the specific provisions of the Plan on which the determination was based;(3) a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claimant's claim for benefits; and (4) a statement of the claimant's right to bring an action under Section 502(a) of ERISA.American Electric Power Service Corporation has caused this Amended and Restated American Electric Power System Supplemental Retirement Savings Plan to be signed as of this 17th day of January, 2003.AMERICAN ELECTRIC POWER SERVICE CORPORATION By: Is! Melinda S. Ackerman Melinda S. Ackerman, Senior Vice President, Human Resources 9 EXHIBIT 10(m)(1)EMPLOYMENT AGREEMENT This AGREEMENT is made as of this December 15, 2003, by and among AMERICAN ELECTRIC POWER COMPANY, INC., a New York corporation ("AEP'), and AMERICAN ELECTRIC POWER SERVICE CORPORATION, a New York corporation and a wvholly-owned subsidiary of AEP ("Service Corporation") (AEP and Service Corporation hereinafter referred to collectively as the "Companies"), and Michael G. Morris ("Executive"). RECITALS In order to induce Executive to serve as the President and Chief Executive Officer of AEP and Service Corporation, as well as Chief Executive Officer of other major subsidiaries of AEP, the Companies desire to provide Executive with compensation and other benefits on the terms and conditions set forth in this Agreement. Executive is willing to accept such employment and perform services for the Companies, on the terms and conditions hereinafter set forth.It is therefore hereby agreed by and between the parties as follows: I. Employment.

1.1 Positions

and Reporting .Subject to the terms and conditions of this Agreement, effective as of the Commencement Date (as defined in Section 2 below), the Companies agree to engage Executive during the term hereof as President and Chief Executive Officer of each of AEP and Service Corporation, as well as such major subsidiaries of AEP as the board of directors of AEP (the "Board') shall designate. In such capacities, Executive shall have the customary powers, responsibilities and authorities of such offices for corporations of the size, type and nature of the Companies (and such major subsidiaries of AEP, as applicable), as they exist from time to time. During the term of this Agreement, Executive, in carrying out his duties under this Agreement, shall report directly to the Board.1.2 Boards of Directors. AEP shall, during the term of this Agreement, cause the election and retention of Executive as a member of the board of directors of each subsidiary of AEP as selected by the Board. Executive agrees to serve, if elected, as Chairman of the Board (and on any committees of the Board), in addition to serving on the board of directors (and any committees thereof) of each subsidiary of AEP.1.3 Executive Agreements and Representations.(a) Subject to the terms and conditions of this Agreement, effective as of the Commencement Date, Executive hereby agrees to be employed as President and Chief Executive Officer of each of AEP and Service Corporation and agrees to devote his full working time and efforts, to the best of his ability, experience and talent, to the performance of services, duties and responsibilities in connection therewith. Executive shall perform such duties and exercise such powers commensurate with his positions and shall accept such other positions or titles of other corporations affiliated with the Companies (including, without limitation, Chief Executive Officer of other subsidiaries of AEP), in each instance as the Board shall from time to time delegate to him on such terms and conditions and subject to such restrictions as may reasonably from time to time be imposed.(b) Executive hereby represents that the execution and delivery of this Agreement by Executive and the performance by Executive of Executive's duties hereunder do not constitute a breach of, or otherwise contravene, the terms of any employment agreement or other noncompetition agreement or policy (including any agreement with Executive's prior employment, Northeast Utilities ("Prior Employer")) to which Executive is a party or otherwise bound. Executive also hereby represents that in no event shall any of the Companies or their subsidiaries become subject to any liability that may arise in connection with that certain litigation between Con Edison and the Prior Employer that is ongoing as of the date hereof, and further agrees to indemnify and hold harmless the Companies and their subsidiaries from any liability that they may incur with respect thereto.1.4 Other Boards and Activities. Notwithstanding anything set forth in this Agreement, during the term of this Agreement, subject to the prior express written consent of the Directors and Corporate Governance Committee of the Board, Executive shall be permitted to serve on the boards of directors (or advisory committees) of a reasonable number of other corporations or entities and of a reasonable number of trade associations and/or charitable organizations. During the term of this Agreement, Executive shall also otherwise be permitted to engage in a reasonable number of charitable activities and community affairs and manage his personal investments and affairs, provided that such activities set forth in this Section 1.4 do not conflict or materially interfere with the effective discharge of his duties and responsibilities under this Agreement.

2. Term of Employment.

The term of this Agreement shall begin on January 1, 2004 (the "Comntencement Date"), and shall extend until the third anniversary of the Commencement Date, with automatic one-year renewals commencing on such third anniversary and on each anniversary thereafter, unless and until either party hereto notifies the other at least six (6) months before the scheduled renewal date that the term of this Agreement is not to be renewed. Notwithstanding the foregoing, the term of this Agreement (and Executive's employment hereunder) may be earlier terminated by either party in accordance with the provisions of Section 4 of this Agreement.

3. Compensation:

Benefits.3.1 Base Salary. During the term of this Agreement, Service Corporation shall pay Executive a base salary ("Base Salary") at the rate of $1,115,000 per annum, payable in accordance with the ordinary payroll practices of the Companies. After December 31, 2004, Executive's rate of Base Salary shall be reviewed annually by the Human Resources Committee of the Board and, if increased, such increased amount shall constitute Executive's Base Salary.3.2 Compensation Plans and Programs.(a) Annual Bonus. During the term of this Agreement, Executive shall be eligible to earn an annual bonus (the "Annual Bonus") in respect of each calendar year of AEP occurring during the term of employment pursuant to the Senior Officer Annual Incentive Compensation Plan or such other annual incentive program maintained by the Companies from time to time in which other senior executives of the Companies participate, on terms comparable to those applicable to such other senior executives (the "Annual Bonus Plan"). During the term of the Agreement, under the Annual Bonus Plan, the amount of Executive's Annual Bonus shall 2 be based upon a percentage of Executive's Base Salary (or such other metric as the Board may establish pursuant to the Annual Bonus Plan); provided that the target Annual Bonus percentage under the Annual Bonus Plan for each calendar year occurring during the term of the Agreement shall be equal to at least one hundred percent (100%) of the amount of Base Salary Executive actually earned in the calendar year in respect of which the Annual Bonus, if any, is payable (the"Target Bonus"). Any Annual Bonus shall only be payable upon the achievement by the Companies as a whole of certain performance goals to be established in respect of each calendar year by the Board; provided, however, that Executive shall receive an Annual Bonus in respect of the first calendar year occurring during the term of the Agreement that shall in no event be less than the Target Bonus. Notwithstanding any of the foregoing, and subject to the provisions of Section 4 of this Agreement, in the event that the term of this Agreement is scheduled to terminate prior to the end of any given calendar year of the Companies, Executive shall only be eligible to earn a pro rata portion of his Annual Bonus in respect of such calendar year, based on the number of days during such calendar year in which Executive is employed hereunder.(b) Deferred Compensation Plan. During the term of this Agreement, Executive shall be eligible to participate in any deferred compensation plan or program maintained by the Companies from time to time in which other senior executives of the Companies participate, on terms comparable to those applicable to such other senior executives.

3.3 Benefit

Plans and Perquisites.(a) Generally. The Companies shall provide Executive, during the term of his employment hereunder, with coverage under all employee benefit programs, plans and practices (commensurate with his positions in the Companies and to the extent permitted under any employee benefit plan) in accordance with the terms thereof, which the Companies make available to its senior executives and other employees including, without limitation, retiree medical insurance program as in effect as of the date of Executive's retirement from employment hereunder; provided, however, that at the Companies' discretion, Service Corporation may pay Executive an amount in cash sufficient, in the good faith determination of the Companies, for Executive to purchase a retiree medical insurance policy for Executive (and his eligible dependents) that provides retiree medical insurance benefits that are equivalent to such benefits as provided under the Companies' retiree medical insurance program to their senior executives as in effect at such time.(b) Perquisites. Executive shall be entitled to the perquisites and other fringe benefits generally made available to senior executives of the Companies, commensurate with his position with the Companies, including, without limitation: (1) use of memberships sponsored by the Companies for their senior executives at local country clubs and/or local luncheon clubs; (2)use of any aircraft owned or leased by the Companies for transportation of their executives, for both business and personal use, in accordance with the Companies' policies in effect from time to time for senior executives; (3) gross-up payments to cover applicable federal, state and local income taxes on such portion of any imputed income associated with Executive's personal use of aircraft owned or leased by the Companies and in accordance with such calculation methodology as may be determined from time to time by the Human Resources Committee of the Board; and (4) participation in the Companies' financial counseling program as in effect for senior executives from time to time.(c) Life Insurance. During the term of this Agreement, Service Corporation will use its reasonable best efforts to purchase and maintain, for the benefit of Executive and his 3 designated beneficiaries, a universal life insurance policy that provides at least a $3,000,000 death benefit.(d) Credit for Service: Pension Benefit. The Companies and Executive hereby agree that the opening balance of Executive's cash balance account under the AEP Excess Benefit Plan shall be $2,100,000, in which account Executive shall become vested, subject to his continued employment hereunder, in increments of twenty percent (20%) on each of the first five anniversaries of the Commencement Date. In recognition of his prior experience, the Companies and Executive also agree that Executive's cash balance account under the AEP Excess Benefit Plan shall, effective as of the Commencement Date, be credited with an amount such that the total credit under the AEP Retirement Plan and the AEP excess Benefit Plan shall be the maximum rate permitted under such plans as amended from time to time (currently 8.5%) on all eligible earnings thereunder (which eligible earnings may not exceed $1,000,000 annually). Subject to the foregoing in this Section 3.3(d), all other provisions of the AEP Retirement Plan and AEP Excess Benefit Plan as in effect from time to time shall apply to Executive's participation therein.(e) Vacation. During the term of this Agreement, Executive shall be entitled to five weeks of paid vacation (and such paid holidays as provided to senior executives of the Companies under the applicable vacation policy in effect from time to time), to be taken at such time(s) as Executive and the Board reasonably agrees is appropriate.(f) Reimbursement of Business Expenses. Executive is authorized to incur reasonable expenses in carrying out his duties and responsibilities under this Agreement, including reimbursement for any reasonable automobile expenses (including mileage) incurred in connection with travel (other than for any commute between Executive's principal office location and primary residence) by Executive in performance of his duties. Service Corporation shall promptly reimburse Executive for all reasonable business expenses incurred in connection with the performnance of his duties hereunder, subject to Executive's provision of reasonable documentation of such expenses in accordance with the Companies' business expense reimbursement policy for senior executives.(g) Payment of Relocation Expenses. To assist Executive in relocating from his principal residence (as of the date hereof) to Columbus, Ohio, Executive shall participate in the Relocation Expense Policy for Newly Hired Exempt Employees (a copy of which is attached as Exhibit A hereto).3.4 Long-Term Incentive Awards. During the term of this Agreement, AEP shall provide Executive with the opportunity to participate in the American Electric Power System 2000 Long-Term Incentive Plan, as amended from time to time (the "LTIP"), under which AEP shall grant to Executive the following equity-based compensation awards, which shall, as of the Commencement Date, have an aggregate target value equal to 360% of Executive's Base Salary: (a) Stock Options. On the Commencement Date, AEP shall grant to Executive options to purchase not less than 149,000 shares of common stock of AEP ("AEP Stock")pursuant to the LTIP (the "Options"). Subject to Executive's continued employment hereunder, the Options shall vest as to one-third of the shares subject to the Options on the January 1 following each of the first three anniversaries of the grant date of the Options, and otherwise shall be granted on such terms and pursuant to such award agreements as provided to senior executives of the Companies generally under the LTIP.4 (b) Performance Shares. On the Commencement Date, Executive will be awarded 119,000 performance share units pursuant to the LTIP. The actual number of performance share units that may be earned will be subject to the satisfaction of the performance metrics to be established by the Human Resources Committee of the Board. Executive shall vest in any such earned performance share units, subject to the Executive's continued employment, on December 31, 2006 and otherwise shall be granted such units on such terms and pursuant to such award agreements as provided to senior executives of the Companies generally for AEP performance share units. As a performance share unit participant, Executive xvill be subject to a stock ownership requirement determined and periodically adjusted by the Human Resources Committee of the Board.3.5 Payments and Provisions in Respect of Employment.(a) Bonus Restricted Stock. On the Commencement Date, AEP shall grant to Executive 100,000 shares of AEP Stock ("Bonts Stock") pursuant to the LTIP. Subject to Executive's continued employment hereunder, fifty percent (50%) of the Bonus Stock shall vest on January 1, 2005 and the remaining fifty percent (50%) of the Bonus Stock shall vest on January 1, 2006 and otherwise the Bonus Stock shall be granted on such terms and pursuant to such award agreement as provided to senior executives of the Companies generally under the LTIP.(b) Replacement of Long-Term Incentive Awards. In consideration for Executive's forfeiture of certain long-term incentive compensation awards, on the Commencement Date, AEP shall grant to Executive 200,000 shares of AEP Stock ("Restricted Stock") pursuant to the LTIP. Subject to Executive's continued employment hereunder, the Restricted Stock shall vest as to one-third of the shares on each of November 30, 2009, November 30, 2010 and November 30, 2011, and otherwise the Restricted Stock shall be granted on such terms and pursuant to such award agreement as provided to senior executives of the Companies generally under the LTIP.4. Termination of Employment.

4.1 Termination

Not for Cause. Either of the Companies may terminate Executive's employment hereunder at any time other than for Cause (as defined in Section 4.4 hereof).(a) If Executive's employment hereunder is terminated by the Companies other than for Cause (as defined in Section 4.4 hereof) (and other than as a result of Executive's death or Permanent Disability (as defined in Section 4.2 hereof)) during the term of this Agreement, Executive shall receive from Service Corporation the following: (1) all "'Accrzied Benefits", which term is defined as the following: (x) any accrued but unpaid Base Salary through the date of termination, payable in a lump sum promptly after such termination of employment; (y) any earned but unpaid Annual Bonus in respect of any previously completed calendar year of the Companies, payable in a lump sum promptly after such termination of employment; and (z) such payments under applicable plans, policies and programs, including but not limited to those referred to in Section 3.3 hereof, to which he is entitled upon such termination of employment pursuant to the terms of such plans, policies or programs; and 5 (2) continued payment of Base Salary, at the rate in effect immediately prior to the date of Executive's termination of employment, for the two year period immediately following the date of such termination of employment, paid in substantially equal installments in accordance with the ordinary payroll practices of the Companies; and (3) subject to Executive's election to receive group health coverage from Service Corporation under the Consolidated Omnibus Reconciliation Act of 1985, as amended, continued participation, at the same level of expense paid by Executive prior to such termination, in all medical, dental, vision and hospitalization insurance programs (collectively, the "Welfare Plans") in which Executive (and his eligible dependents) were participating on the date of his termination until the earlier of: (x) the first anniversary of the date of termination of Executive's employment or (y) the date, or dates, Executive becomes eligible for coverage and benefits under similar plans and programs of a subsequent employer. Executive shall promptly advise the Companies of any such subsequent employment and the benefits he receives in connection therewith.(b) Effect of Change in Control. Notwithstanding the foregoing, upon a termination of Executive's employment that would entitle Executive to receive payments and benefits under that certain Service Corporation Change in Control Agreement for the Office of the Chairman that Service Corporation and Executive agree to enter into on the date hereof, which agreement shall be substantially in the form attached hereto as Exhibit B (the "Change in ControlAgreement"), Executive shall be entitled to the payments and benefits provided under the Change in Control Agreement in lieu of the payments and benefits otherwise provided under Section 4.1(a) to the extent applicable.

4.2 Permanent

Disability. If Executive becomes totally and permanently disabled (as defined in any long-term disability benefit plan of the Companies applicable to senior executive officers as in effect on the date thereof) ("Permanent Disability'), the Companies or Executive may cause Executive to be removed from the positions held hereunder upon written notice thereof, and Executive shall receive or commence receiving as soon as practicable: (a)amounts payable pursuant to the terms of any disability insurance policy or similar arrangement which the Companies maintain during the term hereof; and (b) the Accrued Benefits, if any. In the event of ajudicial determination of Executive's incompetence, reference in this Agreement to Executive shall be deemed, where appropriate, to refer to his legal representative. 4.3 Death. In the event of Executive's death during the term of this Agreement hereunder, Executive's estate or designated beneficiaries shall receive or commence receiving, as soon as practicable (a) any death benefits provided under the employee benefit programs, plans and practices, including those referred to in Section 3.3 hereof, in accordance with their terms and (b) any other Accrued Benefits. In the event of Executive's death, reference in this Agreement to Executive shall be deemed, where appropriate, to refer to his beneficiary, estate or other legal representative, as applicable.

4.4 Discharge

for Cause: Voluntary Termination by Executive. During the term of this Agreement, (i) either of the Companies shall have the right to terminate the employment of Executive hereunder for Cause (as defined in and in accordance with Section 4.4(b) below) at any time and [(ii) Executive shall have the right to terminate his employment hereunder, other 6 than as a result of Executive's Permanent Disability or death, at any time following at least sixty (60) days advance written notice to the Companies of such termination.(a) Effect of Termination. During the term of this Agreement, in the event that Executive's employment is terminated hereunder by the Companies for Cause, or by Executive other than as a result of Executive's Permanent Disability or death, Executive shall only be entitled to receive any amounts to which he has a nonforfeitable right under any employee benefit programs or plans referred to in 3.3 hereof, in accordance with their terms, and any other Accrued Benefits. After the termination of Executive's employment under this Section 4.4(a), the obligations of the Companies under this Agreement to make any further payments, or provide any benefits specified herein, to Executive shall thereupon cease and terminate.(b) Definition of Cause. As used herein, the term "Cause" shall be limited to (1)willful malfeasance or willful misconduct by Executive in connection with his employment, (2)continuing refusal by Executive to perform his duties hereunder or any direction of the Board, after notice and a reasonable opportunity to perform such duties or direction was given to Executive by the Board, (3) any breach of the provisions of Section 7 of this Agreement by Executive or any other material breach of this Agreement by Executive or (4) the commission by Executive of any misdemeanor involving moral turpitude or a felony. Termination of Executive pursuant to this Section 4.4 shall be made by delivery to Executive of a copy of a resolution duly adopted by the affirmative vote of not less than a majority of the directors at a meeting of the Board called and held for the purpose (after 30 days prior written notice to Executive and reasonable opportunity for Executive to be heard before the Board prior to such vote), finding that in the good faith business judgment of such Board, Executive was guilty of conduct sat forth in any of clauses (I) through (4) above and specifying the particulars thereof.5. Mitigation of Damages: Offset. Executive shall not be required to mitigate damages or the amount of any payment provided for under this Agreement by seeking other employment or otherwise after the termination of his employment hereunder. Notwithstanding the foregoing, any payments received by Executive from other employment after any termination of Executive's employment hereunder shall reduce any payments to which he would otherwise be entitled from the Companies hereunder.

6. Notices. All notices or communications hereunder shall be in writing, addressed as follows: To the Companies:

c/o American Electric Power Company, Inc.1 Riverside Plaza Columbus, Ohio 43215 (attn: General Counsel)To Executive: Mr. Michael G. Morris c/o American Electric Power Company, Inc.I Riverside Plaza Columbus, Ohio 43215 7 Any such notice or communication shall be delivered by hand or by courier or sent certified or registered mail, return receipt requested, postage prepaid, addressed as above (or to such other address as such party may designate in a notice duly delivered as described above), and the third business day after the actual date of mailing shall constitute the time at which notice was given.7. Nondisclosure of Confidential Information.

7.1 Nondisclosure

of Confidential Information. Executive shall not, at any time during the term of this Agreement or thereafter, without the prior written consent of the Companies, use, divulge, disclose or make accessible to any other person, firm, partnership, corporation or other entity any Confidential Information (as defined below) pertaining to the business of the Companies or any of their affiliates, except (a) while employed by the Companies, in the business of and for the benefit of the Companies, or (b) when required to do so by a court of competent jurisdiction, by any governmental agency having supervisory authority over the business of the Companies, or by any administrative body or legislative body (including a committee thereof) with jurisdiction to order Executive to divulge, disclose or make accessible such information. Notwithstanding anything herein to the contrary, any party to this Agreement (and any employee, representative, or other agent of any party to this Agreement) may disclose to any and all persons, without limitation of any kind, the tax treatment and tax structure of the transactions contemplated by this Agreement and all materials of any kind (including opinions or other tax analyses) that are provided to it relating to such tax treatment and tax structure. However, any such information relating to the tax treatment or tax structure is required to be kept confidential to the extent necessary to comply with any applicable federal or state securities laws. For purposes of this Section 7, "Confidential Information" shall mean non-public information concerning the finances, strategic business plans, product development (or other proprietary product data), marketing plans and other non-public, proprietary and confidential information of the Companies, their affiliates or their customers.

7.2 Restrictive

Covenants. The Executive acknowledges and recognizes the highly competitive nature of the businesses of the Companies and their affiliates and accordingly agrees as follows: (a) Covenant Not to Compete. During the Term of Employment and the Restricted Period (as defined below), Executive will not directly or indirectly: (1) engage in any business that is a Competing Business (as defined below);(2) enter the employ of, or render any services to, any person or entity (or any division of any person or entity) which is a Competing Business;(3) acquire a financial interest in, or otherwise become actively involved with or in, any Competing Business, directly or indirectly, as an individual, partner, shareholder, officer, director, principal, agent, trustee or consultant; or (4) interfere with, or attempt to interfere with, business relationships (whether formed before, on or after the date of this Agreement) between the Companies and any of its affiliates and their respective material customers, clients or suppliers.(b) Permitted Activities. Notwithstanding anything to the contrary in this Agreement, during the term of this Agreement and thereafter, Executive may: (x) directly or 8 indirectly own, solely as an investment, securities of any person engaged in a Competing Business which are publicly traded on a national or regional stock exchange or on the over-the-counter market if Executive (1) is not a controlling person of, or a member of a group which controls, such person and (2) does not, directly or indirectly, own one percent (1%) or more of any class of securities of such person (excluding any interest Executive owns through a mutual fund, private equity fund or other pooled account).(c) Covenant Not to Solicit Employees. During the term of this Agreement and the Restricted Period, Executive will not, whether on Executive's own behalf or on behalf of or in conjunction with any person, company, business entity or other organization whatsoever, directly or indirectly hire any executive or employee who was employed by either of the Companies (or any of their major subsidiaries) as of the date of Executive's termination of employment with the Companies or who left the employment of the Companies coincident with, or within twelve (12) months prior to or after, the termination of Executive's employment with the Companies (provided that nothing herein shall prevent Executive from the general advertising for employees or from serving as a reference for an employee of the Companies).(d) Definitions. For purpose of this Section 7, (1) the term "Competing Business" shall mean any business in a geographic area in which the Companies or any of their major subsidiaries engage, in any such case at the relevant time during the term of employment or on the date of any termination of Executive's employment hereunder, as applicable, and (2) the term"Restricted Period' shall mean the period beginning on the date on which Executive's employment hereunder termninates, for any reason, through the second anniversary of such date.7.3 Reasonableness of Covenants: Remedies.(a) Reasonableness of Covenants. Executive and the Companies agree that the foregoing nondisclosure and other restrictive covenants are reasonable covenants under the circumstances, and further agree that if in the opinion of any court of competent jurisdiction any such restraints are not reasonable in any respect, such court shall have the right, power and authority to excise or modify such provision or provisions of these covenants as to the court shall appear reasonable and to enforce the remainder of the covenants as so amended.(b) Remedies. Executive agrees that any breach of the covenants contained in this Section 7 would irreparably injure the Companies. Accordingly, Executive agrees that (1)Service Corporation may cease any payments being made under Section 4 of this Agreement and/or (2) either of the Companies may, in addition to pursuing any other remedies it may have in law or in equity, obtain an injunction against Executive from any court having jurisdiction over the matter restraining any further violation of this Agreement by Executive.

8. Withholding Taxes. The Companies may withhold from any amounts payable under this Agreement to Executive such Federal, state, local and other taxes as may be required to be withheld pursuant to any applicable law or regulations.

9. Governing Law: Resolution of Disputes.9.1 Governing Law. This Agreement shall be construed, interpreted and governed in accordance with the laws of the State of Ohio, without reference to rules relating to conflicts of law.9

9.2 Resolution

of Disputes. Subject to the provisions of Section 7.3, any disputes arising under or in connection with this Agreement shall be resolved by binding arbitration, to be held in Columbus, Ohio, in accordance with the rules and procedures of the American Arbitration Association. Judgment upon the award rendered by the arbitrator(s) may be entered in any court having jurisdiction thereof. Each party to this Agreement shall bear his or its own costs of the arbitration.

10. Entire Agreement; Amendments.

10.1 Entire Aareement and Effect on Prior Agreements. This Agreement contains the entire understanding between the parties hereto and supersedes in all respects any prior or other agreement or understanding between the Companies or any affiliate of the Companies and Executive. 10.2 Amendments and Waivers. No provision in this Agreement may be amended unless such amendment is agreed to in writing and signed by Executive and an authorized officer of either of the Companies. No waiver by any party hereto of any breach by another party of any condition or provision contained in this Agreement to be performed by such other party shall be deemed a waiver of a similar or dissimilar condition or provision at the same or any prior or subsequent time. Any waiver must be in writing and signed by Executive or an authorized officer of either of the Companies, as the case may be.11. Severability: Survivorship. 11.1 Severability. In the event that any provision or portion of this Agreement shall be determined to be invalid or unenforceable for any reason, in whole or in part, the remaining provisions of this Agreement shall be unaffected thereby and shall remain in full force and effect to the fullest extent permitted by law so as to achieve the purposes of this Agreement.

12. Survivorship.

Except as otherwise expressly set forth in this Agreement, the respective rights and obligations of the parties hereunder shall survive any termination of Executive's employment. Upon the expiration of the term of the Agreement, the respective rights and obligations of the parties shall survive such expiration to the extent necessary to carry out the intentions of the parties as embodied in the rights (such as vested rights) and obligations of the parties under this Agreement.

13. Assignment.

This contract shall be binding upon and inure to the benefit of the heirs and representatives of Executive and the assigns and successors of the Companies, but neither this Agreement nor any rights or obligations hereunder shall be assignable or otherwise subject to hypothecation by Executive (except by will or by operation of the laws of intestate succession) or by either of the Companies, except that either of the Companies may assign this Agreement to any successor (whether by merger, purchase or otherwise) to all or substantially all of the stock, assets or businesses of the Companies, if such successor expressly agrees to assume the obligations of the Companies hereunder.

14. Counterparts.

This Agreement may be executed in two or more counterparts, each of which will be deemed an original.[Signatures next page]10 IN WITNESS WHEREOF, the undersigned have executed this Agreement as of the date first written above.AMERICAN ELECTRIC POWER COMPANY INC.By Isl John P. DesBarres Name: John P. DesBarres Title: Chairman, Human Resources Committee of American Electric Power Company AMERICAN ELECTRIC POWER SERVICE CORPORATION By Isl John P. DesBarres Name: John P. DesBarres Title: Chairman, Human Resources Committee of American Electric Power Company EXECUTIVE Is! Michael G. Morris Michael G. Morris 11 EXHIBIT A to Exhibit 1O(m)(1)AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR**EXEMPT EMPLOYEES** and**NON-EXEMPT SUPERVISORS** and**NEWLY HIRED EXEMPT EMPLOYEES** SALARY GRADES 26 AND ABOVE EFFECTIVE MAY 1, 2002 (Revised March 1, 2003) .., AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)THIS RELOCATION POLICY AND OTHER USEFUL INFORMATION ON YOUR RELOCATION IS AVAILABLE ON-LINE AT NVWW.SIRVARELOCATION.COM. THIS IS THE NVEBSITE OF SIRVA Relocation (SIRVA), AEP'S RELOCATION VENDOR. YOU WILL BE EMAILED A USER LOGIN ID AND PASSWORD AT THE ONSET OF YOUR RELOCATION. PLEASE VISIT THIS SITE FOR ANSWERS TO YOUR QUESTIONS AND OTHER HELPFUL MOVING TIPS.PLEASE DO NOT CONTACT ANY REAL ESTATE AGENTS OR SIGN ANY LISTING AGREEMENTS, CONTRACTS OR OTHER DOCUMENTS PRIOR TO SPEAKING WITH YOUR DESIGNATED SIRVA RELOCATION COUNSELOR 2 AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)TABLE OF CONTENTS ARTICLE 1. ELIGIBILITY A. Current Employees (Exempt Employees & Non-Exempt Supervisors) B. Newly Hired Exempt Employees in Salary Grades 26 & Above ARTICLE II. MARKETING AND DISPOSAL OF PRESENT RESIDENCE A. Home Defined B. Home Sale Assistance I. Marketing Assistance Program 2. Marketing Assistance Program Bonus 3. Safety-Net

4. Guaranteed Purchase Offer 5. Vacate Date 6. Negative Equity 7. Cost of the Home Sale Program 8. Selling Home Outside the Home Sale Assistance Program C. Loss on Sale Protection D. Lease Agreements E. Land Contracts F. Mobile Homes ARTICLE III. NEW RESIDENCE A. Lump Sum Payment -House Hunting/Temporary Living/Retum Trips B. Final Move Expenses C. Miscellaneous Expense Allowance (Current AEP Employees Only)D. Duplicate Housing Expenses E. Equity Loan F. Movement of Household Goods ARTICLE IV. MORTGAGE ASSISTANCE A. Point Reimbursement Payments B. Mortgage Companies ARTICLE V. TAXABILITY OF REIMBURSED EXPENSES A. IRS 50-Mile Test B. Tax Allowance/Gross Up ARTICLE VI. ADMINISTRATION OF POLICY ATTACHMENT I -EQUITY LOAN AGREEMENT and PROMISSORY NOTE ATTACHMENT II- RELOCATION SERVICES EMPLOYMENT CONTRACT (Newly Hired Exempt Employees Only)3 AMERICAN ELECTRIC PONVER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES

& NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)The AEP relocation policy provides for reimbursement of certain, designated expenses which are directly related to the domestic relocation of an eligible employee who is requested by the Company to relocate to a new work location. The policy is designed to help relieve employees of the financial and physical burdens which normally accompany a relocation. Through close adherence to the policy, efficiency and consistency of all employee relocations can be assured.ARTICLE I. ELIGIBILITY A. Current Employees Regular, full time exempt employees and non-exempt supervisors are eligible for full coverage and all benefits under the relocation policy.Employees are eligible for benefits under this policy provided: 1. The relocation is considered permanent or indefinite (i.e., there is no predetermined intention to return or transfer the employee back to the previous location or to another location within a one-year period), and 2. The Company requests the employee to relocate.B. Newly Hired Exempt Employees in Salary Grades 26 and Above Newly hired exempt employees in salary grades 26 and above are eligible for full coverage and all benefits under the relocation policy except the Miscellaneous Expense Allowance. The new employee will be required to enter into a RELOCATION SERVICES -EMPLOYMENT CONTRACT (Attachment II) with the Company whereby he/she agrees that upon voluntary termination from the Company within one year of employment he/she will upon request from the Company be required to reimburse the Company for all payments made to him/her or in his/her behalf except those made pursuant to article III, sections A and E.ARTICLE II. MARKETING AND DISPOSAL OF PRESENT RESIDENCE The Company has contracted with SIRVA Relocation (SIRVA) an international relocation services firm, to assist relocating employees in finding potential buyers for their homes. If these efforts prove unsuccessful, SIRVA will also offer to purchase the homes of employees, subject to the property meeting SIRVA's minimum requirements, as described on page 6. In addition, SIRVA will assist the employee in locating a home for purchase at the new work location area (Destination Services). SIRVA will also provide assistance in the movement of the household goods through its Moving Services unit (see Article III-E).The home marketing and disposal benefit assists a transferring employee in finding a suitable buyer who is willing to pay at or near the most probable sales price for the home, and disposing of his/her home in the most efficient possible manner. An eligible 4 AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)employee has the option of: (1) selling the home under the Home Sale Assistance Program as described in Section B below; or (2) attempting to sell the home on his/her own outside the Home Sale Assistance Program.In order to maximize your relocation benefits do not contact any real estate agents prior to your initial contact with your individual Relocation Counselor at SIRVA Relocation (SIRVA). SIRVA will provide you with a list of qualified agents who specialize in relocation moves in your area. From this list, you may choose the agent with whom you would like to list the property. If you choose an agent that is not on SIRVA's approved list, the agent must be qualified in advance and agree to pay a referral fee to SIRVA.A. Home Defined Home shall mean improved real estate: I. which is, at the issuance by the Company of the SIRVA relocation assistance authorization, employee-owned and occupied primary, single-family residence, townhouse; two-family (duplex) provided the employee resides in one unit, or condominium unit provided said unit meets FNMA (Fannie Mae) / FHLMC (Freddie Mac) approval. Excluded are: any income producing properties; resort properties; mobile homes not permanently affixed to the property (See Article II, Section F);cooperative units; farms; homes with acreage that does not conform to the immediate area; properties on which clear title cannot be delivered; properties which do not qualify for conventional mortgage financing; properties that have black mold;properties that have an unresolved EIFS exterior finishing problem; properties in which inspections conducted disclose defects which rendered the property unmarketable and/or the employee does not repair to the satisfaction of Supplier.2. which shall include only the items of personal property set forth in the Contract of Sale;3. with respect to which all mortgages can be prepaid. If a prepayment penalty is required, it must not exceed the greater of:* one percent (1%) of the original loan, or* six months interest on the principal balance prepaid 4. with respect to which insurance is available at standard rates for normal hazards of fire and extended coverage;5. with respect to which all leases can be terminated by SIRVA with no more than a (60)sixty-day notice to the lessor;5 AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXENMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)6. which is not situated on or near and does not contain any hazardous or toxic materials or gases, including but not limited to black mold, asbestos, lead paint, radon gas, urea formaldehyde foal insulation (IJFFI), or an unresolved exterior insulating and finishing system problem (EIFS);7. which contains acreage (lot size) within the norm and specific zoning limits for that particular locale or neighborhood. If there is excess acreage, SIRVA will not purchase more than is considered to be necessary to make the residence salable;8. in which the employee has clear and marketable title;9. which has all the normal characteristics of a home such as potable running water, sewvage or septic system, electricity, etc., and 10. which has been repaired by the employee or where repairs are necessary as a result of inspections or appraisals. B. Home Sale Assistance An eligible employee who owns a home at the former location, which meets the above definition, may elect to sell the home through the Home Sale Assistance Program offered by SIRVA. SIRVA will be authorized to contact the employee by the Company at the onset of the move to start the Home Sale Program as well as other relocation benefits.1. Marketing Assistance Program All qualified relocating employees are eligible to participate in the Marketing Assistance Program offered by SIRVA. The Marketing Assistance Program is designed specifically to assist employees in finding potential buyers for their homes. Employees are required to market their home for a ninety (90) day marketing period before they may accept the Guaranteed Purchase Offer described below.SIRVA's assistance includes the selection of relocation specific Realtors, assistance in effectively pricing the employee's home for sale, the development of an effective marketing plan and the tax-efficient purchase of the employee's home by SIRVA, at acceptable price, terms and conditions to the employee. With SIRVA's help: The employee should sell their home quickly at the highest attainable market price (The best opportunity to maximize the asking price of a home is during the first 30 days of listing, when market excitement about the home is highest and buyer traffic is at its greatest.) 6 AMERICAN ELECTRIC POWVER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)The employce will not incur any costs of sale such as commissions and/or statutory closing costs. These costs will be incurred by SIRVA.* The employee is not required to attend the ultimate closing on their old home.* The employee is protected from contracts or buyers that "fall-through" once SIRVA has committed to buy the home. If the ultimate market buyer fails to close on the purchase of the employee's home, SIRVA is solely responsible for the disposal of the property.IMPORTANT: In order to preserve their relocation benefits, employees should not make any agreement or sign any document or accept any money before speaking with their Relocation Counselor at SIRVA to discuss the home sale process.To be eligible for the benefits described above, the employee must fully comply with the guidelines set forth below:* The employee agrees to execute the SIRVA Option Agreement, which details the terms and conditions under which SIRVA will purchase their home.* The employee agrees to work with SIRVA recommended real estate agents for home listing and at the employee's option, for home finding in the new location.* The employee agrees to allow SIRVA to market the home at a price no greater than 105% of the most probable selling price as indicated by the average of at least two Broker Price Opinions (BPO's) rendered by two independent realty agents approved by SIRVA.* The employee agrees to cooperate with their chosen listing agent in showing the property to prospective buyers and with any inspectors authorized by SIRVA and/or a prospective buyer.Additionally, an employee's property must qualify for the home sale program. The employee must also disclose any known defects to the property that may affect its marketability. The SIRVA Relocation Counselor will help evaluate a property's eligibility, provide more detail, and answer all questions that may arise.Once the employee executes the Option Agreement and agrees to a suitable list price for their home, SIRVA will handle all the administrative details of marketing the home during the 90 day marketing period. The SIRVA Relocation Counselor will discuss with the employee all market offers and will negotiate the highest attainable price for the home, which will represent the fair market value at which SIRVA will exercise its option to purchase the employee's home. Once the employee agrees to the fair market value, the employee will enter into a binding contract with SIRVA and a date at which the employee will receive the proceeds of the sale will be established. The employee's equity -will be computed and expenses prorated as of the date SIRVA accepts the contract of sale or vacating date, whichever is later. SIRVA will then complete the sale with the buyer. The homesale process is consideredfinal once it is 7 AMERICAN ELECTRIC POOWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)determined that the bz'er has been financially qualified to purchase the enployee 's home, inspections by the buyer ha'e been completed and addressed, and all contracts have been approved by SIR VA, regardless of whether SIR VA is able to complete the sale to the bri'er.2. Marketing Assistance Program Bonus Employees in the Marketing Assistance Program will receive a bonus of the greater of two percent (2%) of the selling price, or $1,000, if the outside offer is determined to be acceptable by SIRVA. Employees who do not use the Marketing Assistance Program are not eligible for this benefit.The 2% Bonus payment will be made to the employee by The Company when the homesale process between the employee and SIRVA is considered final, and will not be contingent on whether SIRVA is able to complete the sale with the buyer. The payment will be considered ordinary income and twill NOT be grossed up for tax purposes.3. Safety Net In the possible event the employee is unable to find a buyer for his/her home, the Company will also authorize SIRVA to prepare a back-up home purchase offer as described in the Guaranteed Purchase Offer section below.4. Guaranteed Purchase Offer After discussing the Marketing Assistance Program with the employee, a SIRVA Relocation Counselor will provide a list of up to four (4) qualified, licensed independent real estate appraisers from their nationwide network to perform an ERC Relocation Appraisal on their home. Upon receipt, the employee will need to select two (2)appraisers from the list and notify their SIRVA counselor who will work with the employee to arrange an appointment for the evaluation of their home. After the two appraisers inspect the employee's home, they will prepare their independent appraisal reports and determine an appraised value price for the home. The appraisal process documents the price an educated and knowledgeable buyer would pay for a home and the price at which an educated and knowledgeable seller agrees to sell the home. Research, comparable listings and sales, and a normal ninety-day (90) marketing period are used in this determination. The appraisals will be submitted to SIRVA for review. If the appraisal values are found to be accurate by SIRVA, the two appraisals will be averaged together and the resulting amount will become the employee's "Guaranteed Purchase Offer." SIRVA will offer to purchase the employee's home at this value after 90 days of mandatory home marketing, if the home has not already sold. SIRVA will notify the employee by telephone of the 8 AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)offer and confirm the offer in writing. The employee has sixty (60) days from the 90e day of initial home listing to accept SIRVA's offer.If the two appraisals are not within a 5% variance of each other, a third appraisal wvill be ordered and the closest two shall be averaged to come up with the employee's"Guaranteed Purchase Offer." At day 60 of the home marketing time, reasonable and necessary inspections, including but not limited to, a home inspection, structural, roof, pest and radon inspections will also be obtained by SIRVA at this time. The employee is solely responsible for rectifying or repairing any adverse items that appear on any of the inspections obtained by SIRVA, before SIRVA will be obligated to purchase the employee's home.5. Vacate Date The employee remains responsible for mortgage, taxes, insurance, maintenance, utility payments and other homeowner expenses until either the date the property is vacated or the date a new residence is purchased. (See Article II.D -Duplicate Housing) The vacating date normally will not be later than sixty (60) days from the date the employee accepts the offer by SIRVA; however, in unusual cases, extensions may be granted with prior approval from Human Resources.

6. Negative Equity In those cases where there is a Negative Equity situation (i.e. employee mortgage balance is greater than SIRVA's purchase offer/Guaranteed Purchase Offer), the employee must pay the difference between the mortgage balance and the Guaranteed Purchase Offer to SIRVA at the time of closing and sale of the property to SIRVA, should he/she accept SIRVA's purchase offer. Failure to make this payment to SIRVA will result in the withdrawal of SIRVA's Guaranteed Purchase Offer. Please see Article II, Section C for Loss on Sale Protection.

7. Cost of the Home Sale Program The cost of the Home Sale Program will be paid by the Company.8. Selling the Home Outside the Home Sale Assistance Program An employee who otherwise qualified for the Home Sale Assistance Program and elects to sell his/her home without the aid of SIRVA will be reimbursed by the Company for the following closing expenses:* Broker's commission

Reasonable and customary seller closing costs and legal fees 9 AMERICAN ELECTRIC POWVER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES

& NON-EXEMPT SUPERVISORS AND NEWVLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)* Transfer charges and transfer taxes* Mortgage prepayment penalties as per Article II, Section B.3 (but not points)* Taxes other then those incurred due to gain on sale or pro-rated property taxes No Guaranteed Purchase Offer will be available to employees who elect to sell their home outside the Home Sale Assistance Program.C. Loss on Sale Protection (Grossed-Up) Employees may occasionally find that real estate conditions force them to sell their residence for less than it cost them. This feature is designed to lessen the impact of such a financial loss. Under these circumstances, the Company will pay the difference between the sales' price to an outside buyer or the Guaranteed Price Offer (Whichever is applicable), and the original property purchase price (plus documented expenditures for labor and material used in IRS eligible capital improvements). This payment is limited to no more than 10% of the Guaranteed Purchase Price.In order to be eligible for this benefit, the following conditions and limitations apply:* The employee must have owned and occupied their single-family home, townhouse, or condominium located in the United States as their primary place of residence on the date first notified of their transfer.* If the home is on large acreage or is partially an investment property, loss on sale will be prorated on the basis of the percent of total value the residence portion represents.

If the employee shares ownership in the home with anyone other than a spouse, they must own at least 50% or more of the residence to receive any assistance.

The assistance will be prorated based on their percentage of ownership.

Mobile, modular and certain manufactured homes are not eligible except as noted in Article II, Section F.* Capital improvements are limited to those deemed allowable by the Internal Revenue Service (IRS).* Charges for interest on loans, labor performed by the employee or his/her family members are not eligible.* Repairs are not eligible.The Original purchase price documents plus all documentation for allowable capital improvements must be presented by the employee to their SIRVA Relocation Counselor.

After the SIRVA review, a final review by AEP's tax department will be made before authorization. Under no circumstances will payment be made before the home is sold or acquired by SIRVA. This amount will be grossed up for income taxes.10 AMERICAN ELECTRIC POWVER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)D. Lease Agreement An eligible employee renting his/her primary residence at the time of relocating who cannot cancel a lease arrangement without being assessed a penalty, shall be reimbursed by the Company for up to a two-month lease penalty and loss of deposit for canceling the lease. A copy of the lease agreement, indicating the penalty, and a paid receipt are required for reimbursement. E. Land Contracts For those eligible employees who have entered into a Land Contract agreement, the Home Sale Assistance Program is not available unless the employee is able to provide a clear title to the property or acceptable termination procedures are included with the Land Contract agreement. F. Mobile Homes When a mobile or pre-manufactured home is on property owned by the employee, is affixed to the property by being on a permanent concrete footer and poured concrete blocks (wheels, axle, and tongue removed), has all required utilities connected, meets FNMA/FHLMC financing criteria and meets criteria for conventional mortgage financing (such as having a perimeter block foundation), the Home Sale Assistance portion of the Relocation Policy will apply. If a mobile or pre-manufactured home does not meet the criteria described above, special arrangements may be made to assist the employee with the sale of their home.If a mobile or pre-manufactured home has not become affixed to property owned by the employee as described above, the Company will pay for the tear down, transportation and set up of the mobile home. In this type of situation, the Company does not buy the mobile home, but will reimburse the employee for sales commission and selling expenses if the employee sells the mobile home. Under no circumstances, will the Company purchase vacant land.ARTICLE III. NEW RESIDENCE The employee will receive professional assistance from SIRVA in locating homes in the destination location that meet the employee's needs. The Relocation Counselor will help the employee assess preferences, describe the assistance available and arrange for a free mortgage financing pre-qualification and consultation prior to the first home finding trip. The employee's Relocation Counselor will arrange appointments with one or more SIRVA designated Realtors to personally assist with area orientation and home shopping.11 .AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)In an effort to improve the quality of real estate agent selection and control costs, AEP is using a"Broker Registration" program with SIRVA. If the employee wants to use an agent outside of SIRVA's recommendation, the employee must register their agent choice with the SIRVA Relocation Counselor. All brokers selected vill be responsible for paying a referral fee to SIR VA.A. The Lump Sum Payment (Grossed-Up) The Company will provide a Lump Sum Payment to cover expenses related to House Hunting, Return Trips Home and Temporary Living, (e.g. travel, mileage, rental car, lodging, meals, telephone, parking, tolls, babysitting, and other miscellaneous expenses). Payment of this Lump Sum will generally be made within one month of the payroll transfer date to the new work location. The amount of the payment will vary depending on the distance from the employee's former home to the new work location as follow: Long Move (50 or more miles) $ 6,000 (less FICA taxes)Short Move (less than 50 miles) $ 2,500 (less FICA taxes)Note: For those transferees too far away to drive (normally 350 miles), the reasonable cost of air-fare will be reimbursed in addition to the Lump Sum Payment allowance, with prior approval.The employee's FICA expense on this payment will be withheld providing the employee does not exceed the FICA income base in the year of the move.Employees are also eligible for up to 5 days off withpayfor house hunting trips and up to 3 days off vithpayfor the final move trip to the new work location, as needed Additional time off with pay may be available at the discretion of the supervisor. The SIRVA Relocation Counselor will explain all the details of the expense reimbursement process for the following benefit areas including Selling The Home Outside the Home Sale Assistance Program, Loss on Sale Protection, Lease Break Assistance, The Lump Sum Payment, Final Move Expenses, The Equity Loan, Home Purchase Expense (where applicable), Duplicate Housing Expenses, Miscellaneous Expense Allowance and other potential expenses.B. Final Move Expenses The employee will be reimbursed for transportation expenses related to their final move to the new location. Mileage will be paid at the current Company mileage rate. Expense coverage for the final move consists of reasonable meals and lodging for the employee and their family for one day prior to the departure to the new location, number of days en route (no vacation or sight-seeing) and arrival day. The employee should submit ALL receipts on the appropriate Relocation Expense form supplied by the Company.12 AMERICAN ELECTRIC PONVER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)Note: Reimbursement for local mileage prior to departure day at the former location and after arrival day at the new location is NOT reimbursable Meals and mileage reimbursement in excess of 12 cents per mile are included in the employee's earnings for income tax purposes and will be included in amounts reported as income on the employee's W-2 form. The Company will gross-up these expenses.Other travel expenses, including transportation and lodging are excluded from taxable income and, therefore, will not be tax assisted.C. Miscellaneous Expense Allowance (Current AEP Employees Only)A payment to current AEP employees of an amount equal to 100% of one month's salary (based on the salary at the new location), up to a maximum of $5,000, will be made by the Company. This payment is intended to help cover expenses the employee incurs in moving to the new location beyond the expenses specifically covered in this policy. This payment will be grossed-up for income taxes and the employee's FICA expense on this payment will be withheld providing the employee will not exceed the FICA income base in the year of the move.D. Duplicate Housing Expenses Homeowners -After an employee closes on his/her new residence, and if the employee has not sold his/her former home and is still paying a mortgage on his/her former home, the Company will reimburse the employee for the interest portion of the monthly mortgage payments of the former home for a period of up to sixty (60) calendar days from the date of closing on his/her new home.Whether or not the employee had a mortgage on his/her home, the Company will also reimburse the employee for real estate taxes, property insurance, utility expenses, and a reasonable amount for lawn care and/or snow removal. This reimbursement for duplicate residence expenses is available for a period up to sixty (60) calendar days from the date of closing on his/her home at the new location.Employee must be actively marketing former residence in order to be eligible for duplicate housing expense reimbursement. E. Equity Loan Upon entering into a purchase contract on a new residence, the employee can apply for an equity loan, interest free for 90 days, in an amount equal to SIRVA's Guaranteed Purchase Offer less any remaining mortgage balances, less four percent (4%) of the Guaranteed Purchase Offer held back for contingencies. An equity loan is available for the sole purpose of purchasing a home or initiating construction at the new location. This loan is available whether the employee sells his/her home to SIRVA or whether he/she tries to sell it himself/herself. If the employee eventually sells the property to SIRVA, 13 AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMIPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)the loan amount is deducted from the final equity due the employee from SIRVA. Any remaining balance of the four percent (4%) holdback not used for contingencies (taxes, interest, liens, etc.), is also paid to the employee when the property is sold.The employee is required to sign the SIRVA Mortgage Equity Loan Agreement and a Promissory Note to secure an equity loan. (See Attachment I)The equity loan, which is secured by the Promissory Note, will require repayment by the employee of the principal, as well as any costs incurred by SIRVA in collecting the Promissory Note, should the employee default (i.e., legal costs, collection, termination). Executive Officers and Directors of American Electric Power Company, Inc. (AEP) or any AEP subsidiary with publicly registered securities are not eligible to participate in this program.F. Movement of Household Goods The Company has contracted with SIRVA to provide experienced, efficient moving of all furniture and household effects to the residence at the new work location. The employee will be contacted by SIRVA's Moving Coordinator once authorization has been given by the Company. The Move Coordinator will assign a designated relocation van line to personally assist the employee with their move.1. The services provided by the SIRVA designated van line are: a. Shipment, packing and unpacking of all furniture and household goods. (One extra pickup and delivery en route to the new location will also be provided if needed.) Within one week of the move-in date, the van line will return to pick up packing boxes, if necessary. Shipment from temporary residence to permanent residence would be considered as a local move and would require management approval.b. All insurance premiums to cover loss or damage to furniture and household goods caused by fire, theft, collision, or water while in transit and/or storage on a replacement value basis or less based on the weight of the shipment. The limit of coverage is $ 100k, without a declaration by the employee of greater value, which will require an added premium.c. Storage of furniture and household goods for up to sixty (60) calendar days and delivery out of storage. Extensions of this 60-day limitation must be approved by Human Resources. Storage means at the moving company's facility only and delivery out of storage means one movement only.14 .AMERICAN ELECTRIC POWVER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)d. Major appliance disconnection and reconnection. The van line will transport items such as waterbeds, pool tables, satellite discs and swing sets, but will not disassemble or reassemble these items.e. Shipping of personal vehicles (one car if move is over 500 miles), boats 14 feet and less (including trailer), motorcycles, riding mowers/garden tractors and snowmobiles, with the number of each within reason for the size of the family. A second personal vehicle may be shipped if approved by management.

2. The van line is not authorized to ship: a. Any animals (including house pets)b. Trailers, campers or boats longer than 14 feet in length c. Farm or heavy machinery d. Furnishings from a second home e. Firewood, building materials, paint, chemicals, toxic or flammable materials.

ARTICLE IV.MORTGAGE ASSISTANCE A. Point Reimbursement Payments The Company will reimburse an employee for discount point(s) paid to reduce the interest rate on a mortgage obtained at the new location as follows: The 30-year rate for a given month will be the Federal National Mortgage Association (Fannie Mae) posted yield on 30-year mortgage commitments for delivery within 30 days as indicated in the Wall Street Journal on the first working day of each month. The 30-year rate and related point reimbursement amount will be determined as of the date 15 AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)the employee locks in a mortgage rate with the new lender.16 , AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)B. Mortgage Companies As part of the relocation program, AEP has contracted with SIRVA Mortgage and Huntington National Bank, to provide mortgage programs to help employees purchase homes in an efficient and economical manner. Although AEP is contracted with SIRVA Mortgage and Huntington National Bank, employee is under no obligation to use either lender.Employee may utilize a lender of their choice and receive reimbursement of normal and customary closing costs.SIRVA Mortgage offers a variety of loan products from prominent national lenders.SIRVA Mortgage will shop these lenders for you to find the best rate, product and program for your budget.A SIRVA Mortgage loan counselor will contact the employee to discuss loan options and the various lenders within this program. SIRVA Mortgage can be reached at 1-800-531-3837 or their website at ,wwvv.sirva.com. Although the employee is under no obligation to utilize SIRVA Mortgage, it should prove more beneficial to the employee to do so.SIRVA's No Closing Cost Loan Program -Non-recurring closing costs normally paid by the employee are eliminated through a no-closing cost loan program provided to the Company by SIRVA in conjunction with SIRVA Mortgage. SIRVA's mortgage program eliminates the need for the employee to turn in a HUD- I Settlement Statement for reimbursement and saves the company valuable tax gross-tip dollars.Under SIRVA's program, the employee will be responsible for non-recurring costs such as prepaid interest, real estate taxes, and private mortgage insurance (PMI).* Purchase must occur within 12 months of the effective date of relocation

Purchase must be permanent residence of the associate and his family* Does not apply to mobile homes or boats Executive Officers and Directors of American Electric Power Company, Inc. (AEP) or any AEP subsidiary with publicly registered securities are not eligible to participate in this program.Huntington National Bank's Loan Program -AEP has also contracted with Huntington National Bank to provide alternative mortgage options. Huntington's loan program will cover normal and customary closing costs normally incurred by the employee.

These costs are generally appraisal fees, credit report fees, title search, buyer paid title costs, required attorney's fees, statutory taxes/stamps and reasonable inspection costs.Should the employee choose Huntington for their mortgage, Huntington will advance to closing all of the reimbursable costs listed above. This service eliminates the need for the 17 AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)employee to have or to seek extra funds to have on hand in order to close. Nor will the employee need to submit an expense request, as Huntington will directly bill the Company for the appropriate costs. (This expense is taxable to the employee and ivill be grossed-up for income tax liability. Employee will be notified of their FICA tax liability for this expense.)The employee can contact Huntington National Bank by calling 1-800-228-5576 or refer to their website at www.huntington.com An employee utilizing a lender other than SIRVA Mortgage or Huntington National Bank must provide a copy of their HUD-I Settlement Statement in order to be reimbursed the normal and customary closing costs. (This expense is taxable to the employee and wvill be grossed-up for income tax liability when check is issued, and FICA tax on this amount and the gross-up will be withheld.) Executive Officers and Directors of American Electric Power Company, Inc. (AEP) or any AEP subsidiary with publicly registered securities are not eligible to participate in this program.ARTICLE V. TAXABILITY ON REIMBURSED EXPENSES All reimbursements of moving expenses other than certain costs of moving household goods and 30 days of household goods storage must be reported on the employee's W-2 as other compensation at the end of the year in which such reimbursements were received. The Company is required to withhold at statutory rates for all federal/state/local taxes and FICA (Social Security) up to the designated yearly base.A. IRS 50-Mile Test If a move meets the IRS 50-mile test, the payment for the transportation of household goods is excluded from the employee's income. If the move fails the IRS -50 mile test, the payment for the transportation of household goods and 30 days of storage are included in the employee's income. To meet the IRS 50 -mile test, the employee's new work location must be at least 50 miles farther from their former residence than was their former work location. (It should be noted that the distance calculation for the IRS 50 -mile test is different than the Company's distance calculation used to determine the amount of the Lump Sum Payment for the less than 50 mile transfer described in Article II. Section A.)B. Tax Allowance/Gross-Up The Company will pay to the appropriate taxing authorities on behalf of the employee a tax allowance approximating the federal, state, and local income taxes (there will be no tax allowance for any additional FICA taxes) imposed as a result of the employee 18 AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)receiving from the Company the following benefits: (1) the one-month salary allowance, (2) the lump sum payment [which covers house hunting, return trips home and temporary living, (3) the cost of settling any leases; (4) reimbursement of closing expenses on the old residence if the employee sells the home without SIRVA's assistance, (5) the payment for closing costs on the home purchased at the new location if necessary, (6) the Loss on Sale Protection payment, if any, and (7) certain duplicate housing expenses.In the case of a move that fails the IRS -50 mile Test, the tax allowance will also cover cost of moving household goods and storage. The tax allowance itself is additional gross income to the employee, so the allowance will be "grossed up" to cover the additional tax resulting from the tax allowance. The tax allowance will be calculated on the basis of: (I) the employee's annualized compensation from the Company less the amount the employee is contributing through the Tax Deferral Option of the Savings Plan, (2) the standard deduction and the portion of the moving expenses which qualify as itemized deductions, and (3) the number of exemptions the employee is entitled to claim on his/her federal income tax return (regardless of the number claimed on his/her W-4 statement). In addition, only the Company's W-2 source income will apply as the base for the Tax Assistance. No outside income such as that from investments, rental properties or trusts will be considered. Spousal income will also not be eligible for gross-up unless the spouse also is employed by the Company.19 AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)TAX

SUMMARY

Home Sale Program No No No MAP Home Sale Yes Yes No Bonus Lump Sum Payment Yes Yes Yes Lease Break Penalty Yes Yes Yes Closing Cost on Old Yes Yes Yes Residence (outside the Home Sale Program)Loss on Sale Yes Yes Yes Household Goods No No No Shipment and 30 days of Storage Storage over 30 Days Yes Yes Yes New Home Purchase Yes*/No Yes*/No Yes*/No Duplicate Housing Yes Yes Yes Tax Assistance (1) Yes Yes Yes 1. Tax gross-up on gross-up payments 2. FICA will be withheld up to the yearly base and will not be grossed-up

If the employee does not utilize SIRVA's 'No Closing Cost Loan' Program *20 AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES

& NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)ARTICLE VI. ADMINISTRATION OF POLICY A. After an employee has accepted a new position/job transfer, a relocation authorization will be provided to SIRVA by AEP's Human Resources Relocation Coordinator. Assurning the house is marketable, the offer process will be continued. In addition, the employee will be requested to inform SIRVA of the original purchase price of his/her home and the outstanding balance of any existing mortgages on the property. If the employee decides to not accept the transfer, the process will stop upon notification to SIRVA.B. In the case of inter-company transfers, the Business Unit into which the employee is transferred will bear the cost of the relocation. C. All expenses pertaining to the relocation shall be approved by the Human Resources Department after review by SIRVA.D. The Human Resources Department at the new location will offer the employee such assistance and advice as shall be required.E. Any exceptions to this policy or home disposal procedures require the approval of the appropriate member of management. All requests for exceptions are to be submitted to the Human Resources Department. 21 AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWVLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1, 2003)ATTACHMENT I SIRVA Relocation Equity Loan Agreement and Promissory Note Employee Name: File No: Loan Amount S Check Number: Date Issued: e SIRVA Approval: Property Address:$ Date:_For value received, the undersigned Makers hereby promise to pay to SIRVA Relocation (hereinafter "SIRVA"), or its order, at its designated office, the principal sum of Dollars ($_ ) on or before the earliest to occur of (a) the expiration of an offer by SIRVA to purchase the Maker's home; (b) the closing of the sale of the Maker's home pursuant to contract of sales between the Makers, as sellers, and a third party, as buyer, or the failure to consummate such a sale at the scheduled place and time; (c) cancellation of the Makers' relocation for any reason whatsoever, or (e) the effective date of termination of the Relocation Management Agreement between SIRVA and the Makers' employer of the Equity Loan Agreement Service contained herein, (f) SIRVA determines that the Agreement and Promissory Note has remained outstanding for an unreasonable period of time.In the event that SIRVA purchases the Makers' home, the principal sum due shall be deducted from the equity due the Makers' under the application contract, and the deficit, if any, shall become immediately due and payable to SIRVA. In order to secure repayment of the indebtedness, the Makers' hereby assign, transfer and set over unto SIRVA all rights, title and interest in and to any agreement for the sale of the Makers' home which the Makers have entered into or may in the future enter into, and in and to all sums due or to become due thereunder or which may be payable on account of the sale of the said Home. Any such sum received by the Makers shall be held by them in trust as the property of SIRVA, and shall be paid by the Makers to SIRVA on demand by SIRVA, up to the amount of the Makers indebtedness to SIRVA under this agreement and promissory note. Makers agree not to consummate a sale of their Home without advising SIRVA prior thereto.In consideration of SIRVA entering into this agreement and promissory note: (a) The Makers represent that the loan will be used solely for the purpose of purchasing a new principal residence in connection with a transfer to a new principal place of employment and that neither the former for the new principal residence is or will be located outside the United State or a United States possession.(b) The Makers represent that the Makers intend to sell their Home, and have taken appropriate action, such as listing with brokers, or will do so within a reasonable time. The Makers agree that the Makers will notify SIRVA in writing when the Makers enter into an agreement to sell their Home, and again when title passes.(c) The Makers represent that the Makers have no intention of converting the Makers' present or former principal residence to business or investment use.(d) The Makers agree that any loss which the Makers sustain because of nonfulfillment of any contract to sell and purchase their Home by either the Makers, the buyer, or any other third party, is the Makers' responsibility, and that in such event the Makers will be obligated to repay their indebtedness to SIRVA.22 AMERICAN ELECTRIC POWER RELOCATION EXPENSE POLICY GUIDELINES FOR EXEMPT EMPLOYEES & NON-EXEMPT SUPERVISORS AND NEWLY HIRED EXEMPT EMPLOYEES -SALARY GRADES 26 AND ABOVE Effective May 1, 2002 (Revised March 1,2003)SIRVA Relocation Equity Loan Agreement and Promissory Note (e) The Makers agree that the obligations and benefits under this agreement and promissory note are personal to the Makers and may not be transferred, assigned or otherwise disposed of to any person except their employer.() The Makers agree that their Home will not be made subject to any further indebtedness by the Makers'affirmative act subsequent to signing this agreement and promissory note without prior written approval of SIRVA.(g) The Makers hereby represent that the Makers intent to and will itemize their deductions on their Federal Income Tax Returns.The undersigned Makers hereby waive presentment and notice of dishonor and agree that the obligations and benefits under this agreement and promissory note are personal to them and may not be transferred, assigned, or otherwise disposed of to any person except the Maker's employer.This instrument shall be governed by the laws of the State of Ohio.Maker: Date: Social Security No.: Maker: Date: Social Security No.:_23 Newly Hired Exempt Employee ATTACHMENT 11 Salary Grade 26 and Above RELOCATION SERVICES -EMPLOYMENT CONTRACT TIiS AGREEMENT, made and entered into this day of by and between AMERICAN ELECTRIC POWER, a corporation (hereinafter called "Company") and-of hereinafter called "Employee"). WITNESSETH THAT WHEREAS, Employee proposes to accept employment as an exempt employee of the Company at , and WHEREAS, Employee, in order to accept such position, must move his place of residence to , or its environs, and WHEREAS, Company is willing to pay the moving and incidental expenses of Employee providing Employee agrees to certain conditions, NOW, THEREFORE, for and in consideration of the agreements hereinafter contained, Company and Employee do hereby agree as follows: 1. Company will pay the moving and incidental expenses of Employee in accordance with the Special Relocation Expense Policy -Nevly-Hired Exempt Employees SG 26 & Above.2. Should Employee voluntarily terminate his/her employment with the Company within one year from the date of his/her employment, Employee, upon request of the Company, agrees to reimburse Company, promptly upon such termination, for all payments made to Employee, or in his/ier behalf pursuant to the Special Relocation Expense Policy -Newly-Hired Exempt Employees SG 26 &Above, EXCEPT those made pursuant to Article III -Sections A (Lump Sum Payment for house hunting, temporary living and final move) and E (payment for movement of household goods).IN WITNESS WHEREOF, the parties hereto have executed this agreement, the day and year first above written.AMERICAN ELECTRIC POWER By Date_(Company Representative) Date_(Employee) EXHIBIT B to Exhibit 10(m)(1)AMERICAN ELECTRIC POWER SERVICE CORPORATION CHANGE IN CONTROL AGREEMENT FOR THE OFFICE OF THE CHAIRMAN Whereas, American Electric Power Service Corporation, a New York corporation, including any of its subsidiary companies, divisions, organizations, or affiliated entities (collectively referred to as "AEPSC") considers it essential to its best interests and the best interests of the shareholders of the American Electric Power Company, Inc., a New York corporation, (hereinafter referred to as "Corporation") to foster the continued employment of key management personnel; and Whereas, the uncertainty attendant to a Change In Control of the Corporation may result in the departure or distraction of management personnel to the detriment of AEPSC and the shareholders of the Corporation; and Whereas, the Board of the Corporation has determined that steps should be taken to reinforce and encourage the continued attention and dedication of members of AEPSC's management to their assigned duties in the event of a Change In Control of the Corporation. Now Therefore, AEPSC hereby establishes the American Electric Power Service Corporation Change In Control Agreement (the "Agreement"). ARTICLE I DEFINITIONS As used herein the following words and phrases shall have the following respective meanings unless the context clearly indicates otherwise.(a) "Anniversary Date" means January 1 of each Calendar Year.(b) "Annual Compensation" means the sum of the Executive's Annual Salary and the Executive's Target Annual Incentive.(c) "Annual Salary" means the Executive's regular annual base salary immediately prior to the Executive's termination of employment, including compensation converted to other benefits under a flexible pay arrangement maintained by AEPSC or deferred pursuant to a written plan or agreement with AEPSC, but excluding allowances and compensation paid or payable under any of AEPSC's long-term or short-term incentive plans or any similar payments. (d) "Board" means the Board of Directors of American Electric Power Company, Inc.(e) "Calendar Year" means the twelve (12) month period commencing each January I and ending each December 31.(f) "Cause" shall mean (i) the willful and continued failure of the Executive to perform substantially the Executive's duties with AEPSC (other than any such failure resulting from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to the Executive by the Board or an elected officer of AEPSC wvhich specifically identifies the manner in which the Board or the elected officer believes that the Executive has not substantially performed the Executive's duties, or (ii) the willful engaging by the Executive in illegal conduct or gross misconduct which is materially and demonstrably injurious to AEPSC or the Corporation, or a breach of the Executive's fiduciary duty to AEPSC or the Corporation, as determined by the Board.For purposes of this provision, no act or failure to act, on the part of the Executive, shall be considered "willful" unless it is done, or omitted to be done, by the Executive in bad faith or without reasonable belief that the Executive's action or omission was in the best interests of AEPSC or the Corporation. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board or upon the advice of counsel for AEPSC or the Corporation, shall be conclusively presumed to be done, or omitted to be done, by the Executive in good faith and in the best interests of AEPSC or the Corporation (g) "Change In Control" of the Corporation shall be deemed to have occurred if (i) any "person" or "group" (as such terms are used in Section 13(d) and 14(d) of the Securities Exchange Act of 1934 ("Exchange Act"), other than AEPSC, any company owned, directly or indirectly, by the shareholders of the Corporation in substantially the same proportions as their ownership of stock of the Corporation or a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Corporation; (ii) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new directors (other than a director nominated by a person (x) who has entered into an agreement with the Corporation to effect a transaction described in this Article I (g)(i), (iii) or (iv) hereof or (y) who publicly announces an intention to take or to consider taking action (including, but not limited to, an actual or threatened proxy contest) which if consummated would constitute a Change In Control) whose election or nomination for election was approved by a vote of at least two-thirds of the directors then still in office who were either 2 directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason, except for death or disability, to constitute at least a majority of the Board; or (iii) the consummation of a merger or consolidation of the Corporation with any other entity, other than a merger or consolidation which would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 50 percent of the total voting power represented by the voting securities of the Corporation or such surviving entity outstanding immediately after such merger or consolidation; or (iv) the shareholders of the Corporation approve a plan of complete liquidation of the Corporation, or an agreement for the sale or disposition by the Corporation (in one transaction or a series of transactions) of all or substantially all of the Corporation's assets.(h) "Code" means the Internal Revenue Code of 1986, as amended from time to time.(i) "Commencement Date" means January 1, 2002, which shall be the beginning date of the term of this Agreement.(j) "Disability" means the Executive's total and permanent disability as defined in AEPSC's long-term disability plan covering the Executive immediately prior to the Change In Control.(k) "Executive" means an employee of AEPSC who is designated by AEPSC as an employee entitled to benefits, if any, under the terms of this Agreement.(I) "Good Reason" means;(1) an adverse change in the Executive's status, duties or responsibilities as an executive of AEPSC as in effect immediately prior to the Change In Control, provided that the Executive shall have given AEPSC written notice of the alleged adverse change and AEPSC shall have failed to cure such change within thirty (30) days after its receipt of such notice;(2) failure of AEPSC to pay or provide the Executive in a timely fashion the salary or benefits to which the Executive is entitled under any employment agreement between AEPSC and the Executive in effect on the date of the Change In Control, or under any benefit plans or policies in which the Executive was participating at the time of the Change In Control, provided that such failure was other than an isolated, insubstantial and inadvertent action not taken in bad faith and which is remedied by the Corporation within eight days following notice from the Executive; (3) the reduction of the Executive's salary as in effect on the date of the Change In Control;3 (4) the taking of any action by AEPSC (including the elimination of a plan without providing substitutes therefore, the reduction of the Executive's awards thereunder or failure to continue the Executive's participation therein) that would substantially diminish the aggregate projected value of the Executive's awards or benefits under AEPSC's benefit plans or policies in which the Executive was participating at the time of the Change In Control;(5) a failure by AEPSC or the Corporation to obtain from any successor the assent to this Agreement contemplated by Article IV hereof; or (6) the relocation, without the Executive's prior approval, of the office at which the Executive is to perform services on behalf of AEPSC to a location more than fifty (50) miles from its location immediately prior to the Change In Control or a change, without the Executive's prior approval, in the Executive's business travel obligation subsequent to the Change In Control that requires the Executive to travel on a regular and continuous basis in an amount that represents a significant increase, from immediately prior to the Change In Control, in the portion of the Executive's working time routinely devoted to business travel.Any circumstance described in this Article I (I) shall constitute Good Reason even if such circumstance wvould not constitute a breach by AEPSC of the terms of an employment agreement between AEPSC and the Executive in effect on the date of the Change In Control. The Executive shall be deemed to have terminated employment for Good Reason effective upon the effective date stated in a written notice of such termination given by the Executive to AEPSC (which notice shall not be given, in circumstances described in Article I (1), before the end of the thirty (30) day period described therein, or in circumstances described in Article I (1)(2), before the end of the eight day period described therein), setting forth in reasonable detail the facts and circumstances claimed to provide the basis for termination, provided that the effective date may not precede, nor be more than sixty (60) days from, the date such notice is given. The Executive's continued employment shall not constitute consent to, or a waiver of rights with respect to, any circumstances constituting Good Reason hereunder.(m) "Retirement" shall mean an Executive's termination of employment after attainment of age 55 with five or more years of service with AEPSC.(n) "Target Annual Incentive" shall mean the award that the Executive would have received under the Senior Officer Annual Incentive Compensation Plan ("SOIP") or the Management Incentive Compensation Plan ("MICP") for the year in which the Executive's termination occurs, if one hundred percent (100%) of the annual target award has been earned. Executives participating in annual incentive compensation plans that do not have predefined target levels will be treated as though they were participants in either the SOIP or MICP and will be assigned the same annual target percent as their participating peers in a comparable salary grade.4 (o) "Qualifying Termination" shall mean following a Change In Control and during the term of this Agreement the Executive's employment is terminated for any reason excluding (i) the Executive's death, (ii) the Executive's Disability, (iii) the Executive's Retirement, (iv) by AEPSC for Cause or (v) by the Executive without Good Reason. In addition, a Qualifying Termination shall be deemed to have occurred if, prior to a Change In Control, the Executive's employment was terminated during the term of this Agreement by AEPSC without Cause, or by the Executive for Good Reason based on events or circumstances that occurred, (i) at the request of a person who has entered into an agreement with AEPSC or the Corporation, the consummation of which would constitute a Change In Control or (ii) otherwise in connection with, as a result of or in anticipation of a Change In Control. The mere act of approving a Change In Control agreement shall not in and of itself be deemed to constitute an event or circumstance in anticipation of a Change In Control for purposes of this Article I (o).ARTICLE II TERM OF AGREEMENT 2.1 The initial term of this Agreement shall be for the period beginning on the Commencement Date and ending on the December 31 immediately following the Commencement Date. The term of this Agreement shall automatically be extended for an additional Calendar Year on the first Anniversary Date immediately following the initial term of this Agreement without further action by AEPSC, and shall be automatically extended for an additional Calendar Year on each succeeding Anniversary Date, unless AEPSC shall have served notice upon the Executive at least sixty (60) days prior to such Anniversary Date of AEPSC's intention that this Agreement shall not be extended, provided, however, that if a Change In Control of the Corporation shall occur during the term of this Agreement, this Agreement shall terminate two years after the date the Change In Control is completed. 2.2 If an employee is designated as an Executive after the Commencement Date or after an Anniversary Date, the initial term of this Agreement shall be for the period beginning on the date the employee is designated as an Executive and ending on the December 31 immediately following.

2.3 Notwithstanding

Section 2.1, the term of this Agreement shall end upon any termination of the Executive's employment prior to a Change In Control of the Corporation. This Agreement shall also terminate if the Executive's position is eliminated due to a downsizing, consolidation or restructuring of AEPSC other than by reason of a Change In Control.ARTICLE III COMPENSATION UPON A CHANGE IN CONTROL FOLLOWED BY A TERMINATION 5 3.1 Upon a Qualifying Termination, the Executive shall be under no further obligation to perform services for AEPSC and shall be entitled to receive the following payments and benefits: (a) As soon as practicable following the Executive's date of termination, AEPSC shall make a lump sum cash payment to the Executive in an amount equal to the sum of(1) the Executive's Annual Salary through the date of termination to the extent not theretofore paid, (2) the product of (x)the current plan year's Target Annual Incentive and (y) a fraction, the numerator of which is the number of days in such calendar year through the date of termination, and the denominator of which is 365, except that annual incentive plans which do not have predetermined annual target awards for participants shall have their pro-rated incentive compensation award for the current plan year paid as soon as practicable, and (3) any accrued vacation pay, in each case the extent not theretofore paid and in full satisfaction of the rights of the Executive thereto;(b) Within sixty (60) days of the Executive's return of the signed release form, AEPSC shall make a lump sum cash payment to the Executive in an amount equal to three times the Executive's Annual Compensation; and (c) For purposes of the American Electric Power System Excess Benefit Plan, or any successor thereto, provided that the Executive is a participant thereunder, the Executive shall be credited with three (3) additional years of service; provided that if the Executive is older than age 62 as of the Executive's date of termination the additional years of service shall be limited to the difference between the Executive's age as of the date of termination and the date the Executive would attain age 65, and assuming that the Executive's compensation for the additional period of service would have been equal to the Executive's compensation in effect as of the Executive's date of termination. 3.2 The Executive shall be entitled to the continuing benefits as follows: (a) For the three (3) year period following the Executive's date of termination, the Executive and the Executive's family shall be provided with medical and dental insurance benefits as if the Executive's employment had not been terminated; provided, however, that if the Executive becomes reemployed with another employer and is eligible to receive medical or other welfare benefits under another employer-provided plan, the medical and other welfare benefits described herein shall be secondary to those provided under such other plan during such applicable period of eligibility. For purposes of determining eligibility (but not the time of commencement of benefits) of the Executive for retiree medical and dental insurance benefits under AEPSC's plans, practices, programs and policies, the Executive shall be considered to have remained employed during the 6 three (3) year period and to have retired on the last day of the three (3)year period;(b) AEPSC shall, at its sole expense as incurred, provide the Executive with outplacement services the scope and provider of which shall be selected by the Executive at the Executive's sole discretion (but at a cost to AEPSC of not more than $30,000) or, at the Executive's option, the use of comparable and accessible office space, office supplies and equipment and secretarial services for a period not to exceed one year, which in the aggregate are of comparable cost to the Corporation or AEPSC as the outplacement services;(c) To the extent any benefits described in this Article III, Section 3.2 cannot be provided pursuant to the appropriate plan or program maintained by AEPSC, AEPSC shall provide such benefits outside such plan or program at no additional cost (including without limitation tax cost) to the Executive.

3.3 Notwithstanding

the foregoing;(a) The severance payments and benefits provided under Sections 3.1 (b), 3. 1(c) and 3.2 hereof shall be conditioned upon the Executive executing a release at the time the Executive's employment is terminated, in the form established by the Corporation or by AEPSC, releasing the Corporation, AEPSC and their shareholders, partners, officers, directors, employees and agents from any and all claims and from any and all causes of action of kind or character, including but not limited to all claims or causes of action arising out of Executive's employment with the Corporation or AEPSC or the termination of such employment.(b) The severance payments and benefits provided under Sections 3.1 and 3.2 hereof shall be subject to, and conditioned upon, the waiver of any other cash severance payment or other benefits provided by AEPSC pursuant to any other severance agreement between AEPSC and the Executive. No amount shall be payable under this Agreement to, or on behalf of the Executive, if the Executive elects benefits under any other cash severance plan or program, or any other special pay arrangement with respect to the termination of the Executive's employment.(c) The Executive agrees that at all times following termination, the Executive will not, without the prior written consent of AEPSC or the Corporation, disclose to any person, firm or corporation any "confidential information," of AEPSC or the Corporation which is now known to the Executive or which hereafter may become known to the Executive as a result of the Executive's employment or association with AEPSC or the Corporation, unless such disclosure is required under the terms of a valid and effective 7 subpoena or order issued by a court or governmental body; provided, however, that the foregoing shall not apply to confidential information which becomes publicly disseminated by means other than a breach of this provision. It is recognized that damages in the event of breach of this Section 3.3(c) by the Executive would be difficult, if not impossible, to ascertain, and it is therefore agreed that AEPSC and the Corporation, in addition to and without limiting any other remedy or right that AEPSC or the Corporation may have, shall have the right to an injunction or other equitable relief in any court of competent jurisdiction, enjoining any such breach, and the Executive hereby waives any and all defenses the Executive may have on the ground of lack ofjurisdiction or competence of the court to grant such an injunction or other equitable relief. The existence of this right shall not preclude AEPSC or the Corporation from pursuing any other rights or remedies at law or in equity which AEPSC or the Corporation may have."Confidential information" shall mean any confidential, propriety and or trade secret information, including, but not limited to, concepts, ideas, information and materials relating to AEPSC or the Corporation, client records, client lists, economic and financial analysis, financial data, customer contracts, marketing plans, notes, memoranda, lists, books, correspondence, manuals, reports or research, whether developed by AEPSC or the Corporation or developed by the Executive acting alone or.jointly with AEPSC or the Corporation while the Executive was employed by AEPSC.3.4 Notwithstanding anything to the contrary in this Agreement, in the event that any payment or distribution by AEPSC to or for the benefit of the Executive, whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise (a "Payment"), would be subject to the excise tax imposed by Section 4999 of the Code or any interest or penalties with respect to such excise tax (such excise tax, together with any such interest or penalties, are hereinafter collectively referred to as the"Excise Tax"), AEPSC shall pay to the Executive an additional payment (a "Gross-up Payment") in an amount such that after payment by the Executive of all taxes (including any interest or penalties imposed with respect to such taxes), including any Excise Tax imposed on any Gross-up Payment, the Executive retains an amount of the Gross-up Payment equal to the Excise Tax imposed upon the Payments. AEPSC and the Executive shall make an initial determination as to whether a Gross-up Payment is required and the amount of any such Gross-up Payment. Executive shall notify AEPSC immediately in writing of any claim by the Internal Revenue Service which, if successful, would require AEPSC to make a Gross-up Payment (or a Gross-up Payment in excess of that, if any, initially determined by AEPSC and the Executive) within five days of the receipt of such claim. AEPSC shall notify the Executive in writing at least five days prior to the due date of any response required with respect to such claim, or such shorter time period following AEPSC's receipt of the notice, if it plans to contest the claim. If AEPSC decides to contest such claim, the Executive shall cooperate fully with AEPSC in such action;8 provided, however, AEPSC shall bear and pay directly or indirectly all costs and expenses (including additional interest and penalties) incurred in connection with such action and shall indemnify and hold the Executive harmless, on an after-tax basis, for any Excise Tax or income tax, including interest and penalties with respect thereto, imposed as a result of AEPSC's action. If, as a result of AEPSC's action with respect to a claim, the Executive receives'a refund of any amount paid by AEPSC with respect to such claim, the Executive shall promptly pay such refund to AEPSC. If AEPSC fails to timely notify the Executive whether it will contest such claim or AEPSC determines not to contest such claim, then AEPSC shall immediately pay to the Executive the portion of such claim, if any, which it has not previously paid to the Executive. 3.5 The obligations of AEPSC to pay the benefits described in Sections 3.1 and 3.2 shall be absolute and unconditional and shall not be affected by any circumstances, including, without limitation, any set-off, counterclaim, recoupment, defense or other right which AEPSC may have against the Executive. In no event shall the Executive be obligated to seek other employment or take any other action by way of mitigation of the amounts payable to the Executive under any of the provisions of this Agreement, nor shall the amount of any payment hereunder be reduced by any compensation earned by the Executive as a result of employment by another employer, except as specifically provided in Section 3.2.ARTICLE IV SUCCESSOR TO CORPORATION 4.1 This Agreement shall bind any successor of AEPSC or the Corporation, its assets or its businesses (whether direct or indirect, by purchase, merger, consolidation or otherwise) in the same manner and to the same extent that AEPSC or the Corporation would be obligated under this Agreement if no succession had taken place.4.2 In the case of any transaction in which a successor would not by the foregoing provision or by operation of law be bound by this Agreement, AEPSC and the Corporation shall require such successor expressly and unconditionally to assume and agree to perform AEPSC's and the Corporation's obligations under this Agreement, in the same manner and to the same extent that AEPSC and the Corporation would be required to perform if no such succession had taken place. The term "Corporation," as used in this Agreement, shall mean the Corporation as hereinbefore defined and any successor or assignee to the business assets which by reason hereof becomes bound by this Agreement. ARTICLE V MISCELLANEOUS 5.1 Any notices and all other communications provided for herein shall be in writing and shall be deemed to have been duly given when delivered or mailed, by N 9 certified or registered mail, return receipt requested, postage prepaid addressed to AEPSC at its principal office and to the Executive at the Executive's residence or at such other addresses as AEPSC or the Executive shall designate in writing.Section 5.2 No provision of this Agreement may be modified, waived or discharged except in a writing specifically referring to such provision and signed by either AEPSC or the Executive against whom enforcement of such modification, waiver or discharge is sought. No waiver by either AEPSC or the Executive of the breach of any condition or provision of this Agreement shall be deemed a waiver of any other condition or provision at the same or any other time.5.3 The validity, interpretation, construction and performance of this Agreement shall be governed by the laws of the State of Ohio.5.4 The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.5.5 This Agreement does not constitute a contract of employment or impose on the Executive, AEPSC or the Corporation any obligation to retain the Executive as an employee, to change the status of the Executive's employment, or to change AEPSC's policies regarding the termination of employment. 5.6 If the Executive institutes any legal action in seeking to obtain or enforce or is required to defend in any legal action the validity or enforceability of, any right or benefit provided by this Agreement, AEPSC will pay for all actual and reasonable legal fees and expenses incurred (as incurred) by the Executive, regardless of the outcome of such action; provided, however, that if such action instituted by the Executive is found by a court of competent jurisdiction to be frivolous, the Executive shall not be entitled to legal fees and expenses and shall be liable to AEPSC for amounts already paid for this purpose.5.7 If the Executive makes a written request alleging a right to receive benefits under this Agreement or alleging a right to receive an adjustment in benefits being paid under the Agreement, AEPSC shall treat it as a claim for benefit. All claims for benefit under the Agreement shall be sent to the Human Resources Department of AEPSC and must be received within 30 days after the Executive's termination of employment. If AEPSC determines that the Executive who has claimed a right to receive benefits, or different benefits, under the Agreement is not entitled to receive all or any part of the benefits claimed, it will inform the Executive in writing of its determination and the reasons therefore in terms calculated to be understood by the Executive. The notice will be sent within 90 days of the claim unless AEPSC determines additional time, not exceeding 90 days, is needed. The notice shall make specific reference to the pertinent Agreement provisions on which the denial is based, and describe any additional material or information, if any, necessary for the Executive to perfect the claim and the reason any such addition material or information is necessary. Such notice shall, in addition, inform 10 the Executive what procedure the Executive should follow to take advantage of the review procedures set forth below in the event the Executive desires to contest the denial of the claim. The Executive may within 90 days thereafter submit in writing to AEPSC a notice that the Executive contests the denial of the claim by AEPSC and desires a further review. AEPSC shall within 60 days thereafter review the claim and authorize the Executive to appear personally and review pertinent documents and submit issues and comments relating to the claim to the persons responsible for making the determination on behalf of AEPSC. AEPSC will render its final decision with specific reasons therefore in writing and will transmit it to the Executive within 60 days of the written request for review, unless AEPSC determines additional time, not exceeding 60 days, is needed, and so notifies the Executive. If AEPSC fails to respond to a claim filed in accordance with the foregoing within 60 days or any such extended period, AEPSC shall be deemed to have denied the claim.11 EXHIBIT 10(q)AMERICAN ELECTRIC POWER SYSTEM INCENTIVE COMPENSATION DEFERRAL PLAN (As Amended and Restated Effective January 1, 2003)ARTICLE I PURPOSE AND EFFECTIVE DATE 1.1 The American Electric Power System Incentive Compensation Deferral Plan (the "Plan") was established by American Electric Powver Service Corporation and such subsidiaries and affiliates designated by the Company for participation in the Plan ("AEP") to allow Eligible Employees to elect to defer receipt of all or a portion of their Incentive Compensation until after their termination of employment. 1.2 The effective date of the Plan, as amended and restated by this document, is January 1, 2003.ARTICLE II DEFINITIONS 2.1 "Account" means the separate memo account established and maintained by the Company or the recordkeeper employed by the Company to record Participant deferrals of Incentive Compensation and to record any related Investment Income on the Fund or Funds selected by the Participant or Former Participant. 2.2 "Base Compensation" means an employee's regular annual base salary or wage rate determined without regard to any salary or wage reductions made pursuant to sections 125 or 402(e)(3) of the Code or participant contributions pursuant to a pay reduction agreement under the American Electric Power System Supplemental Retirement Savings Plan, as amended.2.3 "Code" means the Internal Revenue Code of 1986 as amended from time to time.2.4 "Committee" means employees of the Company holding the following offices; Senior Vice President Human Resources, Executive Vice President -Shared Services, and Executive Vice President -Policy, Finance and Strategic Planning.2.5 "Company" means American Electric Power Service Corporation. 2.6 "Eligible Employee" means any employee of AEP who (as of January 1 of the Plan Year either (i) to which annual incentive compensation relates, or (ii) prior to the Plan Year in which long-term incentive compensation would become payable if a deferral election under this Plan were not in effect) (a) has Base Compensation of at least$100,000 or (b) is employed at exempt salary grade 26 or higher.2.7 "Former Participant" means a Participant whose employment with AEP has terminated or a Participant who is no longer an Eligible Employee, but whose Account has a balance greater than zero.2.8 "Fund" means the investment options made available to participants in the American Electric Power System Retirement Savings Plan, as revised from time to time, except as the Committee may specify otherwise. 2.9 "Incentive Compensation" means incentive compensation payable pursuant to the terms of annual and long-term incentive compensation plans approved by the Committee for inclusion in the Plan, provided that such incentive compensation shall be determined without regard to any salary or wage reductions made pursuant to sections 125 or 402(e)(3) of the Code or participant contributions pursuant to a pay reduction agreement under the American Electric Power System Supplemental Retirement Savings Plan, as amended. Incentive Compensation will not include Base Compensation, non-annual bonuses compensation (such as but not limited to project bonuses and sign-on bonuses), severance pay, or relocation payments.2.10 "Investment Income" means, with respect to Incentive Compensation deferred under this Plan, the earnings, gains and losses that would be attributable to the investment of such deferrals in a Fund or Funds.2.11 "Participant" means an Eligible Employee who elects to defer part or all of his or her Incentive Compensation. 2.12 "Plan Year" means the twelve-month period commencing each January 1 and ending the following December 31.2.13 "Retirement" means a Participant or Former Participant's termination of employment from AEP and its subsidiaries and affiliates after attaining age 55 and the completion of five years of service with AEP.ARTICLE III ADMINISTRATION 3.1 The Committee shall have full discretionary power and authority (i) to administer and interpret the terms and conditions of the Plan; (ii) to establish reasonable procedures with which Participants, Former Participant and beneficiaries must comply to 2 exercise any right or privilege established hereunder; and (iii) to be permitted to delegate its responsibilities or duties hereunder to any person or entity. The rights and duties of the Participants and all other persons and entities claiming an interest under the Plan shall be subject to, and bound by, actions taken by or in connection with the exercise of the powers and authority granted under this Article.3.2 The Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan.3.3 The Company shall maintain, or cause to be maintained, records showing the individual balances in each Participant's Account. Statements setting forth the value of the amount credited to the Participant's Account as of a particular date shall be made available to each Participant no less often than quarterly. The maintenance of the Account records and the distribution of statements may be delegated to a recordkeeper by either the Company or the Committee. ARTICLE IV PARTICIPATION 4.1 An Eligible Employee shall become a Participant by making a deferral election on a form prescribed by the Company to defer part or all of the Eligible Employee's Incentive Compensation attributable to the Plan Year (or non-annual long-term incentive compensation pursuant to a plan during the Plan Year in which the Eligible Employee has become a participant) indicated on the election form, but which would not become payable to such Eligible Employee until after the end of such Plan Year.ARTICLE V DEFERRALS 5.1 A Participant shall make a separate Incentive Compensation deferral election for each Plan Year. If a deferral election for a Plan Year is not made within the time period prescribed by the Company, no portion of the Eligible Employee's Incentive Compensation for the Plan Year shall be deferred.5.2 All deferred Incentive Compensation shall be paid in accordance with the distribution option selected by the Participant in accordance with the terms of Article VII.3 ARTICLE VI INVESTMENT OF DEFERRED AMOUNTS 6.1 All deferred Incentive Compensation shall be credited to the Participant's Account. Amounts credited to the Participant's Account shall be further credited with earnings as if invested in the Funds selected by the Participant. To the extent the Participant fails to select Funds for the investment of Contributions under the Plan, the Participant shall be deemed to have selected the Managed Income Fund option. The Participant may change the selected Funds by providing notification in accordance with the Plan's procedures. Any change in the Funds selected by the Participant shall be implemented in accordance with the Plan's procedures. 6.2 A Participant may elect to transfer all or a portion of the amounts credited to his Account from any Fund or Funds to any other Fund or Funds by providing notification in accordance with the Plan's procedures. Such transfers between Funds may be made in any whole percentage or dollar amounts and shall be implemented in accordance with the Plan's procedures. 6.3 The amount credited to each Participant's Account shall be determined daily based upon the fair market value of the Fund or Funds to which that Account is allocated. The fair market value calculation for a Participant's Account shall be made after all deferrals, distributions, Investment Income and transfers for the day are recorded. A Participant's Account, as adjusted from time to time, shall continue to be credited with Investment Income until the balance of the Account is zero and the Committee anticipates no additional contributions from such Participant. 6.4 The Plan is an unfunded non-qualified deferred compensation plan and therefore the deferrals credited to a Participant's Account and the investment of those deferrals in the Fund or Funds selected by the Participant are memo accounts that represent general, unsecured liabilities of the Participant's AEP employer payable exclusively out of the general assets of such AEP employer.ARTICLE VII DISTRIBUTIONS 7.1 Upon a Participant's or Former Participant's termination of employment with AEP and its subsidiaries and affiliates for any reason other than Retirement, the Company shall cause the Participant or the Former Participant to be paid the full amount credited to the Participant's or Former Participant's Account. The payment shall be made no later the 9oth day following the Participant's or Former Participant's termination of employment. 4 7.2 (a) Upon a Participant's or Former Participant's termination of employment due to Retirement, all amounts that are credited to the Participant's Account shall be distributed to the Participant or Former Participant in one of the following optional forms as selected by the Participant: (1) A single lump-sum payment, or (2) In annual installment payments over not less than two nor more than ten years.(b) Payment in the form of distribution selected by the Participant or Former Participant pursuant to section 7.2(a) shall commence within 60 days after the date elected by the Participant or Former Participant on an effective distribution election form;provided that distributions commencing upon the termination of a Participant's or Former Participant's employment shall begin no later than the end of the calendar quarter following the end of the calendar quarter of the Participant's or Former Participant's termination of employment. Such date elected by the Participant or Former Participant shall be either (1) the date of the Participant's Retirement (provided, however, if the Participant was an executive officer of the Company at the time of his or her termination of employment, the earliest commencement date shall be the January 1 of the year following the executive officer's Retirement) or (2) the first, second, third, fourth or fifth anniversary of the Participant's Retirement, as selected by the Participant or Former Participant.(c) Each Participant or Former Participant shall select the form of distribution [as set forth in section 7.2(a)] and benefit commencement date [as set forth in section 7.2(b)]when the Participant first elects to participate in the Plan. The Participant or Former Participant may amend his or her distribution election at any time prior to the ninetieth (90t) day preceding the Participant's termination of employment by submitting a distribution election form in accordance with the Plan's procedures. If the Participant has not submitted an effective distribution election at the time of his termination of employment, his distribution shall be in the form of a single lump sum payment made within 60 days after the Participant's termination of employment. Notwithstanding the preceding sentence, distributions to a Participant who is an executive officer of the Company, but who has not submitted an effective distribution election at the time of his termination of employment, shall commence in January of the year following the Participant's or Former Participant's Retirement. 7.3 If a Participant's or Former Participant's Account is $25,000 or less on the date that the distribution of the Participant's Account is to commence in accordance with section 7.2, the full value of the Account shall be distributed as of such commencement date in a single, lump sum distribution regardless of the form elected by such Participant or Former Participant pursuant to section 7.2(a).7.4 If an annual distribution is selected, the amount to be distributed in any one-year shall be determined by dividing the Participant's or Former Participant's Account by 5 the number of years remaining in the elected distribution period. The Participant or Former Participant electing annual distributions shall have the right to direct changes in the investment of the Account in a Fund or Funds in accordance with Article VI until the amount credited to the Account is reduced to zero.7.5 Notwithstanding any other provision of this Plan a Participant or Former Participant shall be entitled to receive, upon a written request to the Committee that is effective between April I and December 31 of any Plan Year, a lump sum distribution from his or her Account of an amount equal to or greater than 25% of the Participant's Account as of the date of the request. The date of the request shall be the date the Committee or the Committee's representative receives the request. The lump sum amount to be paid to the Participant shall be subject to a 10% early withdrawal penalty, which penalty shall reduce the amount to be distributed to the Participant or Former Participant. The Participant or Former Participant shall forfeit the amount of the 10%withdrawal penalty. The lump sum amount shall be paid within 60 days after the Committee receives the withdrawal request. Any Participant or Former Participant who elects to receive a benefit under this section shall not be eligible to have any Incentive Compensation attributable to that Plan Year and the next succeeding two Plan Years deferred into his or her Account pursuant to this Plan, and such Participant shall not be entitled to request any additional withdrawals under this section prior to the Participant's termination of employment. ARTICLE VIII BENEFICIARIES 8.1 Each Participant or Former Participant may designate a beneficiary or beneficiaries Who shall receive the balance of the Participant's Account if the Participant dies prior to the complete distribution of the Participant's Account. Any designation, or change or rescission of a beneficiary designation shall be made by the Participant's completion, signature and submission to the Committee of the appropriate beneficiary form prescribed by the Committee. A beneficiary form shall take effect as of the date the form is signed provided that the Committee receives it before taking any action or making any payment to another beneficiary named in accordance with this Plan and any procedures implemented by the Committee. If any payment is made or other action is taken before a beneficiary form is received by the Committee, any changes made on a form received thereafter will not be given any effect. If a Participant fails to designate a beneficiary, or if all beneficiaries named by the Participant do not survive the Participant, the Participant's Account will be paid to the Participant's estate. Unless clearly specified otherwise in an applicable court order presented to the Committee prior to the Participant's death, the designation of a Participant's spouse as a beneficiary shall be considered automatically revoked as to that spouse upon the legal termination of the Participant's marriage to that spouse.6

8.2 Distribution

to a Participant's or Former Participant's beneficiary shall be in the form of a single lump-sum payment within 60 days after the Committee makes a final determination as to the beneficiary or beneficiaries entitled to receive such distribution. ARTICLE IX CLAIMS PROCEDURE Section 9.1 The following procedures shall apply with respect to claims for benefits under the Plan.(a) Any Participant or Former Participant or beneficiary who believes he or she is entitled to receive a distribution under the Plan which he or she did not receive or that amounts credited to his or her Account are inaccurate, may file a written claim signed by the Participant, beneficiary or authorized representative with the Company's Director -Compensation and Executive Benefits, specifying the basis for the claim. The Director-Compensation and Executive Benefits shall provide a claimant with written or electronic notification of its determination on the claim within ninety days after such claim was filed; provided, however, if the Director -Compensation and Executive Benefits determines special circumstances require an extension of time for processing the claim, the claimant shall receive within the initial ninety-day period a written notice of the extension for a period of up to ninety days from the end of the initial ninety day period. The extension notice shall indicate the special circumstances requiring the extension and the date by which the Plan expects to render the benefit determination.(b) If the Director -Compensation and Executive Benefits renders an adverse benefit determination under Section 9. 1(a), the notification to the claimant shall set forth, in a manner calculated to be understood by the claimant: (1) The specific reasons for the denial of the claim;(2) Specific reference to the provisions of the Plan upon which the denial of the claim was based;(3) A description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary, and (4) An explanation of the review procedure specified in Section 9.2, and the time limits applicable to such procedures, including a statement of the claimant's right to bring a civil action under section 502(a) of the Employee Retirement Income Security Act of 1974, as amended, following an adverse benefit determination on review.7 Section 9.2 The following procedures shall apply with respect to the review on appeal of an adverse determination on a claim for benefits under the Plan.(a) Within sixty days after the receipt by the claimant of an adverse benefit determination, the claimant may appeal such denial by filing with the Committee a written request for a review of the claim. If such an appeal is filed within the sixty day period, the Committee, or a duly appointed representative of the Committee, shall conduct a full and fair review of such claim' that takes into account all comments, documents, records and other information submitted by the claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The claimant shall be entitled to submit written comments, documents, records and other information relating to the claim for benefits and shall be provided, upon request and free of charge, reasonable access to, and copies of all documents, records and other information relevant to the claimant's claim for benefits. If the claimant requests a hearing on the claim and the Committee concludes such a hearing is advisable and schedules such a hearing, the claimant shall have the opportunity to present the claimant's case in person or by an authorized representative at such hearing.(b) The claimant shall be notified of the Committee's benefit determination on review within sixty days after receipt of the claimant's request for review, unless the Committee determines that special circumstances require an extension of time for processing the review. If the Committee determines that such an extension is required, written notice of the extension shall be furnished to the claimant within the initial sixty-day period. Any such extension shall not exceed a period of sixty days from the end of the initial period. The extension notice shall indicate the special circumstances requiring the extension and the date by which the Committee expects to render the benefit determination.(c) The Committee shall provide a claimant with written or electronic notification of the Plan's benefit determination on review. The determination of the Committee shall be final and binding on all interested parties. Any adverse benefit determination on review shall set forth, in a manner calculated to be understood by the claimant: (1) The specific reason(s) for the adverse determination; (2) Reference to the specific provisions of the Plan on which the determination was based;(3) A statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claimant's claim for benefits; and (4) A statement of the claimant's right to bring an action under Section 502(a)of ERISA.8 ARTICLE X MISCELLANEOUS PROVISIONS 10.1 Each Participant agrees that as a condition of participation in the Plan, the Company may withhold applicable federal, state and local taxes, Social Security taxes and Medicare taxes from any distribution hereunder to the extent that such taxes are then payable.10.2 In the event the Committee, in its sole discretion, shall find that a Participant, Former Participant or beneficiary is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant or the beneficiary be paid to the duly appointed personal representative of the Participant or beneficiary, and any such payment so made shall be a complete discharge of the liabilities of the Plan and the Company with respect to such Participant or beneficiary. 10.3 The Company intends to continue the Plan indefinitely but reserves the right, in its sole discretion, to modify the Plan from time to time, or to terminate the Plan entirely or to direct the permanent discontinuance or temporary suspension of deferral contributions under the Plan; provided that no such modification, termination, discontinuance or suspension shall reduce the benefits accrued for the benefit of any Participant, Former Participant or beneficiary under the Plan as of the date of such modification, ternination, discontinuance or suspension. 10.4 Nothing in the Plan shall interfere with or limit in any way the right of AEP to terminate any Participant's employment at any time, or confer upon a Participant any right to continue in the employ of AEP.10.5 The Plan shall be construed and administered according to the laws of the State of Ohio.American Electric Power Service Corporation has caused this amendment and restatement of the American Electric Power System Incentive Compensation Deferral Plan to be signed as of this 8th day of April, 2003.AMERICAN ELECTRIC POWER SERVICE CORPORATION By: /s/Melinda S. Ackerman Melinda S. Ackerman, Senior Vice President, Human Resources 9 EXHIBIT 10(u)AMERICAN ELECTRIC POWER SYSTEM 2000 LONG-TERM INCENTIVE PLAN, AS AMENDED Table of Contents Section Page 1. Purpose of the Plan .................................. A-I 2. Definitions ........................................................... .A-I 3. Shares of Common Stock Subject to the Plan ..... .A-3 4. Administration of the Plan .................................. A4 5. Eligibility and Awards .................................. A-5 6. Stock Options .................................. A-5 7. Stock Appreciation Rights .................................. A-6 8. Restricted Stock .................................. A-6 9. Performance Awards .................................. A-7 10. Phantom Stock .................................. A-8 11. Dividend Equivalents .................................. A-8 12. Change in Control ................... ............... A-9 13. Award Agreements .................................. A-9 14. General Provisions .................... .............. A-10 15. Effective Date, Termination and Amendment ..... .A-Il American Electric Power System 2000 Long-Term Incentive Plan 1. Purpose of the Plan The purpose of the American Electric Power System 2000 Long-Term Incentive Plan is to promote the interests of AEP and its shareholders by strengthening AEPs ability to attract, motivate and retain employees and directors of AEP and its Subsidiaries upon whose judgment, initiative and efforts the financial success and growth of the business of AEP largely depend, to align further the interests of AEPs management with the shareholders, and to provide an additional incentive for employees and directors through stock ownership and other rights that promote and recognize the financial success and growth of AEP.2. Definitions Wherever the following capitalized terms are used in this Plan they shall have the meanings specified below: (a) "AEP" means American Electric Power Company, Inc., a New York corporation, and any successor thereto.(b) "AEP-CSW Merger" means the consummation of the transactions contemplated in the Agreement and Plan of Merger by and among American Electric Power, Inc., Augusta Acquisition Corporation and Central and South WMest Corporation dated as of December 21, 1997, as amended.(c) "Award" means an award of an Option, Restricted Stock, Stock Appreciation Right, Performance

Award, Phantom Stock or Dividend Equivalent granted under the Plan.(d) "Award Agreement" means an agreement entered into between AEP and a Participant setting forth the terms and conditions of an Award granted to a Participant.(e) "Board" means the Board of Directors of AEP.(f) "Change in Control" shall have the meaning specified in Section 12 hereof.(g) "Code" means the Internal Revenue Code of 1986, as amended.(h) "Committee" means the Human Resources Committee of the Board, or such other committee or subcommittee of the Board appointed by the Board to administer the Plan from time to time.(i) "Common Stock" means the common stock of AEP, $6.50 par value.') "Date of Grant" means the date on which the Committee makes an Award under the Plan, or such later date as the Committee may specify that the Award becomes effective.(k) "Effective Date" means the Effective Date of this Plan, as defined in Section 15.1 hereof.(I) "Dividend Equivalent" means an Award under Section II hereof entitling the Participant to receive payments with respect to dividends declared on the Common Stock.(m) "Eligible Person" means any person who is an Employee or an Independent Director.(n) "Employee" means any person who is an employee of AEP or any Subsidiary; provided, however, that with respect to Incentive Stock Options, "Employee" means any person who is considered an employee of AEP or any Subsidiary for purposes of Section 424 of the Code.(o) "Fair Market Value" means, as of any applicable date, the closing price per share of the Common Stock as quoted in the New York Stock Exchange-Composite Transactions listing in The Wall Street Journal (or such other reliable publication as the Committee, in its discretion, may determine to rely upon) for the date as of which Fair Market Value is to be determined.

If there are no sales on such date, then Fair Market Value shall be the closing price per share of the Common Stock as so quoted on the nearest date before the date as of which Fair Market Value is to be determined on which there are sales. If the Common Stock is not listed on the New York Stock Exchange on the date as of which Fair Market Value is to be determined, the Committee shall determine in good faith the Fair Market Value in whatever manner it considers appropriate. Fair Market Value shall be determined without regard to any restriction other than a restriction which, by its terms, will never lapse.(p) "Independent Director" means a member of the Board who is not an Employee.(q) "Incentive Stock Option" means an option to purchase Common Stock that is intended to qualify as an incentive stock option under Section 422 of the Code, or any successor provision thereto.(r) "Nonqualified Stock Option" means an option to purchase Common Stock that is not an Incentive Stock Option.(s) "Option" means an Incentive Stock Option or a Nonqualified Stock Option granted under Section 6 hereof.(t) "Participant" means any Eligible Person who holds an outstanding Award under the Plan.2 (u) "Phantom Stock" means an Award under Section 10 hereof entitling a Participant to a payment based on a measure of value expressed as a share of Common Stock. No stock certificates shall be issued with respect to such Phantom Stock Units, but AEP shall maintain a bookkeeping account in the name of the Participant to which the Phantom Stock Units shall relate.(v) "Plan" means the American Electric Power System 2000 Long-Term Incentive Plan as set forth herein, as it may be amended from time to time.(w) "Performance Award" means an Award made under Section 9 hereof entitling a Participant to a payment based on the Fair Market Value of Common Stock (a "Performance Share") or based on specified dollar units (a"Performance Unit") at the end of a performance period if certain conditions established by the Committee are satisfied.(x) "Restricted Stock" means an Award under Section 8 hereof entitling a Participant to shares of Common Stock that are nontransferable and subject to forfeiture until specific conditions established by the Committee are satisfied.(y) "Section 162(m)" means Section 162(m) of the Code and the Treasury Regulations thereunder.(z) "Section 162(m) Participant" means any Participant who, in the sole judgment of the Committee, could be treated as a "covered employee" under Section 162(m) at the time income may be recognized by such Participant in connection with an Award that is intended to qualify for exemption under Section 162(m).(aa) "Stock Appreciation Right" or "SAR" means an Award under Section 7 hereof entitling a Participant to receive an amount, representing the difference between the base price per share of the right and the Fair Market Value of a share of Common Stock on the date of exercise.(bb) "Subsidiary" means any corporation (other than AEP) in an unbroken chain of corporations beginning with AEP if, at the time of granting an Award, each of the corporations, other than the last corporation in the unbroken chain, owns stock possessing 50 percent or more of the total combined voting power of all classes of stock in one of the other corporations in such chain.3. Shares of Common Stock Subject to the Plan 3.1. Calculation ofNumber of Shares Available. Subject to the following provisions of this Section 3, the aggregate number of shares of Common Stock that may be issued pursuant to all Awards under the Plan is 15,700,000 shares of Common Stock.If any share of Common Stock that is the subject of an Award is not issued and ceases to be issuable for any reason, or is forfeited, cancelled or returned to AEP for failure to satisfy vesting requirements or upon the occurrence of other forfeiture events, such share of Common Stock will no longer be charged against the foregoing maximum share limitations and may again be made subject to Awards under the Plan pursuant to such limitations. 3.2. AccountingforAivards. For purposes of this Section 3, if an Award is denominated in shares of Common Stock, the number of shares covered by such Award, or to which such Award relates, shall be counted on the Date of Grant of such Award against the aggregate number of shares available for granting Awards under the Plan;provided, however, that Awards that operate in tandem.with (whether granted simultaneously with or at a different time from) other Awards may be counted or not counted under procedures adopted by the Committee in order to avoid double counting.3.3. Source of Shares of Common StockDeliverable UndervAwards. The shares of Common Stock to be delivered under the Plan may be authorized but unissued shares, reacquired shares, shares acquired on the open 3 market specifically for distribution under the Plan, or any combination thereof.3.4. Adjustments. If there shall occur any recapitalization, reclassification, stock dividend, stock split, reverse stock split or other distribution with respect to the shares of Common Stock, or any similar corporate transaction or event in respect of the Common Stock such as the AEP-CSW Merger, then the Committee shall, in the manner and to the extent that it deems appropriate and equitable to the Participants and consistent with the terms of this Plan, cause a proportionate adjustment to be made in (a) the maximum numbers and kind of shares provided in Section 3.1 hereof, (b) the maximum numbers and kind of shares set forth in Sections 6.1, 7.1, 8.2 and 9.4 hereof, (c) the number and kind of shares of Common Stock, share units, or other rights subject to the then-outstanding Awards, (d) the price for each share or unit or other right subject to then outstanding Awards without change in the aggregate purchase price or value as to which such Awards remain exercisable or subject to restrictions, (e) the performance targets or goals appropriate to any outstanding Performance Awards (subject to such limitations as appropriate for Awards intended to qualify for exemption under Section 162(m)) or (f) any other terms of an Award that are affected by the event. Notwithstanding the foregoing, in the case of Incentive Stock Options, any such adjustments shall be made in a manner consistent with the requirements of Section 424(a) of the Code.4. Administration of the Plan 4.1. Committee Members. Except as provided in Section 4.4 hereof, the Committee will administer the Plan.The Committee may exercise such powers and authority as may be necessary or appropriate for the Committee to carry out its functions as described in the Plan. No member of the Committee will be liable for any action or determination made in good faith by the Committee with respect to the Plan or any Award under it.4.2. DiscretionaryAuthority. Subject to the express limitations of the Plan, the Committee has authority in its discretion to determine the Eligible Persons to whom, and the time or times at which, Awards may be granted, the number of shares, units or other rights subject to each Award, the exercise, base or purchase price of an Award (if any), the time or times at which an Award will become vested, exercisable or payable, the performance criteria, performance goals and other conditions of an Award, and the duration of the Award. The Committee also has discretionary authority to interpret the Plan, to make all factual determinations under the Plan, and to determine the terms and provisions of the respective Award Agreements and to make all other determinations necessary or advisable for Plan administration. The Committee has authority to prescribe, amend, and rescind rules and regulations relating to the Plan. All interpretations, determinations, and actions by the Committee will be final, conclusive, and binding upon all parties.4.3. Changes to Awards. The Committee shall have the authority to effect, at any time and from time to time, with the consent of the affected Participants, (a) the cancellation of any or all outstanding Awards and the grant in substitution therefor of new Awards covering the same or different numbers of shares of Common Stock and having an exercise or base price which may be the same as or different than the exercise or base price of the cancelled Awards or (b) the amendment of the terms of any and all outstanding Awards; provided, however, that the Committee shall not have the authority to reduce the exercise or base price of an Award by amendment or cancellation and substitution of an existing Award without the approval of AEP's shareholders. The Committee may in its discretion accelerate the vesting or exercisability of an Award at any time or on the basis of any specified event.4.4. Delegation ofAuthority. As permitted by law, the Committee may delegate its authority as identified hereunder; provided, however, that the Committee may not delegate certain of its responsibilities hereunder if such delegation may jeopardize compliance with the "outside directors" provision of Section 162(m).4.5 Awards to Independent Directors. The Independent Directors of the Board shall approve an Award to an Independent Director under the Plan. With respect to Awards to Independent Directors, all rights, powers and authorities vested in the Committee under the Plan shall instead be exercised by the Independent Directors of the Board, and all provisions of the Plan relating to the Committee shall be interpreted in a manner consistent with the 4 foregoing by treating any such reference as a reference to the Independent Directors of the Board for such purpose.5. Eligibility and Awards All Eligible Persons are eligible to be designated by the Committee to receive an Award under the Plan. The Committee has authority, in its sole discretion, to determine and designate from time to time those Eligible Persons who are to be granted Awards, the types of Awards to be granted and the number of shares or units subject to the Awards that are granted under the Plan. Each Award will be evidenced by an Award Agreement as described in Section 13 hereof between AEP and the Participant that shall include the terms and conditions consistent with the Plan as the Committee may determine.

6. Stock Options 6.1. Grant of Option An Option may be granted to any Eligible Person selected by the Committee; provided, however, that only Employees shall be eligible for Awards of Incentive Stock Options. Each Option shall be designated, at the discretion of the Committee, as an Incentive Stock Option or a Nonqualified Stock Option. The maximum number of shares of Common Stock that may be granted under Options to any one Participant during any three calendar year period shall be limited to 1,650,000 shares (subject to adjustment as provided in Section 3.4 hereof).6.2. Exercise Price. The exercise price of the Option shall be determined by the Committee; provided, however, that the exercise price per share of an Option shall not be less than 100 percent of the Fair Market Value per share of the Common Stock on the Date of Grant. Notwithstanding the foregoing; in the event that options are assumed in a transaction which would satisfy the conditions of Section 424 of the Code (whether or not such section would otherwise be applicable), the Committee may grant Options with an exercise price per share less than 100 percent of the Fair Market Value on the date of grant.6.3. Vesting; Term of Option The Committee, in its sole discretion, shall prescribe in the Award Agreement the time or times at which, or the conditions upon which, an Option or portion thereof shall become vested and exercisable, and may accelerate the exercisability of any Option at any time.6.4. Option Exercise; Withholding.

Subject to such terms and conditions as shall be specified in an Award Agreement, an Option may be exercised in whole or in part at any time during the term thereof by written notice to AEP together with payment of the aggregate exercise price therefor. Payment of the exercise price shall be made (a)in cash or by cash equivalent, (b) at the discretion of the Committee, in shares of Common Stock acceptable to the Committee, valued at the Fair Market Value of such shares on the date of exercise, (c) at the discretion of the Committee, by a delivery of a notice that the Participant has placed a market sell order (or similar instruction) with a third party with respect to shares of Common Stock then issuable upon exercise of the Option, and that the third party has been directed to pay a sufficient portion of the net proceeds of the sale to AEP in satisfaction of the Option exercise price or (d) at the discretion of the Committee, by a combination of the methods described above or such other method as may be approved by the Committee. In addition to and at the time of payment of the exercise price, the Participant shall pay to AEP the full amount of any and all applicable income tax and employment tax amounts required to be withheld in connection with such exercise, payable under one or more of the methods described above for the payment of the exercise price of the Options as may be approved by the Committee.

6.5. Additional

Rulesfor Incentive Stock Options. The terms of any Incentive Stock Option granted under the Plan shall comply in all respects with the provisions of Section 422 of the Code, or any successor provision thereto, and any regulations promulgated thereunder. 5

7. Stock Appreciation Rights 7.1. Grant ofSARs. A Stock Appreciation Right granted to a Participant is an Award in the form of a right to receive, upon surrender of the right, but without other payment, an amount based on appreciation in the Fair Market Value of the Common Stock over a base price established for the Award, exercisable at such time or times and upon conditions as may be approved by the Committee.

The maximum number of shares of Common Stock that may be subject to SARs granted to any one Participant during any three calendar year period shall be limited to 1,650,000 shares (subject to adjustment as provided in Section 3.4 hereof).7.2. Tandem SARs. A Stock Appreciation Right may be granted in connection with an Option, either at the time of grant or at any time thereafter during the term of the Option. An SAR granted in connection with an Option will entitle the holder, upon exercise, to surrender such Option or any portion thereof to the extent unexercised, with respect to the number of shares as to which such SAR is exercised, and to receive payment of an amount computed as described in Section 7.4 hereof. Such Option will, to the extent and when surrendered, cease to be exercisable. An SAR granted in connection with an Option hereunder will have a base price per share equal to the per share exercise price of the Option, will be exercisable at such time or times, and only to the extent, that a related Option is exercisable, and will expire no later than the related Option expires.7.3. Freestanding SARs. A Stock Appreciation Right may be granted without relationship to an Option and, in such case, will be exercisable as determined by the Committee. The base price of an SAR granted without relationship to an Option shall be determined by the Committee in its sole discretion; provided, however, that the base price per share of a freestanding SAR shall not be less than 100 percent of the Fair Market Value of the Common Stock on the Date of Grant.7.4. Payment ofSARs. An SAR will entitle the holder, upon exercise of the SAR, to receive payment of an amount determined by multiplying: (i) the excess of the Fair Market Value of a share of Common Stock on the date of exercise of the SAR over the base price of such SAR, by (ii) the number of shares as to which such SAR will have been exercised. Payment of the amount determined under the foregoing may be made, in the discretion of the Committee, in cash, in Restricted Stock or shares of unrestricted Common Stock (both valued at their Fair Market Value on the date of exercise), or a combination thereof.8. Restricted Stock 8.1. Grants ofRestricted Stock An Avard of Restricted Stock to a Participant represents shares of Common Stock that are issued subject to such restrictions on transfer and other incidents of ownership and such forfeiture conditions as the Committee may determine. The Committee may, in connection with an Award of Restricted Stock, require the payment of a specified purchase price. The Committee may grant and designate Awards of Restricted Stock that are intended to qualify for exemption under Section 162(m), as well as Awards of Restricted Stock that are not intended to so qualify.8.2. Vesting Requirements. The restrictions imposed on an Award of Restricted Stock shall lapse in accordance with the vesting requirements specified by the Committee in the Award Agreement. Such vesting requirements may be based on the continued employment of the Participant with AEP or its Subsidiaries for a specified time period or periods, provided that any such restriction shall not be scheduled to lapse in its entirety earlier than the first anniversary of the Date of Grant. Such vesting requirements may also be based on the attainment of specified business goals or measures established by the Committee in its sole discretion. In the case of any Award of Restricted Stock that is intended to qualify for exemption under Section 162(m), the vesting requirements shall be limited to the performance criteria identified in Section 9.3 below, and the terms of the Award shall othervise comply with the Section 162(m) requirements described in Section 9.4 hereof; provided, however, that the maximum number of shares of Common Stock that may be subject to an Award of Restricted Stock granted to a Section 162(m) Participant during any one calendar year shall be separately limited to 330,000 shares (subject to adjustment as provided in Section 3.4 hereof).6 8.3. Restrictions. Shares of Restricted Stock may not be transferred, assigned or subject to any encumbrance, pledge or charge until all applicable restrictions are removed or expire or unless otherwise allowed by the Committee. The Committee may require the Participant to enter into an escrow agreement providing that the certificates representing Restricted Stock granted or sold pursuant to the Plan will remain in the physical custody of an escrow holder until all restrictions are removed or expire. Failure to satisfy any applicable restrictions shall result in the subject shares of Restricted Stock being forfeited and returned to AEP, with any purchase price paid by the Participant to be refunded, unless otherwise provided by the Committee. The Committee may require that certificates representing Restricted Stock granted under the Plan bear a legend making appropriate reference to the restrictions imposed.8.4. Rights as Shareholder. Subject to the foregoing provisions of this Section 8 and the applicable Award Agreement, the Participant will have all rights of a shareholder with respect to shares of Restricted Stock granted to the Participant, including the right to vote the shares and receive all dividends and other distributions paid or made with respect thereto, unless the Committee determines otherwise at the time the Restricted Stock is granted, as set forth in the Award Agreement.

8.5. Section

83(b) Election. The Committee may provide in an Award Agreement that the Award of Restricted Stock is conditioned upon the Participant refraining from making an election with respect to the Award under Section 83(b) of the Code. Irrespective of whether an Award is so conditioned, if a Participant makes an election pursuant to Section 83(b) of the Code with respect to an Award of Restricted Stock, the Participant shall be required to promptly file a copy of such election with AEP.9. Performance Awards 9.1. Grant of PerformancevAwards. The Committee may grant Performance Awards under the Plan, which shall be represented by units denominated on the Date of Grant either in shares of Common Stock (Performance Shares) or in specified dollar amounts (Performance Units). The Committee may grant and designate Performance Awards that are intended to qualify for exemption under Section 162(m), as well as Performance Awards that are not intended to so qualify. At the time a Performance Award is granted, the Committee shall determine, in its sole discretion, one or more performance periods and performance goals to be achieved during the applicable performance periods, as well as such other restrictions and conditions as the Committee deems appropriate. In the case of Performance Units, the Committee shall also determine a target unit value or a range of unit values for each Award. The performance goals applicable to a Performance Award grant may be subject to such later revisions as the Committee shall deem appropriate to reflect significant unforeseen events such as changes in law, accounting practices or unusual or nonrecurring items or occurrences. Any such adjustments shall be subject to such limitations as the Committee deems appropriate in the case of a Performance Award granted to a Section 162(m) Participant that is intended to qualify for exemption under Section 162(m).9.2. Payment of Performance Awards. At the end of the performance period, the Committee shall determine the extent to which performance goals have been attained or a degree of achievement between minimum and maximum levels in order to establish the level of payment to be made, if any. The Committee shall determine if payment is to be made in cash, Restricted Stock, shares of unrestricted Common Stock, Options or Phantom Stock, or a combination thereof. For any cash conversion to or from Performance Shares or Units, Phantom Stock units or shares of Common Stock, payment shall be calculated on the basis of the average of the Fair Market Value of the Common Stock for the last 20 trading days prior to the payment date.9.3. Performance Criteria The performance criteria upon which the payment or vesting of a Performance Award intended to qualify for exemption under Section 162(m) may be based shall be limited to the following business measures, which may be applied with respect to AEP, any Subsidiary or any business unit, and which may be measured on an absolute or relative-to-peer-group basis: (a) financial, such as total shareholder return and earnings per share, (b) operational, such as power generation efficiency, productivity and safety, and (c) strategic, 7 such as entering new markets and product line introductions. In any event, the Committee may, at its discretion, reduce the number of Performance Awards earned by any Participant for a performance period. In the case of Performance Awards that are not intended to qualify for exemption under Section 162(m), the Committee shall designate performance criteria from among the foregoing or such other business criteria as it shall determine in its sole discretion.

9.4. Section

162(m) Requirements. In the case of a Performance Award granted to a Section 162(m)Participant that is intended to comply with the requirements for exemption under Section 162(m), the Committee shall make all determinations necessary to establish a Performance Award within 90 days of the beginning of the performance period (or such other time period required under Section 162(m)), including, without limitation, the designation of the Section 162(m) Participants to whom Performance Awards are made, the performance criteria or criterion applicable to the Award and the performance goals that relate to such criteria, and the dollar amounts or number of shares of Common Stock or Phantom Stock units payable upon achieving the applicable performance goals. As and to the extent required by Section 162(m), the terms of a Performance Award granted to a Section 162(m) Participant must state, in terms of an objective formula or standard, the method of computing the amount of compensation payable to the Section 162(m) Participant, and must preclude discretion to increase the amount of compensation payable that would otherwise be due under the terms of the Award. The maximum amount of compensation that may be payable to a Section 162(m) Participant during any one calendar year under a Performance Unit Award shall be $8,260,000. The maximum number of Performance Share units that may be earned by a Section 162(m) Participant during any one calendar year shall be 330,000 (subject to adjustment as provided in Section 3.4 hereof).10. Phantom Stock 10.1. Grant of Phantom Stock Phantom Stock is an Award to a Participant of a number of hypothetical share units with respect to shares of Common Stock, with an initial value based on the average of the Fair Market Value of the Common Stock for the last 20 trading days prior to the Date of Grant. Phantom Stock shall be subject to such restrictions and conditions as the Committee shall determine. Sections 8.1 and 8.2 shall apply to Awards of Phantom Stock units in similar manner as they apply to shares of Restricted Stock, as interpreted by the Committee, with the limitation in Section 8.2 on the number of shares of Restricted Stock which may be granted applicable separately to Phantom Stock units. An Award of Phantom Stock may be granted, at the discretion of the Committee, together with an Award of Dividend Equivalent rights for the same number of shares covered thereby.10.2. Payment of Phantom Stock Upon the vesting date applicable to Phantom Stock granted to a Participant, an amount equal to one share of Common Stock upon such date shall be paid with respect to such Phantom Stock unit granted to the Participant. Payment may be made, at the discretion of the Committee, in cash, Restricted Stock, shares of unrestricted Common Stock, Options, or a combination thereof. Cash payments of Phantom Stock units shall be calculated on the basis of the average of the Fair Market Value of the Common Stock for the last 20 trading days prior to the payment date.11. Dividend Equivalents A Dividend Equivalent granted to a Participant is an Award in the form of a right to receive cash, shares of Common Stock, or other property equal in value to dividends paid with respect to a specific number of shares of Common Stock. Dividend Equivalents may be awarded on a free-standing basis or in connection with another Award, and may be paid currently or on a deferred basis. The Committee may provide at the Date of Grant or thereafter that the Dividend Equivalent shall be paid or distributed when accrued or shall be deemed to have been reinvested in additional shares of Common Stock or such other investment vehicles as the Committee may specify;provided, however, that Dividend Equivalents (other than free-standing Dividend Equivalents) shall be subject to all conditions and restrictions of the underlying Awards to which they relate.8

12. Change in Control 12.1. Effect of Change in Control. The Committee may, in an Award Agreement, provide for the effect of a Change in Control on an Awvard. Such provisions may include any one or more of the following: (a) the acceleration or extension of time periods for purposes of exercising, vesting in, or realizing gain from any Award, (b) the waiver or modification of performance or other conditions related to the payment or other rights under an Award; (c)provision for the cash settlement of an Award for an equivalent cash value, as determined by the Committee, or (d)such other modification or adjustment to an Award as the Committee deems appropriate to maintain and protect the rights and interests of Participants upon or following a Change in Control.12.2. Definition of Change in Control. For purposes hereof, a "Change in Control" shall be deemed to have occurred if: (a) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934 ("Exchange Act")), other than any company owned, directly or indirectly, by the shareholders of AEP in substantially the same proportions as their ownership of shares of Common Stock or a trustee or other fiduciary holding securities under an employee benefit plan of AEP, becomes the "beneficial owner" (as defined in Rule 1 3d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of AEP;(b) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new directors (other than a director nominated by a person (i) who has entered into an agreement with AEP to effect a transaction described in Section 12.2(a), (c) or (d) hereof or (ii) who publicly announces an intention to take or consider taking actions (including, but not limited to, an actual or threatened proxy contest) which if consummated would constitute a Change in Control) whose election or nomination for election was approved by a vote of at least two-thirds of the directors then still in office who were either directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason (except for death, disability or voluntary retirement) to constitute at least a majority of the Board;(c) AEP consummates a merger or consolidation with any other entity, other than a merger or consolidation which would result in the voting securities of AEP outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 50 percent of the total voting power represented by the voting securities of AEP or such surviving entity outstanding immediately after such merger or consolidation; or (d) the shareholders of AEP approve a plan of complete liquidation of AEP, or an agreement for the sale or disposition by AEP (in one transaction or a series of transactions) of all or substantially all of AEP's assets.Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of the AEP-CSW Merger, nor thereafter as a result of any event in (a) or (c) above, if directors who were members of the Board prior to such event continue to constitute a majority of the Board after such event.13. Award Agreements 13.1. Form ofAgreement.

Each Award under this Plan shall be evidenced by an Award Agreement in a form approved by the Committee setting forth the number of shares of Common Stock, units or other rights (as applicable) subject to the Award, the exercise, base or purchase price (if any) of the Award, the time or times at which an Award will become vested, exercisable or payable, the duration of the Award and, in the case of Performance Awards, the applicable performance criteria and goals. The Award Agreement shall also set forth other material terms and conditions applicable to the Award as determined by the Committee consistent with the 9 limitations of this Plan. Award Agreements evidencing Awards intended to qualify for exemption under Section 162(m) may be designated as such and shall contain such terms and conditions as may be necessary to meet the applicable requirements of Section 162(m). Award Agreements evidencing Incentive Stock Options shall contain such terms and conditions as may be necessary to meet the applicable provisions of Section 422 of the Code.13.2. Contract Rights; Amendment. Any obligation of AEP to any Participant with respect to an Award shall be based solely upon contractual obligations created by an Award Agreement. No Award shall be enforceable until the Award Agreement has been signed on behalf of AEP by its authorized representative and signed by the Participant and returned to AEP. By executing the Award Agreement, a Participant shall be deemed to have accepted and consented to the terms of this Plan and any action taken in good faith under this Plan by and within the discretion of the Committee, the Board or their delegates. Award Agreements covering outstanding Awards may be amended or modified by the Committee in any manner that may be permitted for the grant of Awards under the Plan, subject to the consent of the Participant to the extent provided in the Award Agreement.

14. General Provisions 14.1. Limits on Transfer of Awards; Beneficiaries.

Solely to the extent permitted by the Committee in an Award Agreement and subject to such terms and conditions as the Committee shall specify, Awards shall be nontransferable othenvise than as designated by the Participant by will or by the laws of descent and distribution and, during the lifetime of a Participant, Awards shall be exercised only by such Participant or by his guardian or legal representative. Notwithstanding the foregoing, the Committee may provide in the terms of an Award Agreement that the Participant shall have the right to designate a beneficiary or beneficiaries who shall be entitled to any rights, payments or other benefits specified under an Award Agreement following the Participant's death.14.2. Deferrals of Payment. The Committee may permit a Participant to defer the receipt of payment of cash or delivery of shares of Common Stock that would otherwise be due to the Participant by virtue of the exercise of a right or the satisfaction of vesting or other conditions with respect to an Award. If any such deferral is to be permitted by the Committee, the Committee shall establish the rules and procedures relating to such deferral, including, without limitation, the period of time in advance of payment when an election to defer may be made, the time period of the deferral and the events that would result in payment of the deferred amount, the interest or other earnings attributable to the deferral and the method of funding, if any, attributable to the deferred amount.14.3. Rights as Shareholder. A Participant shall have no rights as a holder of Common Stock with respect to any unissued securities covered by an Award until the date the Participant becomes the holder of record of these securities. Except as provided in Section 3.4 hereof, no adjustment or other provision shall be made for dividends or other shareholder rights, except to the extent that the Award Agreement provides for Dividend Equivalents, dividend payments or similar economic benefits.14.4. Employment or Service. Nothing in the Plan, in the grant of any Award or in any Award Agreement shall confer upon any Eligible Person the right to continue in the capacity in which he is employed by or otherwise serves AEP or any Subsidiary. 14.5. Securities LaIvs. No shares of Common Stock will be issued or transferred pursuant to an Award unless and until all then applicable requirements imposed by federal and state securities and other laws, rules and regulations and by any regulatory agencies having jurisdiction, and by any stock exchanges upon which the Common Stock may be listed, have been fully met. As a condition precedent to the issuance of shares pursuant to the grant or exercise of an Award, AEP may require the Participant to take any reasonable action to meet such .requirements. The Committee may impose such conditions on any shares of Common Stock issuable under the Plan as it may deem advisable, including, without limitation, restrictions under the Securities Act of 1933, as amended, under the requirements of any stock exchange upon which such shares of the same class are then listed, and under any blue sky or other securities laws applicable to such shares.10 14.6. Tar Withholding. The Participant shall be responsible for payment of any taxes or similar charges required by law to be withheld from an Award or an amount paid in satisfaction of an Award, which shall be paid by the Participant on or prior to the payment or other event that results in taxable income in respect of an Award.The Award Agreement shall specify the manner in which the withholding obligation shall be satisfied with respect to the particular type of Award.14.7. Unfunded Plan. The adoption of this Plan and any setting aside of cash amounts or shares of Common Stock by AEP with which to discharge its obligations hereunder shall not be deemed to create a trust or other funded arrangement. The benefits provided under this Plan shall be a general, unsecured obligation of AEP payable solely from the general assets of AEP, and neither a Participant nor the Participant's permitted transferees or estate shall have any interest in any assets of AEP by virtue of this Plan, except as a general unsecured creditor of AEP.Notvithstanding the foregoing, AEP shall have the right to implement or set aside funds in a grantor trust subject to the claims of AEP's creditors to discharge its obligations under the Plan.14.8. Other Compensation and Benefit Plans. The adoption of the Plan shall not affect any other stock incentive or other compensation plans in effect for AEP or any Subsidiary, nor shall the Plan preclude AEP from establishing any other forms of stock incentive or other compensation for employees of AEP or any Subsidiary. The amount of any compensation deemed to be received by the Participant pursuant to an Award shall not constitute compensation with respect to which any other employee benefits of such Participant are determined, including, without limitation, benefits under any bonus, pension, profit sharing, life insurance or salary continuation plan, except as otherwise specifically provided by the terms of such plan.14.9. Plan Binding on Successors. The Plan shall be binding upon AEP, its successors and assigns, and the Participant, his executor, administrator and permitted transferees and beneficiaries. 14.10. Construction and Interpretation. Whenever used herein, nouns in the singular shall include the plural, and the masculine pronoun shall include the feminine gender. Headings of Sections hereof are inserted for convenience and reference and constitute no part of the Plan.14.11. Severability. If any provision of the Plan or any Award Agreement shall be determined to be illegal or unenforceable by any court of law in any jurisdiction, the remaining provisions hereof and thereof shall be severable and enforceable in accordance with their terms, and all provisions shall remain enforceable in any other jurisdiction. 14.12. Governing Lav. The laws of the State of Ohio shall govern the validity and construction of this Plan and of the Award Agreements, without giving effect to principles relating to conflict of laws, except to the extent that such laws may be preempted by Federal law.15. Effective Date, Termination and Amendment 15.1. Effective Date; ShareholderApproval. Subject to approval by the Securities and Exchange Commission, the Effective Date of the Plan shall be the date following adoption of the Plan by the Board on which the Plan is approved by the shareholders of AEP. Grants of Awards under the Plan may be made prior to the Effective Date (but after adoption of the Plan by the Board), subject to approval of the Plan by the Securities and Exchange Commission and the shareholders. At the sole discretion of the Board, in order to comply with the requirements of Section 162(m) for certain types of Awards under the Plan, the performance criteria set forth in Section 9.3 shall be reapproved by the shareholders no later than the first shareholder meeting that occurs in the fifth calendar year following the calendar year of the initial shareholder approval of such performance criteria.15.2. Termination The Plan shall remain in effect until terminated by action of the Board; provided, however, that no Incentive Stock Option may be granted hereunder after the tenth anniversary of the date the Plan is adopted by the Board.I1I Notwithstanding the foregoing, no termination of the Plan shall in any manner affect any Award theretofore granted without the consent of the Participant or the permitted transferee of the Award.15.3. Amendment. The Board may at any time and from time to time and in any respect, amend or modify the Plan; provided, however, that no amendment or modification of the Plan shall be effective without the consent of AEP's shareholders that would (a) increase the number of shares of Common Stock reserved for issuance or (b)allow the grant of Options at an exercise price below Fair Market Value (except as otherwise permitted by Section 6.2), or allow the repricing of Options without AEP shareholder approval. In addition, the Board may seek the approval of any amendment or modification by AEP's shareholders to the extent it deems necessary or advisable in its sole discretion for purposes of compliance with Section 162(m) or Section 422 of the Code, the listing requirements of the New York Stock Exchange or for any other purpose. No amendment or modification of the Plan shall in any manner affect any Award theretofore granted without the consent of the Participant or the permitted transferee of the Award.12 ..........- EXHIBIT 10(v)(3)CERTIFIED COPY OF A RESOLUTION OF THE BOARD OF DIRECTORS OF AEP UTILITIES, INC.RESOLVED: That the Board of Directors of AEP Utilities, Inc. hereby authorizes the appropriate officers of the Corporation to establish additional pension benefits through the Central and South West System Special Executive Retirement Plan, which shall contain substantially the same terms and conditions as are set out in the said plan which has heretofore been approved by the Board of Directors. It is the intent of this Board of Directors, by taking this action, to: 1. Grant to Thomas M. Hagan additional years of credited service in excess of the actual credited service earned under the Central and South West System Pension Plan.2. Provide for payment of pension benefits for retirement commencing at age 60 or later based on thirty years of credited service less benefits payable under the basic Pension Plan in accordance with the provisions of the Special Executive Retirement Plan.FURTHER RESOLVED: That the Board of Directors approves and ratifies any and all actions heretofore taken in connection with this plan on behalf of Thomas M. Hagan.This resolution and the authorization herein contained shall become effective immediately. I, Thomas G. Berkemeyer, do hereby certify that I am Assistant Secretary of AEP Utilities, Inc., a Delaware corporation, and as such Assistant Secretary and the keeper of the corporate records and seal of said Corporation, and as said Assistant Secretary, I do hereby further certify that the above and foregoing is a true and correct copy of a certain resolution as the same appears upon the records of said Corporation duly adopted by the Board of Directors of said Corporation at a meeting of said Board duly called and held on the 16th day of July, 1996, at which meeting a quorum of said Board was present and voting throughout. IN WITNESS WHEREOF, I have hereunto set my hand and affixed the seal of said Corporation this 26th day of February, 2004.Isl Thomas G. Berkemeyer Assistant Secretary SEAL EXHIBIT 12 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARIES Computation of Consolidated Ratios of Earnings to Fixed Charges (in millions except ratio data)Year Ended December31, 1999 2000 2001 2002 2003 Fixed Charges: Interest on Long-term Debt Interest on Short-term Debt Miscellaneous Interest Charges Estimated Interest Element in Lease Rentals Preferred Stock Dividends Total Fixed Charges$608 $608 $599 $642 $735 149 258 143 62 23 78 161 133 103 80 212 223 222 229 203 28 32 15 .18 15$1,075 $1,282 $1,112 $1,054 $1,056 Earnings: Income Before Income Taxes Plus Fixed Charges (as above)Less Undistributed Earnings in Equity Investments Total Earnings$1,327 1,075 46$2,356$779 1,282 46$1,513 1,112 28$800 1,054 12$880 1,056 10$2,015 $2,597 $1,842 $1,926 Ratio of Earnings to Fixed Charges 2.19 1.57 2.33 1.74 1.82 2003 Annual Reports American Electric Power Company, Inc.AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company Audited Financial Statements and Management's Discussion and Analysis AI AMERICAN ELECTRIC POWER AE:iA merkas Emrvg &dwritne AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES INDEX TO ANNUAL REPORTS Page Glossary of Terms i Forward-Looking Information iv AEP Common Stock and Dividend Informnation v American Electric Power Company, Inc. and Subsidiary Companies: Selected Consolidated Financial Data A-I Management's Financial Discussion and Analysis A-2 Consolidated Financial Statements A-46 Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries A-51 Schedule of Consolidated Long-term Debt A-52 Index to Notes to Consolidated Financial Statements A-53 Independent Auditors' Report A-133 Management's Responsibility A-134 AEP Generating Company: Selected Financial Data B-1 Management's Narrative Financial Discussion and Analysis B-2 Financial Statements B14 Statements of Capitalization B-8 Index to Notes to Respective Financial Statements B-9 Independent Auditors' Report B-10 AEP Texas Central Company and Subsidiary: Selected Consolidated Financial Data C-I Management's Financial Discussion and Analysis C-2 Consolidated Financial Statements C-10 Consolidated Statements of Capitalization C-15 Schedule of Long-term Debt C-16 Index to Notes to Respective Financial Statements C-18 Independent Auditors' Report C-l9 AEP Texas North Company: Selected Financial Data D-I Management's Narrative Financial Discussion and Analysis D-2 Financial Statements D-8 Statements of Capitalization D-13 Schedule of Long-term Debt D-14 Index to Notes to Respective Financial Statements D-15 Independent Auditors' Report D-16 Appalachian Power Company and Subsidiaries: Selected Consolidated Financial Data E-l Management's Financial Discussion and Analysis E-2 Consolidated Financial Statements E-9 Consolidated Statements of Capitalization E-14 Schedule of Long-term Debt E-15 Index to Notes to Respective Financial Statements E-17 Independent Auditors' Report E-18 Columbus Southern Power Company and Subsidiaries: Selected Consolidated Financial Data F-1 Management's Narrative Financial Discussion and Analysis F-2 Consolidated Financial Statements F-8 Consolidated Statements of Capitalization F- 13 Schedule of Long-term Debt F-14 Index to Notes to Respective Financial Statements F-16 Independent Auditors' Report F-17 Indiana Michigan Power Company and Subsidiaries: Selected Consolidated Financial Data G-l Management's Financial Discussion and Analysis G-2 Consolidated Financial Statements G-10 Consolidated Statements of Capitalization G-15 Schedule of Long-term Debt G-16 Index to Notes to Respective Financial Statements G-18 Independent Auditors' Report G-19 Kentucky Power Company: Selected Financial Data H-I Management's Narrative Financial Discussion and Analysis H-2 Financial Statements H-8 Statements of Capitalization H-13 Schedule of Long-term Debt H-14 Index to Notes to Respective Financial Statements H-15 Independent Auditors' Report H-16 Ohio Power Company Consolidated: Selected Consolidated Financial Data I-l Management's Financial Discussion and Analysis 1-2 Consolidated Financial Statements 1-12 Consolidated Statements of Capitalization 1-17 Schedule of Long-term Debt 1-18 Index to Notes to Respective Financial Statements 1-21 Independent Auditors' Report 1-22 Public Service Company of Oklahoma: Selected Financial Data J-I Management's Narrative Financial Discussion and Analysis J-2 Financial Statements J-7 Statements of Capitalization J-12 Schedule of Long-term Debt J-13 Index to Notes to Respective Financial Statements J-15 Independent Auditors' Report J-16 Southivestern Electric Power Company Consolidated: Selected Consolidated Financial Data K-l Management's Financial Discussion and Analysis K-2 Consolidated Financial Statements K-9 Consolidated Statements of Capitalization K-14 Schedule of Long-term Debt K-15 Index to Notes to Respective Financial Statements K-17 Independent Auditors' Report K-18 Notes to Respective Financial Statements L-1 Registrants' Combined Management's Discussion and Analysis M-l GLOSSARY OF TERMIS When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.Term Meaning 2004 True-up Proceeding AEGCo AEP AEP Consolidated AEP Credit AEP East companies AEPES AEPR AEP System or the System AEPSC AEP System Power Pool or AEP Power Pool AEP West companies AFUDC ALJ Alliance RTO Amos Plant APB 18 APCo Arkansas Commission Buckeye COLI Cook Plant CSPCo CSW CSW Energy CSW International D.C. Circuit Court DETM DOE ECOM EITF A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.AEP Generating Company, an electric utility subsidiary of AEP.American Electric Power Company, Inc.AEP and its majority owned consolidated subsidiaries and consolidated affiliates. AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated domestic electric utility companies. APCo, CSPCo, I&M, KPCo and OPCo.AEP Energy Services, Inc., a subsidiary of AEPR.AEP Resources, Inc.The American Electric Power System, an integrated electric utility system, owned and operated by AEP's electric utility subsidiaries. American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale system sales of the member companies. PSO, SWVEPCo, TCC and TNC.Allowance for funds used during construction, a noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant.Administrative Law Judge.Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated utilities (the FERC overturned earlier approvals of this RTO in December 2001).John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.Accounting Principles Board Opinion Number 18: The Equity Method of Accounting for Investments in Common Stock.Appalachian Power Company, an AEP electric utility subsidiary. Arkansas Public Service Commission. Buckeye Power, Inc., an unaffiliated corporation. Corporate owned life insurance program.The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.Columbus Southem Power Company, an AEP electric utility subsidiary. Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.CSW International, Inc., an AEP subsidiary which invests in energy projects and entities outside the United States.The United States Court of Appeals for the District of Columbia Circuit.Duke Energy Trading and Marketing L.L.C., a risk management counterparty. United States Department of Energy.Excess Cost Over Market.The Financial Accounting Standards Board's Emerging Issues Task Force.i EITF 02-3 ERCOT ENVGs FASB Federal EPA FERC FIN 45 FIN 46 FUCOs GAAP 1&M ICR IRS IURC ISO JMG KPCo KPSC KV KNVH LIG LPSC Michigan Legislation MISO MLR Money Pool MPSC MTM MW MWH NOx NOx Rule NRC OCC Ohio Act Ohio EPA OPCo OVEC PCBs PJM PRP PSO PTm PUCO PUCT Emerging Issues Task Force Issue No. 02-3: Issues Involved in Accounting for Derivative Contracts Held For Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. The Electric Reliability Council of Texas.Exempt Wholesale Generators. Financial Accounting Standards Board.United States Environmental Protection Agency.Federal Energy Regulatory Commission. FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FASB Interpretation No. 46, "Consolidation of Variable Interest Entities." Foreign Utility Companies. Generally Accepted Accounting Principles. Indiana Michigan Power Company, an AEP electric utility subsidiary. Interchange Cost Reconstruction. Internal Revenue Service.Indiana Utility Regulatory Commission. Independent System Operator.JMG Funding LP.Kentucky Power Company, an AEP electric utility subsidiary. Kentucky Public Service Commission. Kilovolt.Kilowatthour. Louisiana Intrastate Gas, an AEP subsidiary. Louisiana Public Service Commission. The Customer Choice and Electricity Reliability Act, a Michigan law which provides for customer choice of electricity supplier.Midwest Independent System Operator (an independent operator of transmission assets in the Midwest).Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.AEP System's Money Pool.Michigan Public Service Commission. Mark-to-Market. Megawatt.Megawatthour. Nitrogen oxide.A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states including seven of the states in which AEP companies operate.Nuclear Regulatory Commission. The Corporation Commission of the State of Oklahoma.The Ohio Electric Restructuring Act of 1999.Ohio Environmental Protection Agency.Ohio Power Company, an AEP electric utility subsidiary. Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a 44.2% equity interest.Polychlorinated Biphenyls. Pennsylvania -New Jersey -Maryland regional transmission organization. Potentially Responsible Party.Public Service Company of Oklahoma, an AEP electric utility subsidiary. Price-to-Beat. The Public Utilities Commission of Ohio.The Public Utility Commission of Texas.ii PUHCA PURPA RCRA Registrant Subsidiaries REP Risk Management Contracts Rockport Plant RTO SEC SFAS SFAS 71 SFAS 101 SFAS 133 SFAS 143 SFAS 149 SFAS 150 SNF SPP STP STPNOC Superfund SWEPCo TCC Tenor Texas Legislation TNC TVA U.K.VaR Virginia SCC WVPSC WPCo Zimmer Plant Public Utility Holding Company Act of 1935, as amended.The Public Utility Regulatory Policies Act of 1978.Resource Conservation and Recovery Act of 1976, as amended.AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC.Retail Electric Provider.Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges, and non-derivative contracts held for trading purposes that were subject to mark-to-market accounting prior to January 1, 2003.A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and l&M.Regional Transmission Organization. Securities and Exchange Commission. Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain TVpes of Regulation. Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuance of Application of Statement 71.Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Statement of Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Eguity.Spent Nuclear Fuel.Southwest Power Pool.South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an AEP electric utility subsidiary. STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of its joint owners including TCC.The Comprehensive Environmental, Response, Compensation and Liability Act.Southwestern Electric Power Company, an AEP electric utility subsidiary. AEP Texas Central Company, an AEP electric utility subsidiary. Maturity of a contract.Legislation enacted in 1999 to restructure the electric utility industry in Texas.AEP Texas North Company, an AEP electric utility subsidiary. Tennessee Valley Authority. The United Kingdom.Value at Risk, a method to quantify risk exposure.Virginia State Corporation Commission. Public Service Commission of West Virginia.Wheeling Power Company, an AEP electric distribution subsidiary. William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus Southern Power Company, an AEP subsidiary. iii FORWARD-LOOKING INFORMATION This report made by AEP and certain of its subsidiaries contains forvard-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its registrant subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:* Electric load and customer growth.* Weather conditions.

Available sources and costs of fuels.* Availability of generating capacity and the performance of AEP's generating plants.* The ability to recover regulatory assets and stranded costs in connection with deregulation.
New legislation and government regulation including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon and other substances.
Resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery for environmental compliance).
Oversight and/or investigation of the energy sector or its participants.
Resolution of litigation (including pending Clean Air Act enforcement actions and disputes arising from the bankruptcy of Enron Corp.).* AEP's ability to reduce its operation and maintenance costs.* The success of disposing of investments that no longer match AEP's corporate profile.* AEP's ability to sell assets at attractive prices and on other attractive terms.* International and country-specific developments affecting foreign investments including the disposition of any current foreign investments.
The economic climate and growth in AEP's service territory and changes in market demand and demographic patterns.* Inflationary trends.* AEP's ability to develop and execute on a point of view regarding prices of electricity, natural gas, and other energy-related commodities.
Changes in the creditworthiness and number of participants in the energy trading market.* Changes in the financial markets, particularly those affecting the availability of capital and AEPs ability to refinance existing debt at attractive rates.* Actions of rating agencies, including changes in the ratings of debt and preferred stock.* Volatility and changes in markets for electricity, natural gas, and other energy-related commodities.
Changes in utility regulation, including the establishment of a regional transmission structure.
Accounting pronouncements periodically issued by accounting standard-setting bodies.* The performance of AEP's pension plan.* Prices for power that we generate and sell at *wholesale.
Changes in technology and other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.iv AEP COMMON STOCK AND DIVIDEND INFORMATION The AEP common stock quarterly high and low sales prices, quarter-end closing price and the cash dividends paid per share are shortn in the following table: Quarter-end Quarter Ended High Low Closing Price Dividend December 2003 $30.59 $26.69 $30.51 $0.35 September 2003 30.00 26.58 30.00 0.35 June 2003 31.51 22.56 29.83 0.35 March 2003 30.63 19.01 22.85 0.60 December 2002 $30.55 $15.10 $27.33 $0.60 September 2002 40.37 22.74 28.51 0.60 June 2002 48.80 39.00 40.02 0.60 March 2002 47.08 39.70 46.09 0.60 AEP common stock is traded principally on the New York Stock Exchange.

At December 31, 2003, AEP had approximately 150,000 registered shareholders. V AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SELECTED CONSOLIDATED FINANCIAL DATA OPERATIONS STATEMENTS DATA Total Revenues Operating Income Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect Discontinued Operations Income (Loss)Extraordinary Losses Cumulative Effect of Accounting Changes Gain (Loss)Net Income (Loss)2003 2002 2001 2000 1999 (in millions)$14,545 $13,308 $12,753 $10,743 $9,695 1,632 1,804 2,223 1,758 2,053 522 (605)193 110 485 (654)(350)(519)960 41 (48)18 971 177 134 (44)267 865 116 (9)972 BALANCE SHEET DATA Property, Plant and Equipment Accumulated Depreciation and Amortization Net Property, Plant and Equipment Total Assets$36,033 14.004__SyL2$34,127 13.539_$20.58$36,744 $35,890 Common Shareholders' Equity 7,874 Cumulative Preferred Stocks of Subsidiaries (a) (d)Trust Preferred Securities (b)137 7,064 145 321 10,190 228 (in millions)$32,993 12.655$2R.33W8$40,432 8,229 156 321 9,409 451 8,054$31,472 $30,476 124398 11,895$47,703 $36,297 8,673 161 182 Long-term Debt (a) (b)Obligations Under Capital Leases (a)14,101 182 334 8,980 614 335 9,471 610 COMMON STOCK DATA Earnings (Loss) per Common Share: Before Discontinued Operations, Extraordinary Items and Cumulative Effect Discontinued Operations Extraordinary Losses Cumulative Effect of Accounting Changes Earnings (Loss) Per Share Average Number of Shares Outstanding (in millions)Market Price Range: High Low Year-end Market Price Cash Dividends on Common (c)Dividend Payout Ratio(c)Book Value per Share$1.35 (1.57)0.51$1.46 (1.97)(1.06)$2.98 0.13 (0.16)0.06$0.55 $2.69 0.42 0.36 (0.14) (0.02)_QS. $ $0.83 $3.03 385$31.51 19.01 30.51$1.65 569.0%$19.93 332$48.80 15.10 27.33$2.40 (152.9)%$20.85 322$51.20 39.25 43.53$2.40 79.7%$25.54 322$48.94 25.94 46.50$2.40 289.2%$25.01 321$48.19 30.56 32.13$2.40 79.2%$26.96 (a) Including portion due within one year.(b) See Note 17 of the Notes to Consolidated Financial Statements.(c) Based on AEP historical dividend rate.(d) Includes Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption which are classified in 2003 as Non-Current Liabilities. A-1 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS American Electric Power Company, Inc. (AEP) is one of the largest investor owned electric public utility holding companies in the U.S. Our electric utility operating companies provide generation, transmission and distribution service to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia.We have a vast portfolio of assets including:

38,000 megawatts of generating capacity, the largest complement of generation in the U.S., the majority of which has a significant cost advantage in many of our market areas. Utility generating capacity of 4,500 megawatts located in Texas and approximately 280 megawatts of independent power generation located in Colorado and Florida are expected to be sold during 2004* 39,000 miles of transmission lines, the backbone of the electric interconnection grid in the Eastern U.S.* 210,000 miles of distribution lines that deliver electricity to customers* Substantial coal transportation assets (7,000 railcars, 1,800 barges, 37 towboats and two coal handling terminals with 20 million tons of annual capacity)* 6,400 miles of gas pipelines in Louisiana and Texas with 127 Bcf of gas storage facilities.

We have entered into an agreement to sell 2,000 miles of pipeline and plan to sell 9 Bcf of storage located in Louisiana related to our disposal of LIG* 4,000 megawatts of generating capacity in the U.K., a market which we plan to exit by the end of 2004 BUSINESS STRATEGY We will continue to concentrate our efforts on our domestic utilities. Our objectives are to be an economical, reliable and safe provider of energy to the markets that wve serve. We will achieve economic advantage by designing, building, improving and operating low cost efficient sources of power and maximizing the volumes of power delivered from these facilities. We will maintain and enhance our position as a safe and reliable provider of energy by making significant investments into environmental and reliability upgrades. We will seek to recover the cost of our new utility investments in a manner that results in reasonable rates for our customers and that provides a fair return for our shareholders through a stable stream of cash flows enabling us to pay competitive dividends. We are addressing many challenges in our unregulated business. We have substantially reduced our trading activities that are not related to the sale of power from our owned-generation. We have written down the value of several investments to reflect deterioration in market conditions and sold or plan to sell assets that no longer fit our core business strategy. We have identified certain assets as "held-for-sale" and will move others to "held-for-sale" as we formalize and approve our plans for disposition. We will continue to operate HPL as we evaluate our future plans for this investment. In summary our business strategy calls for us to: Operations

Invest in technology that improves the environment of the communities in which we operate* Maximize the value of our transmission assets and protect our revenue stream through membership in PJM* Continue maintaining and improving distribution service quality* Optimize generation assets by increasing availability and consequently increasing sales* Complete the sales of our non-core assets Regulation
Focus on the regulatory process to maximize our earnings while providing fair and reasonable rates to our customers* Complete the sale of our generation assets in Texas and recognize and recover the associated stranded costs in compliance with the law* Complete the integration of the operation of our transmission system into PJM consistent with applicable regulatory requirements A-2 Financial* Operate only those unregulated investments that are consistent with our energy expertise and risk tolerance and that provide reasonable prospects for a fair return and moderate growth* Continue to improve credit quality and maintain acceptable levels of liquidity* Achieve moderate but steady earnings growth 2003 OVERVIEW 2003 was a year of transition for AEP. We repositioned ourselves to take advantage of, and maximize, the value of our utility assets. At the same time we took significant strides to exit non-core investments.

Our utility operations had a year of continued improvement resulting from strong wholesale results and our efforts to control and reduce operating costs. We reduced our losses from unregulated investments by reducing transitional trading losses and cutting related administrative expenses.During 2003 we further stabilized our financial strength by:* Issuing approximately $1.1 billion in common stock* Completing a cost reduction initiative which led to a $392 million decline in operations and maintenance expenses during 2003 as compared to 2002. Savings of approximately $139 million are attributable to our utility operations

Minimizing future capital requirements associated with non-core assets* Reducing our cash flow risk by limiting our trading activities to a level consistent with the scope of our generation fleet* Stabilizing our credit ratings We have redirected our business strategy by:* Continuing to streamline our trading activities principally to support the sale of power from our core assets* Actively pursuing the sale of all of our U.K. generation and our gas pipeline operations located in Louisiana; we expect each of these dispositions to be completed during 2004 OUTLOOK FOR 2004 WVe remain focused on the fundamental earning power of our utilities, and we are committed to strengthening our balance sheet. Our strategy for achieving these goals is well planned. We will:* Continue to identify opportunities to further reduce both our operations and maintenance expenses and to efficiently manage our capital expenditures
Seek rate changes that are fair and reasonable and that allow us to make the necessary operational and environmental improvements to our system* Dispose of various unregulated assets to eliminate the negative earnings and cash consequences of these operations
Use the proceeds from our dispositions to reduce debt and strengthen our capital structure* Successfully operate certain unregulated investments such as our wind farms and our barge and river transport groups, which compliment our core capabilities
Evaluate opportunities to hold and operate HPL under a revised business model that reduces commodity risk and earns reasonable returns for shareholders Our objective is excellence in operations and results. There are, nevertheless, certain risks and challenges.

We discuss these matters in detail in the Notes to Financial Statements and later in Management's Discussion and Analysis under the heading of Significant Factors. We will diligently resolve these matters by finding workable solutions that balance the interests of our customers, our employees and our investors. A-3 RESULTS OF OPERATIONS In 2003, AEP's principal operating business segments and their major activities were:* Utility Operations: o Domestic generation of electricity for sale to retail and wholesale customers o Domestic electricity transmission and distribution

Investments-Gas Operations:*

o Gas pipeline and storage services* Investments-UK Operations:** o International generation of electricity for sale to wholesale customers o Coal procurement and transportation to AEP plants and third parties* Investments-Other: o Coal mining, bulk commodity barging operations and other energy supply related businesses

Operations of Louisiana Intrastate Gas were classified as discontinued during 2003.** UK Operations were classified as discontinued during 2003.American Electric Power Company's consolidated Net Income (Loss) for the years ended December 31, 2003, 2002 and 2001 were as follows (Earnings and Average Shares Outstanding in millions):

2003 2002 2001 Earnings EPS Earnings EPS Earnines EPS Utility Operations $1,218 $3.17 $1,154 $3.47 $941 $2.92 Investments -Gas Operations (290) (.76) (99) (.29) 91 .28 Investments -UK Operations

Investments

-Other (277) (.72) (522) (1.58) --All Other* (129) (.34 (48 (.14) (72) (.22 Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect 522 1.35 485 1.46 960 2.98 Investments-Gas Operations (91) (.24) 8 .02 (4) (.01)Investments-UK Operations (507) (1.32) (472) (1.42) (41) (.13)Investments-Other (7) (.01) (190) (.57) 86 .27 Discontinued Operations (605) (1.57) (654) (1.97) 41 .13 Extraordinary Loss ----(48) (.16)Cumulative Effect of Accounting Changes 193 .51 (350) (1.06) 18 .06 Total Net Income (Loss) _1_. _( 1 ) 1.5 7 ) _$3 .0!Average Shares Outstanding 385 33232* All Other includes the parent company interest income and expense, as well as other non-allocated costs.2003 Compared to 2002 Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect in 2003 increased compared to 2002 due to increased wholesale earnings, lower impairment and other charges, and reduced operations and maintenance expenses. This increase was offset, in part, by milder weather and continuing weakness in the economy.OurNet Income for 2003 of $1 10 million or $.29 per share includes a loss, net of taxes, on discontinued operations of$605 million and $193 million of income, net of taxes, from the cumulative effect of changing our accounting for asset retirement obligations and for certain trading activities. Our Net Loss for 2002 of $519 million or ($1.57) per share includes a loss, net of taxes, on discontinued operations of $654 million and a $350 million, net of tax, charge for implementing a newly issued accounting pronouncement related to the impairment of goodwill.A-4 During the fourth quarter of 2003 we concluded that the U.K. operations and LIG wvere not part of our core business and we began actively marketing each of these investments. The U.K. operations consist of our generation and trading operations that sell to wholesale customers. LIG's operations include 2,000 miles of intrastate gas pipelines and 9 Bcf of natural gas storage capacity. In addition, we recognized that poor market conditions also affected our merchant generation, other gas pipeline and storage assets, goodwill associated with these investments and various other assets. Based on market factors, as measured by a combination of indicative bids from unrelated interested buyers, independent appraisals, and estimates of cash flows, we recognized impairment losses of $960 million, net of taxes.Average shares outstanding increased to 385 million in 2003 from 332 million in 2002 due to a common stock issuance in March 2003. The additional average shares outstanding decreased our 2003 earnings per share by $0.04.2002 Compared to 2001 Our Net Loss was $519 million or a loss of $1.57 per share in 2002 which was a $1.5 billion decline from 2001.Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect was negatively affected by plant availability, lower wholesale prices, reduced trading activity and *write-offs to reduce the valuation of the under-performing assets. In the fourth quarter 2002, wve recognized impairments on under-performing assets and recorded losses, net of taxes, of $854 million. The losses in the fourth quarter 2002 were caused by the extended decline in domestic and international energy markets. In addition to the fourth quarter impairment losses, we had losses on discontinued operations of $654 million including U.K. operations, SEEBOARD, Citipowver and other investments and a loss for transitional goodwill impairment of $350 million related to SEEBOARD and Citipower that resulted from the adoption of a newly issued accounting standard related to the impairment of goodwill.Our results of operations are discussed below according to our operating segments.Utility Operations Summary of Selected Sales Data For Utility Operations For the Years Ended December 31,2003,2002 and 2001 2003 2002 2001 Energy Summary (in millions of KWH)Retail Residential 45,479 46,805 43,498 Commercial 37,104 36,487 35,589 Industrial 51,856 53,686 52,443 Miscellaneous 303.5 3.2 16 .2208 Total 137,474 140.194 133.738 Wholesale 72.977 70.661 79.288 2003 2002 2001 Weather Summary (in degree days)Eastern Region Actual -Heating 5,314 4,963 4,679 Normal -Heating* 5,182 5,177 5,232 Actual -Cooling 757 1,252 1,021 Normal -Cooling* 975 1,013 997 Western Region Actual -Heating 1,020 1,044 1,134 Normal -Heating* 1,062 1,034 1,060 Actual -Cooling 2,220 2,369 2,377 Normal -Cooling* 2,217 2,224 2,233*Normal Heating/Cooling represents the 30-year average of degree days.A-5 2003 Compared to 2002 Earnings from Utility Operations increased $64 million to $1,218 million in 2003. Decreased operating expenses were partially offset by decreases in revenues net of related fuel and purchased power.Utility revenues net of related fuel and purchased power decreased as follows:* Residential demand decreased principally as a consequence of milder weather, and industrial demand was down due to the continued slow economic recovery. The combination of these factors reduced revenues net of related fuel and purchased power by approximately $65 million.* Reserves for final fuel factor decisions in Texas as well as other disallowances and associated rate reserves of$102 million and lower regulatory deferrals for ECOM-based stranded costs of $44 million reduced earnings.The provisions for stranded cost recovery in Texas recognize a regulatory asset or liability for the difference between the actual price received from the state-mandated auction of 15% of generation capacity and the earlier estimate of market price derived by a PUCT model.* Fuel and purchased power costs increased by approximately $40 million due in part to nuclear plant outages.* During the fourth quarter of 2002, we exited trading activities that were not related to the sale of power from our owned-generation. The loss of these contributions from exiting the related trading positions reduced utility earnings by approximately $70 million.The decreases in utility revenues net of related fuel and purchased power were partially offset as follows:* Off-system sales, including optimization activities, increased by approximately $160 million primarily due to increased prices and plant availability.

Transmission revenues increased by approximately

$45 million, due principally to increased wholesale power sales volumes.Utility operating expenses decreased as follows:* Maintenance and Other Operation expense decreased $139 million due to continuing efforts to reduce costs, primarily labor and insurance, despite severe storm damage in the Midwest.* Taxes Other Than Income Taxes decreased $17 million primarily due to reduced gross receipts tax as a result of the sale of the Texas REPs.* Depreciation and Amortization expense decreased $18 million due to the change in our accounting for asset retirement obligations. The accounting change caused similar offsetting increases in Maintenance and Other Operation expenses.2002 Compared to 2001 Earnings from Utility Operations increased $213 million to $1,154 million in 2002 due to an $84 million gain on the sale of the Texas REPs and capital cost reductions of $104 million, partially offset by a reduction in operating income.Capital costs decreased due to reductions in short-term interest rates, lower outstanding balances of short-term debt and the refinancing of long-term debt at favorable interest rates. These reductions were partially offset by an increase in the amount of long-term debt outstanding. Increased operating expenses were partially offset by increases in revenues net of related fuel and purchased power.Utility revenues net of related fuel and purchased power increased as follows:* ECOM-based Texas stranded cost deferrals increased $262 million.* Retail demand increased approximately $180 million due to increased usage by residential customers. Eastern region cooling degree days were up 23% over 2001.A-X The increases in utility revenues net of related fuel and purchased power were partially offset as follows:* Off-system sales net of related fuel and purchased power decreased $126 million primarily due to lower plant availability, lower wholesale prices, the loss of certain municipal and co-op customers, and customers switching from FERC tariff-based to market-based rates.* Trading operations, which decreased $214 million as a result of our previously announced plan to exit trading activities that are not related to the sale of power from our owned-generation. Utility operating expenses increased as follows:* Maintenance and Other Operation expense increased $102 million due to increased benefit costs of $48 million, increased post September 11 insurance cost of $35 million and increased nuclear maintenance and other expenses of $19 million.* Depreciation and Amortization expense increased $46 million as a result of additional generation, transmission and distribution assets.* Taxes Other Than Income Taxes increased $70 million due to increased property and payroll taxes.Investments -Gas Operations 2003 Compared to 2002 The loss from our Gas Operations of $290 million increased $191 million from 2002. This increase is primarily due to impairments recorded to reflect the reduction in the value of our gas assets. In the fourth quarter 2003, we recognized impairments and other related charges of $228 million, net of tax, associated with HPL assets and goodwill based on market indicators supported by indicative bids received for LIG. These bids led us to conclude that purchasers were no longer willing to pay higher multiples for historic cash flows which included trading activities. Our previous operating strategy included higher risk tolerances associated with trading activities in order to achieve such operating results.Partially offsetting the 2003 impairments, gas operations earnings have improved approximately $68 million from 2002 due to a $40 million decrease in losses associated with the options trading portfolio that we are no longer actively trading and exiting through a transition plan (our transition gas trading portfolio) and a $28 million reduction in operating expenses. These earnings improvements were partially offset by $15 million of losses due to unexpected late February 2003 sales to Entex, at fixed prices, when the Houston Ship Channel prices were at historic highs, a decrease in March deliveries due to unseasonably mild weather, and a decline in trading optimization of $28 million due to lower risk tolerances and limits compared to the previous year.2002 Compared to 2001 The loss from our Gas Operations of $99 million increased $190 million from 2001. The increase is due to significant trading losses in 2002 compared with strong trading results in 2001.Investments -UK Operations 2003 Compared to 2002 The loss from our UK Operations of $507 million for 2003 increased by $35 million from 2002 and was due primarily to $375 million, net of tax, of impairment and other related charges recorded during the fourth quarter. During 2003, we concluded that the UK Operations were not part of our core business and we began actively marketing our investment. As a result, we devalued our UK investment based on bids received from interested unrelated buyers.The loss includes $157 million of pre-tax losses associated with commitments for below market forward sales of power, which are beyond the date of the anticipated sale of these plants. We also experienced operating losses as a result of the deterioration of pretax trading margins of $83 million associated with U.K. power and $29 million associated with coal and freight.A-7 2002 Compared to 2001 Our loss in 2002 from UK Operations of $472 million increased by $431 million from 2001. Our operations in the U.K. were dramatically expanded in December 2001 with the acquisition of two 2,000 MWV generation stations.Goodwill and asset impairment charges of $414 million, net of tax, contributed to our 2002 losses. The oversupply conditions throughout 2002 worsened in the fourth quarter after the British government's decision to subsidize British Energy, a financially troubled, dominant generator of power in the U.K. This intervention in the competitive market kept inefficient generation in the marketplace. The write-down of our two U.K. power plants was the result of our analyses that indicated U.K. power prices would not recover to levels that would permit us to carry the plants at their original purchase prices. In addition to unfavorable U.K. power and coal markets, higher than anticipated operating costs contributed to the loss in 2002.Investments -Other 2003 Compared to 2002 The loss from our Other investments decreased by $245 million to $277 million in 2003. The decrease was primarily due to asset impairment charges of $257 million, net of tax, compared to impairments of $392 million, net of tax, recorded in 2002. 2003 impairments included losses of $45 million, net of tax, for two of our independent generation facilities due to market conditions; $168 million, net of tax, for the Dow facility due to the current market conditions and litigation; and coal mining asset impairments of $44 million, net of tax, based on bids from unrelated parties.Additionally we incurred lower international development costs and reduced interest expenses during 2003.2002 Compared to 2001 The loss from our Other investment operations of $522 million resulted from $392 million of asset impairment charges, net of tax. These *vrite-downs in the fourth quarter of 2002 recognized the lowver valuation in our investments in a utility in Brazil, AEP Communications and other under-performing assets. There were no such write-downs in 2001.All Other Our parent company's 2003 expenses increased $81 million over 2002 primarily from higher interest costs due to increased debt at the parent level and reduced reliance on short-term borrowings as wvell as the recognition of estimated losses from certain litigation contingencies. Expenses in 2002 declined $24 million from 2001 due to lower interest costs.FINANCIAL CONDITION We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows.During 2003 we improved our financial condition as a consequence of the following actions and events:* We issued approximately $1.1 billion of new common equity* We reduced our quarterly dividend in June 2003 to $.35 per share which reduced our annualized cash outflows by approximately $395 million* We reduced short-term debt by $2.8 billion, restructured our lines of credit into two $750 million facilities, completed approximately $1.3 billion of optional long-term debt redemptions, paid-off $225 million of our Steelhead financing, and funded $1.4 billion of debt maturities

We limited our energy trading activity to levels necessary to optimize earnings from sales of our owvned-generation I* Despite downgrades of certain debt ratings during the first quarter and continued uncertainty in the industry, we have maintained stable credit ratings across the AEP System A-8 Capitaliz-ation 2003 2002 2001 Common Equity 35% 32 % 36%Preferred Stock 1 1 1 Long-term Debt, including amounts due within one year 63 50 43 Short-term Debt 1 14 17 Minority Interest in Finance Subsidiary 3 3 Total Capitalization 100% JDDD Our capital was affected by the following, during 2003:* We recognized

$960 million of impairment losses related to our unregulated investments while reducing our ratio of debt to total capital* WVe substantially reduced our short-term debt commitments, thereby reducing refinancing and cash flow risks* NVe improved our percentage of common equity outstanding to total capitalization, in part through the issuance of approximately $1.1 billion of new equity.Liquidity Liquidity, or access to cash, is an important factor in determining our financial stability due to volatility in wholesale power prices and the effects of credit rating downgrades. NVe are committed to preserving an adequate liquidity position.Credit Facilities WVe manage our liquidity by maintaining adequate external financing commitments. NVe had an available liquidity position of approximately $3.5 billion as illustrated in the table below: Amount Maturity (in millions)Commercial Paper Backup: Lines of Credit $ 750 May 2004 Lines of Credit 1,000 May 2005 Lines of Credit 750 May 2006 Euro Revolving Credit Facility 189 October 2004 Letter of Credit Facility 200 September 2006 Total 2,889 Available Cash and Temporary Investments 920*Total Liquidity Sources 3,809 Less: AEP Commercial Paper Outstanding 282**Letters of Credit Outstanding 35 Net Available Liquidity MM* Available Cash and Temporary Investments of $920 million and $262 million in unavailable cash on hand make up the $1.2 billion Cash and Cash Equivalents balance on our Consolidated Balance Sheet at December 31, 2003.** Amount does not include JMG Funding LP (JMG) commercial paper outstanding in the amount of $26 million. This commercial paper is specifically associated with the Gavin scrubber lease. This commercial paper does not reduce available liquidity to AEP.A-9 Debt Covenants Our revolving credit agreements require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating our outstanding debt and other capital is contractually defined. At December 31, 2003, this percentage was 58.8%. Non-performance of these covenants may result in an event of default under these credit agreements. At December 31, 2003, we complied with the covenants contained in these credit agreements. In addition, the acceleration of the payment obligations of us, or certain of our subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million would cause an event of default under these credit agreements and permit the lenders to declare the amounts outstanding thereunder payable.Our commercial paper backup facilities generally prohibit new borrowings if we experience a material adverse change in our business or operations. We may, however, make new borrowings under these facilities if we experience a material adverse change so long as the proceeds of such borrowings are used to repay outstanding commercial paper.Under an SEC order, AEP and its utility subsidiaries cannot incur additional indebtedness if the issuer's common equity would constitute less than 30% (25% for TCC due to its securitization bonds) of its capital. In addition, this order restricts AEP and the utility subsidiaries from issuing long-term debt unless that debt will be rated investment grade by at least one nationally recognized statistical rating organization. Dividend Restrictions Provisions within the Articles of Incorporation relating to the preferred stock of certain of our subsidiaries restrict the payment of cash dividends or other distributions on their common and preferred stock. PUHCA prohibits our subsidiaries from making loans or advances to the parent company, AEP. In addition, under PUHCA, AEP and its public utility subsidiaries can only pay dividends out of retained or current earnings.Credit Ratings We also manage our liquidity by continuing to maintain investment grade credit ratings and a stable credit outlook and are taking steps to improve our credit quality, including plans during 2004 to further reduce our outstanding debt through the use of proceeds from the planned dispositions. If we receive a downgrade in our credit ratings by these agencies, our borrowing costs could increase. The rating agencies currently have AEP and our rated subsidiaries on stable outlook. Current ratings for AEP are as follows: Moody's S&P Fitch AEP Short-Terrn Debt P-3 A-2 F-2 AEP Senior Unsecured Debt Baa3 BBB BBB Cash Flow Our cash flows are a major factor in managing and maintaining our liquidity strength.2003 2002 2001 (in millions)Cash and Cash Equivalents at Beginning of Period $1,199 $194 $232 Net Cash Flows From Operating Activities 2,308 2,067 2,818 Net Cash Flows Used For Investing Activities (1,888) (378) (3,292)Net Cash Flows (Used For) From Financing Activities (437) (681) 437 Effect of Exchange Rate Changes on Cash -(3) (1)Net Increase (Decrease) in Cash and Cash Equivalents (17) 1,005 (38)Cash and Cash Equivalents at End of Period $L1J2 ,$1,, Cash from operations, combined with a bank-sponsored receivables purchase agreement and short-term borrowings provide working capital and meet other short-term cash needs. We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries. The corporate borrowing program includes a utility money pool A-1 0 which funds the utility subsidiaries and a non-utility money pool which funds the majority of the non-utility subsidiaries. In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in the non-utility money pool for regulatory or operational reasons. As of December 31, 2003, we had credit facilities totaling $2.9 billion to support our commercial paper program. We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding mechanisms are arranged. Sources of long-term funding include issuance of common stock, preferred stock or long-term debt and sale-leaseback or leasing agreements. Money pool and external borrowings may not exceed SEC authorized limits.Operating Activities 2003 2002 2001 (in millions)Net Income (Loss) $110 $(519) $971 Plus: Discontinued Operations 605 654 (41)Income from Continuing Operations 715 135 930 Noncash Items Included in Earnings 1,798 2,734 976 Changes in Assets and Liabilities (205) (802) 912 Net Cash Flows From Operating Activities S2,39B $2.06 $2ij 2003 Operating Cash Flow Our cash flows from operating activities were $2.3 billion for 2003. We produced income from continuing operations of $715 million during the period. Income from continuing operations for 2003 included noncash items of $1.5 billion for depreciation, amortization, and deferred taxes, $193 million for the cumulative effects of accounting changes, and $720 million for impairment losses and other related charges. In addition, there is a current period impact for a net $122 million balance sheet change for risk management contracts that are marked-to-market. These contracts have an unrealized earnings impact as market prices move, and a cash impact upon settlement or upon disbursement or receipt of premiums. Changes in Assets and Liabilities represent those items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant are presented below:* The wholesale capacity auction true-up (ECOM) resulted in stranded cost deferrals of $218 million, which are not recoverable in cash until the conclusion of our Texas true-up proceeding. These proceedings are not expected to be finalized earlier than April 2005.* Net changes in accounts receivable and accounts payable of $269 million related, in large part, to the settlement of risk management positions during 2002 and payments related to those settlements during 2003.These payments include $90 million in settlement of power and gas transactions to the Williams Companies. The earnings effects of substantially all payments were reflected in earlier periods.* Increases in inventory levels of $71 million resulting primarily from higher procurement prices.* Reserves for disallowed fuel costs, principally related to Texas, which will be a component of our 2004 final Texas true-up order of the PUCT.2002 Operating Cash Flow During 2002, our cash flows from operating activities were $2.1 billion. Income from continuing operations was$135 million during the period. Income from continuing operations for 2002 included noncash items of $1.4 billion for depreciation, amortization, and deferred taxes, $350 million related to the cumulative effect of an accounting change, and $639 million for impairment losses. There was a current period impact for a net $275 million balance sheet change for risk management contracts that were marked-to-market. These contracts have an unrealized earnings impact as market prices move, and a cash impact upon settlement or upon disbursement or receipt of premiums. The activity in the asset and liability accounts related to the wholesale capacity auction true-up asset (ECOM) of $262 million, deposits associated with risk management activities of $136 million, and seasonal increases in our fuel inventories. A-11 2001 Operating Cash Flow Our cash flows from operating activities were $2.8 billion for 2001. Income from continuing operations was $930 million during the period. Income from continuing operations for 2001 included noncash items of $1.5 billion for depreciation, amortization, and deferred taxes, and $18 million related to the cumulative effect of an accounting change. There was a current period impact for a net $294 million balance sheet change for risk management contracts that were marked-to-market. These contracts have an unrealized earnings impact as market prices move, and a cash impact upon settlement or upon disbursement or receipt of premiums. The activity in the asset and liability accounts was primarily attributable to increased levels of trading activities as compared to 2002 and 2003. During the fourth quarter of 2002 we exited trading that was not related to the sale of power from our owned-generation. Inmvesting Activities 2003 2002 2001 (in millions)Construction Expenditures $(1,358) $(1,685) $(1,646)Business Acquisitions/Sales Proceeds, net 82 1,263 (621)Other (612) 44 (1,025 Net Cash Flows Used for Investing Activities $R888) 1n$Our cash flowvs used for investing activities increased $1.5 billion in 2003 from $378 million during the prior year.This increase was due to additional sales proceeds in 2002 related to SEEBOARD, CitiPower, and the Texas REPs as wvell as increased investments in our U.K. operations during 2003. These increases were partially offset by a reduction of our capital expenditures in 2003 as compared to 2002.In 2002, our cash flows used for investing activities decreased $2.9 billion from 2001. This decrease resulted from the HPL and UK acquisitions during 2001 as well as the net increase in proceeds received from asset sales during 2002.We forecast $5.8 billion of construction expenditures for 2004-2006. FinancingActivities 2003 2002 2001 (in millions)Issuances of Equity Securities (common stock/equity units) $1,142 $990 $11 Issuances/Retirements of Debt, net (727) (868) 460 Retirement of Preferred Stock (9) (10) (5)Issuance/Retirement of Minority Interest (225) -744 Dividends (618) (793) (773)Net Cash Flows (Used for) From Financing Activities $(43) $(a1) $_437 Our cash flows used for financing activities decreased $244 million in 2003 from $681 million during the prior year.This decrease was due to additional proceeds from the issuance of common stock and the reduction of our common stock dividend in 2003.In 2002 we used $681 million for financing activities compared to $437 million provided by the same activities in 2001. The increase in cash used pertained primarily to the debt retirements that occurred in 2002.The following financing activities occurred during 2003 and 2002: Common Stock and Equity Units:* In March 2003, wve issued 56 million shares of common stock at $20.95 per share through an equity offering and received net proceeds of $1.1 billion (net of issuance costs of $36 million). We used the proceeds to pay down both short-term and long-term debt with the balance being held in cash.A-12

In June 2002, we issued 16 million shares of common stock at $40.90 per share and 6.9 million equity units at$50 per unit and received combined net proceeds of $979 million. We used the proceeds to pay down short-term debt and establish a cash liquidity reserve fund.Debt:* We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries.

The corporate borrowing program includes a utility money pool which funds the utility subsidiaries and a non-utility money pool which funds the majority of the non-utility subsidiaries. In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in the non-utility money pool for regulatory or operational reasons. As of December 31, 2003, we had credit facilities totaling $2.9 billion to support our commercial paper program. At December 31, 2003, we had $282 million outstanding in short-term borrowings supported by these credit facilities. In addition, JMG has commercial paper outstanding in the amount of $26 million. This commercial paper is specifically associated with the Gavin scrubber lease. This commercial paper does not reduce available liquidity.

In February 2003, we issued over $2 billion of senior notes through our Ohio and Texas subsidiaries.

The proceeds were used to repay the bank facility that was due to mature in April 2003, retire short-term debt and for other general corporate purposes. During the remainder of the year, our subsidiaries issued an additional $2.3 billion in senior notes and refinanced approximately $465 million in pollution control revenue bonds.The proceeds of these issuances were used to term-out short-term debt, fund long-term debt maturities and fund optional redemptions.

In March 2003, AEP issued a $500 million senior unsecured note. The proceeds of this issuance wvere used to pay-down $225 million of the Steelhead financing and to prefund a portion of the AEP Resources bond that matured in December 2003.* In May 2003, a third party exercised its option to call our $250 million of 5.50% putable callable notes, issued in May 2001, for purchase and remarketing.

On May 15, 2003, AEP issued $300 million of 5.25% senior notes due 2015, a portion of which was an exchange for the $250 million putable callable notes due in 2003 that were outstanding at that time.* AEP Credit extended its sale of receivables agreement from its May 28, 2003 expiration to July 25, 2003, when the agreement was renewed for an additional 364 days. The sale of receivables agreement, which expires on July 23, 2004, provides commitments of $600 million to purchase receivables from AEP Credit.At December 31, 2003, $385 million of commitments to purchase accounts receivable were outstanding under the receivables agreement. All receivables sold represent affiliate receivables. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivable less an allowance for anticipated uncollectible accounts.* In September 2003, we closed on a $200 million revolving loan and letter of credit facility. The facility is available for the issuance of letters of credit and for general corporate purposes. The facility will expire in September 2006.Minority Interest and Off-balance Sheet Arranpements We enter into minority interest and off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties. The following identifies significant minority interest and off-balance sheet arrangements: AMinority Interest in Finance Subsidiary We formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis Partners, LLC (Caddis) in August 2001. SubOne is a wholly-owned consolidated subsidiary that was capitalized with the assets of Houston Pipe Line Company and Louisiana Intrastate Gas Company and $321.4 million of AEP Energy Services Gas Holding Company A-13 (AEP Gas Holding is a subsidiary of AEP and the parent of SubOne) preferred stock, that was convertible into our common stock at market price on a dollar-for-dollar basis. Caddis was capitalized with $2 million cash and a subscription agreement that represents an unconditional obligation to fund $83 million from SubOne for a managing member interest and $750 million from Steelhead Investors LLC (Steelhead) for a non-controlling preferred member interest. SubOne is the managing member of Caddis. As a result SubOne and all of its subsidiaries, including Caddis, HPL and LIG, are included in our Consolidated financial statements. Steelhead is an unconsolidated special purpose entity and had an original capital structure of $750 million (currently approximately $525 million) of which 3% is equity from investors with no relationship to us or any of our subsidiaries and 97% is debt from a syndicate of banks. The $525 million invested in Caddis by Steelhead w as loaned to SubOne.The loan to SubOne is due August 2006. Net proceeds from the planned sale of LIG will be used to reduce the outstanding balance of the loan from Caddis.On July 1, 2003, due to the application of FIN 46, we deconsolidated Caddis, which included amounts previously reported as Minority Interest in Finance Subsidiary ($759 million at December 31, 2002 and $533 million at June 30, 2003). As a result, a $527 million note payable to Caddis is part of our Long-Term Debt at December 31, 2003.Application of FIN 46 is prospective and we, therefore, did not change the presentation of Minority Interest in Finance Subsidiary in periods prior to July 1, 2003.On May 9, 2003, we reduced the outstanding balance of our note payable to Caddis by $225 million. Caddis used these proceeds to reduce the preferred interest in Caddis that was held by Steelhead. This payment eliminated the convertible preferred stock of AEP Gas Holding which under certain conditions had been convertible to AEP stock.The credit agreement between Caddis and SubOne contains covenants that restrict certain incremental liens and indebtedness, asset sales, investments, acquisitions, and distributions. The credit agreement also contains covenants that impose minimum financial ratios. Non-performance of these covenants may result in an event of default under the credit agreement. Through December 31, 2003, SubOne has complied with the covenants contained in the credit agreement. In addition, the acceleration of our outstanding debt in excess of $50 million would be an event of default under the credit agreement. SubOne has deposited $422 million in a cash reserve fund in order to comply with certain covenants in the credit agreement. Pursuant to the terms of the credit agreement, SubOne subsequently loaned these funds to affiliates, and we guaranteed the repayment obligations of these affiliates. These loans must be repaid in the event our credit ratings fall below investment grade.Steelhead has certain rights as a preferred member in Caddis. Upon the occurrence of certain events, including a default in the payment of the preferred return, Steelhead's rights include forcing a liquidation of Caddis and acting as the liquidator. Liquidation of Caddis could negatively impact our liquidity. AEP Credil AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140, allowing the receivables to be taken off of AEP Credit's balance sheet and allowing AEP Credit to repay any debt obligations. AEP has no ownership interest in the commercial paper conduits and does not consolidate these entities in accordance with GAAP. We continue to service the receivables. This off-balance sheet transaction was entered into to allow AEP Credit to repay its outstanding debt obligations, continue to purchase the AEP operating companies' receivables, and accelerate its cash collections. AEP Credit extended its sale of receivables agreement to July 25, 2003 from its May 28, 2003 expiration date. The agreement was then renewed for an additional 364 days and now expires on July 23, 2004. This new agreement provides commitments of $600 million to purchase receivables from AEP Credit. At December 31, 2003, $385 million was outstanding. As collections from receivables sold occur and are remitted, the outstanding balance for sold receivables is reduced and as new receivables are sold, the outstanding balance of sold receivables increases. All of the receivables sold represented affiliate receivables. AEP Credit maintains a retained interest in the receivables sold A-14 and this interest is pledged as collateral for the collection of the receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivables less an allowance for anticipated uncollectible accounts.RocAport Plant U0it 2 AEGCo and l&M entered into a sale and leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated unconsolidated trustee for Rockport Plant Unit 2 (the plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and certain institutional investors. The future minimum lease payments for each respective company are $1.4 billion.The FASB and other accounting constituencies continue to interpret the application of FIN 46 (revised December 2003) (FIN 46R). As a result, we are continuing to review the application of this new interpretation as it relates to the Rockport Plant Unit 2 transaction. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the plant and leases it to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the lease footnote. The lease term is for 33 years with potential renewal options.At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the plant. Neither AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and none of these entities guarantee its debt.Railcars In June 2003, we entered into an agreement with an unrelated, unconsolidated leasing company to lease 875 coal-transporting aluminum railcars. The lease has an initial term of five years and may be renewed for up to three additional five-year terms, for a maximum of twenty years. We intend to renew the lease for the full twenty years.At the end of each lease term, we may (a) renew for another five-year term, not to exceed a total of twenty years, (b)purchase the railcars for the purchase price amount specified in the lease, projected at the lease inception to be the then fair market value, or (c) return the railcars and arrange a third party sale (return-and-sale option). The lease is accounted for as an operating lease with the future payment obligations included in the annual lease footnote. This operating lease agreement allows us to avoid a large initial capital expenditure, and to spread our railcar costs evenly over the expected twenty-year usage.Under the lease agreement, the lessor is guaranteed that the sale proceeds under the return-and-sale option discussed above will equal at least a lessee obligation amount specified in the lease, which declines over time from approximately 86% to 77% of the projected fair market value of the equipment. At December 31, 2003, the maximum potential loss was approximately $31.5 million ($20.5 million net of tax) assuming the fair market value of the equipment is zero at the end of the current lease term. The railcars are subleased for one year to an unaffiliated company under an operating lease. The sublessee may renew the lease for up to four additional one-year terms. AEP has other railcar lease arrangements that do not utilize this type of financing structure. A-15 Summar Obligation Information Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2003: Payments Due by Period (in millions)Contractual Cash Obliioations Less Than 1 year 2-3 years 4-5 years After 5 Vears Total Long-term Debt Short-term Debt Preferred Stock Subject to Mandatory Redemption Capital Lease Obligations Unconditional Purchase Obligations (a)Noncancellable Operating Leases Total$1,779 326 63 1,720 291$4129$3,460 $1,711$7,151 $14,101-326 77 2,132 492$6X1d 21 49 55 31 76 220 6,738 3.555$20L 1,101 441 a323 1,785 2.331$SL353 (a) Represents contractual obligations to purchase coal and natural gas as fuel for electric generation along with related transportation of the fuel.Some of the transactions, described under "Minority Interest and Off-Balance Sheet Arrangements" above, include contractual cash obligations reported in the above table. The lease of Rockport Unit 2 and Railcars are reported in Noncancellable Operating Leases. The Minority Interest in Finance Subsidiary is reported in Long-term Debt.In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business. These commitments include standby letters of credit, guarantees for the payment of obligation performance bonds, and other commitments. Our commitments outstanding at December 31, 2003 under these agreements are summarized in the table below: Amount of Commitment Expiration Per Period (in millions)Other Commercial Commitments Less Than 1 year 2-3 years 4-5 years After 5 years Total Standby Letters of Credit (a)Guarantees of the Performance of Outside Parties (b)Guarantees of our Performance Transmission Facilities for Third Parties (c)Other Commercial Commitments (d)Total Commercial Commitments $175 1,083 99 14$1,371$43$9 $227 18 107 110 I 134 8 153 1,198 54 263 14 28$151 $1,869 (a) We have issued standby letters of credit to third parties. These letters of credit cover gas and electricity risk management contracts, construction contracts, insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. All of these letters of credit were issued in the ordinary course of business. The maximum future payments of these letters of credit are$227 million with maturities ranging from January 2004 to January 2011. As the parent of all of these subsidiaries, we hold all assets of the subsidiaries as collateral. There is no recourse to third parties in the event these letters of credit are drawn.(b) These amounts are the balances drawn, not the maximum guarantee disclosed in Note 8.A-16 (c) As construction agent f6r third party owners of transmission facilities, we have committed by contract terms to complete construction by dates specified in the contracts. Should we default on these obligations, financial payments could be required including liquidating damages of up to $8 million and other remedies required by contract terms.(d) OPCo has entered into a 30-year power purchase agreement for electricity produced by an unaffiliated entity's three-unit natural gas fired plant. The plant was completed in 2002 and the agreement will terminate in 2032. Under the terms of the agreement, OPCo has the option to run the plant until December 31, 2005, taking 100% of the power generated and making monthly capacity payments.The capacity payments are fixed through December 2005 at $1.2 million per month. For the remainder of the 30-year contract term, OPCo will pay the variable costs to generate the electricity it purchases which could be up to 20% of the plant's capacity.Expenditures for domestic electric utility construction are estimated to be $5.8 billion for the next three years.Approximately 80% of those construction expenditures is expected to be financed by internally generated funds.Other Polymer Generation Facility We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop, construct, and finance a non-regulated merchant power generation facility (Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to us. -The Facility is a "qualifying cogeneration facility" for purposes of PURPA. Construction of the Facility was begun by Katco Funding, Limited Partnership (Katco), an unrelated unconsolidated special purpose entity. Katco assigned its interest in the Facility to Juniper in June 2003.Juniper is an unaffiliated limited partnership, formed to construct or otherwise acquire real and personal property for lease to third parties, to manage financial assets and to undertake other activities related to asset financing.. Juniper arranged to finance the Facility with debt financing up to $494 million and equity up to $31 million from investors with no relationship to AEP or any of AEP's subsidiaries. Juniper wvill own the Facility and lease it to AEP after construction is completed. At December 31, 2002, we would have reported the Facility and related obligations as an operating lease upon achieving commercial operation (COD). In the fourth quarter of 2003, we chose to not seek funding from Juniper for budgeted and approved pipeline construction costs related to the Facility. In order to continue reporting the Facility as an off-balance sheet financing, we were required to seek funding of our construction costs from Juniper. As a result, we recorded $496 million of construction work in progress (CWIP) and the related financing liability for the debt and equity as of December 31, 2003. At December 31, 2003, the lease of the Facility is reported as an owned asset under a lease financing transaction. Since the debt obligations of the Facility are recorded on our financial statements, the obligations under the lease agreement are excluded from the above table of future minimum lease payments.We are the construction agent for Juniper. WVe expect to achieve COD in the spring of 2004, at which time the obligation to make payments under the lease agreement will begin to accrue and we will sublease the Facility to The Dow Chemical Company (Dow). If COD does not occur on or before March 14, 2004, Juniper has the right to terminate the project. In the event the project is terminated before COD, we have the option to either purchase the Facility for 100% of Juniper's acquisition cost (in general, the outstanding debt and equity associated with the Facility) or terminate the project and make a payment to Juniper for 89.9% of project costs (in general, the acquisition cost less certain financing costs).The initial term of the lease agreement between Juniper and AEP commences on COD and continues for five years.The lease contains extension options, and if all extension options are exercised, the total term of the lease will be 30 years. AEP's lease payments to Juniper during the initial term and each extended term are sufficient for Juniper to make required debt payments under Juniper's debt financing associated with the Facility and provide a return on equity to the investors in Juniper. We have the right to purchase the Facility for the acquisition cost during the last month of the initial term or on any monthly rent payment date during any extended term. In addition, we may purchase the Facility from Juniper for the acquisition cost at any time during the initial term if we have arranged a A-17 sale of the Facility to an unaffiliated third party. A purchase of the Facility from Juniper by AEP should not alter Dow's rights to lease the Facility or our contract to purchase energy from Dow. If the lease were renewed for up to a 30-year lease term, 'we may further renew the lease at fair market value subject to Juniper's approval, purchase the Facility at its acquisition cost, or sell the Facility, on behalf of Juniper, to an independent third party. If the Facility is sold and the proceeds from the sale are insufficient to pay all of Juniper's acquisition costs, 'we may be required to make a payment (not to exceed $396 million) to Juniper of the excess of Juniper's acquisition costs over the proceeds from the sale, provided that we would not be required to make any payment if we have made the additional rental prepayment described below. We have guaranteed the performance of our subsidiaries to Juniper during the lease term. Because we now report the debt related to the Facility on our balance sheet, the fair value ofthe liability for our guarantee (the $396 million payment discussed above) is not separately reported.At December 31, 2003, Juniper's acquisition costs for the Facility totaled $496 million, and total costs for the completed Facility are currently expected to be approximately $525 million. For the 30-year extended lease term, the base lease rental is a variable rate obligation indexed to three-month LIBOR. Consequently, as market interest rates increase, the base rental payments under the lease will also increase. Annual payments of approximately $18 million represent future minimum payments for interest on Juniper's financing structure during the initial term calculated using the indexed LIBOR rate (1.15% at December 31, 2003). An additional rental prepayment (up to $396 million)may be due on June 30, 2004 unless Juniper has refinanced its present debt financing on a long-term basis. Juniper is currently planning to refinance by June 30, 2004. The Facility is collateral for the debt obligation of Juniper. At December 31, 2003, we reflected $396 million of the $496 million recorded obligation as long-term debt due within one year. Our maximum required cash payment as a result of our financing transaction with Juniper is $396 million as well as interest payments during the lease term. Due to the treatment of the Facility as a financing of an owned asset, the recorded liability of $496 million is greater than our maximum possible cash payment obligation to Juniper.Dow will use a portion of the energy produced by the Facility and sell the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow. OPCo has also agreed to sell up to approximately 800 MWV of energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in excess of market.Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as non-conforming. On September 5, 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. We allege that TEM has breached the PPA, and we are seeking a determination of our rights under the PPA. TEM alleges that the PPA never became enforceable, or alternatively, that the PPA has already been terminated as the result of AEP breaches. If the PPA is deemed terminated or found to be unenforceable by the court, we could be adversely affected to the extent we are unable to find other purchasers of the power with similar contractual terms to the extent we do not fully recover claimed termination value damages from TEM. The corporate parent of TEM has provided a limited guaranty.On November 18, 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols relating to the dispatching, operation, and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM basically argued that in the absence of mutually agreed upon protocols there was no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the "creation of protocols" was not subject to arbitration, but did not rule upon the merits of TEM's claim that the PPA is not enforceable. If commercial operation is not achieved for purposes of the PPA by April 30, 2004, TEM may claim that it can terminate the PPA and is owed liquidating damages of approximately $17.5 million. TEM may also claim that we are not entitled to receive any termination value for the PPA.The current litigation between TEM and ourselves, combined with a substantial oversupply of generation capacity in the markets where we would otherwise sell the power freed up by the TEM contract termination, triggered us to review the project for possible impairment of its reported values. We determined that the value of the Facility was impaired and recorded a $258 million pre-tax impairment in December 2003 on the CWIP.A-18 SIGNIFICANT FACTORS Possible Divestitures We are firmly committed to continually evaluating the need to reallocate resources to areas that effectively match our investments with our business strategy, providing the greatest potential for financial returns. We are committed to disposing of investments that no longer meet these goals.We are seeking to divest significant components of our non-regulated assets, including certain domestic and international unregulated generation, part of our gas pipeline and storage business, a coal business, independent power producers (IPPs) and a communications business. In June 2003, we began actively seeking buyers for 4,497 megawatts of unregulated generating capacity in Texas. The value received from this disposition wvill also be used to calculate our stranded costs in Texas (see Note 6). We are currently evaluating bids received during the fourth quarter of 2003 and are in negotiations to sell these assets.During the second quarter of 2003, we also hired an advisor to evaluate our coal business, which has resulted in the receipt of non-binding bids. We are currently negotiating the anticipated sale of certain assets from this business. In the fourth quarter of 2003, in connection with the evaluation of this business, we recorded a $66.6 million pre-tax charge related to asset impairments, remediation accruals and other exit costs (see Note 10).During the third quarter of 2003, management hired advisors to review business options regarding various investment components of our Gas Operations. We distributed an initial offering memorandum and request for proposal on the sale of our Louisiana Intrastate Gas and Jefferson Island Storage Facility operations during the fourth quarter of 2003.We are currently evaluating the proposals that we received. We are evaluating the merits of retaining our interest in Houston Pipe Line, which is part of Gas Operations. In connection with our review of the Gas Operations, we recorded $133.9 million in pre-tax charges related to LIG and $315 million in pre-tax charges related to HPL (see Note 10). WVe signed a sale agreement for the pipeline portion of LIG in the first quarter of 2004 and we expect the sale to close shortly with an immaterial impact on 2004 results of operations. During the third quarter of 2003, we initiated an effort to sell four domestic IPP investments. Based on studies using current market assumptions, we believe that two of the facilities had declines in fair value that are other than temporary in nature. As a consequence, we recorded an impairment of $70 million pre-tax ($45.5 million net of tax)in the third quarter of 2003 (see Note 10). During the fourth quarter of 2003, we distributed an information memorandum related to the possible sale of our interest in these IPPs. We have received and are reviewing final bids and anticipate a sale of the four domestic IPP investments in 2004.During the fourth quarter of 2003, we engaged an advisor for the disposition of our U.K. business and are planning to dispose of these assets in 2004. In connection with the evaluation of this business, we recorded a pre-tax charge of$577.4 million during the fourth quarter of 2003 based on indications of value received from potential buyers (see Note 10).Management continues to have periodic discussions with various parties on business alternatives for certain of our other non-core investments. The ultimate timing for a disposition of one or more of these assets will depend upon market conditions and the value of any buyer's proposal. We may realize losses from operations or upon disposition of these assets that, in the aggregate, could have a material impact on our results of operations, cash flows and financial condition. Corporate Separation In Texas, we are in the process of divesting our TCC generating assets in accordance with provisions of the Texas Legislation concerning stranded cost recovery (see Note 6). In order to sell these assets, we anticipate retiring TCC's first mortgage bonds by making open market purchases or defeasing the bonds. Once such generating assets are sold, which we expect to be finalized in 2004, we will effectively accomplish the structural separation requirements of the Texas Legislation for those assets.A-19 In Ohio, the PUCO has encouraged utilities to file rate stabilization plans to provide rate certainty and stability for customers who do not choose alternative suppliers, for the period of January 1, 2006 through December 31, 2008, which is after the expiration of the current market development period. On February 9, 2004, CSPCo and OPCo filed such a rate stabilization plan with the PUCO. The plan, in part, provides that both CSPCo and OPCo will remain functionally separated. Approval of the rate stabilization plan is currently pending before the PUCO.Unless otherwise directed by the PUCO in an order on the rate stabilization plan, CSPCo and OPCo will remain functionally separated through at least the end of the rate stabilization plan period, December 31, 2008, and therefore, are not planning to legally separate, or to change the affiliate pooling agreement for the AEP East companies, in the foreseeable future.Management continues to evaluate the most appropriate approach for complying with the Texas Legislation's structural separation requirements for TNC, including appropriate regulatory approvals to implement its structural separation. RTO Formation The FERC's AEP-CSW merger approval and many of the settlement agreements with the state regulatory commissions to approve the AEP-CSW merger required the transfer of functional control of our subsidiaries' transmission systems to RTOs. Further, legislation in some of our states requires RTO participation. In May 2002, we announced an agreement with PJM to pursue terms for participation in its RTO for AEP East companies with final agreements to be negotiated. In July 2002, FERC issued an order accepting our decision to participate in PJM, subject to specified conditions. AEP and other parties continue to work on the resolution of those conditions. In December 2002, our subsidiaries that operate in the states of Indiana, Kentucky, Ohio and Virginia filed for state regulatory commission approval of their plans to transfer functional control of their transmission assets to PJM.Proceedings in Ohio remain pending.In February 2003, the state of Virginia enacted legislation preventing APCo from joining an RTO prior to July 1, 2004 and thereafter only with the approval of the Virginia SCC, but required such transfers by January 1, 2005. In January 2004, APCo filed a cost/benefit study with the Virginia SCC covering the time period through 2014 as required by the Virginia SCC. The study results show a net benefit of approximately $98 million for APCo over the I I-year study period from AEP's participation in PJM.In July 2003, the KPSC denied KPCo's request to join PJM based in part on a lack of evidence that it would benefit Kentucky retail customers. In December 2003, AEP filed with the KPSC a cost/benefit study showing a net benefit of approximately $13 million for KPCo over the five-year study period from AEP's participation in PJM. A hearing has been scheduled in April 2004.In September 2003, the IURC issued an order approving I&M's transfer of functional control over its transmission facilities to PJM, subject to certain conditions included in the order. The IURC's order stated that AEP shall request and the IURC shall complete a review of Alliance formation costs before any deferral of the costs for future recovery.In April 2003, FERC approved our transfer of functional control of the AEP East companies' transmission system to PJM. FERC also accepted our proposed rates for joining PJM, but set a number of rate issues for resolution through settlement proceedings or FERC hearings. Settlement discussions continue on certain rate matters.On September 29 and 30, 2003, the FERC held a public inquiry regarding RTO formation, including delays in AEP's participation in PJM. In November 2003, the FERC issued an order preliminarily finding that AEP must fulfill its CSWV merger commitment to join an RTO by fully integrating into PJM (transmission and markets) by October 1, 2004. The FERC set several issues for public hearing before an ALJ. Those issues include whether the lawvs, rules, or regulations of Virginia and Kentucky are preventing AEP from joining an RTO and whether the states' provisions meet either of the two exceptions under PURPA. The FERC directed the ALI to issue his initial decision by March 15, 2004.A-20 If AEP East companies do not obtain regulatory approval to join PJM, wve are committed to reimburse PJM for certain project implementation costs (presently estimated at $24 million for AEP's share of the entire PJM integration project). AEP also has $28 million, at December 31, 2003, of deferred RTO formation/integration costs for which we plan to seek recovery in the future. See Note 4 for further discussion. AEP West companies are members of ERCOT or SPP. In 2002, FERC conditionally accepted filings related to a proposed consolidation of MISO and SPP. State public utility commissions also regulate our SPP companies. The Louisiana and Arkansas commissions filed responses to the FERC's RTO order indicating that additional analysis was required. Subsequently, the proposed SPP/MISO combination was terminated. On October 15, 2003, SPP filed a proposal at FERC for recognition as an RTO. In February 2004, FERC granted RTO status to the SPP, subject to fulfilling specified requirements. Regulatory activities concerning various RTO issues are ongoing in Arkansas and Louisiana. Management is unable to predict the outcome of these regulatory actions and proceedings or their impact on our transmission operations, results of operations and cash flows or the timing and operation of RTOs.Pension Plans We maintain qualified, defined benefit pension plans (Qualified Plans), which cover a substantial majority of non-union and certain union associates, and unfunded excess plans to provide benefits in excess of amounts permitted to be paid under the provisions of the tax law to participants in the Qualified Plans. Additionally, we have entered into individual retirement agreements with certain current and retired executives that provide additional retirement benefits.Our net periodic pension expense was an income item for all pension plans approximating $3 million and $44 million for the years ended December 31, 2003 and 2002, respectively, and is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on the Qualified Plans' assets. In 2002 and 2003, the long-term return was assumed to be 9.00%, and for 2004, the long-term rate of return was lowered to 8.75%. In developing the expected long-term rate of return assumption, we evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as wvell as long-term inflation assumptions. Projected returns by such actuaries and consultants are based on broad equity and bond indices. We also considered historical returns of the investment markets as well as our 10-year average return, for the period ended December 2003, of approximately 10.0%. We anticipate that the investment managers we employ for the pension fund will continue to generate long-term returns of at least 8.75%.The expected long-term rate of return on the Qualified Plan's assets is based on our targeted asset allocation and our expected investment returns for each investment category. Our assumptions are summarized in the following table: 2003 2004 Assumed/Expected Actual Target Long-term Rate Asset Allocation Asset Allocation of Return (in percentage) Equity 71 70 10.5 Fixed Income 27 28 5 Cash and Cash Equivalents

2. 22 2 Total *10 Overall Expected Return (weighted average)We regularly review the actual asset allocation and periodically rebalance the investments to our targeted allocation when considered appropriate.

We believe that 8.75% is a reasonable long-term rate of return on the Qualified Plans'assets despite the recent market volatility in which the Qualified Plans' assets had a loss of 11.2% for the twelve months ended December 31, 2002, and a gain of 23.8% for the twelve months ended December 31, 2003. We will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust them as necessary. A-21 We base our determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of December 31, 2003, we had cumulative losses of approximately $325 million which remain to be recognized in the calculation of the market-related value of assets. These unrecognized net actuarial losses result in increases in the future pension costs depending on several factors, including whether such losses at each measurement date exceed the corridor in accordance with SFAS No. 87, "Employers' Accounting for Pensions." The discount rate that we utilize for determining future pension obligations is based on a review of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. The discount rate determined on this basis has decreased from 6.75% at December 31, 2002, to 6.25% at December 31, 2003. Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on the Qualified Plans' assets of 8.75%, a discount rate of 6.25% and various other assumptions, we estimate that the pension expense for all pension plans will approximate $41 million, $78 million and $103 million in 2004, 2005 and 2006, respectively. Future actual pension cost ,vill depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the pension plans.Lowering the expected long-term rate of return on the Qualified Plans' assets by 0.5% (from 9.0% to 8.5%) would have increased pension cost for 2003 by approximately $18 million (income of $3 million would have become $15 million in pension expense). Lowering the discount rate by 0.5% would have reduced pension income for 2003 by approximately $0.5 million.The value of the Qualified Plans' assets has increased from $2.795 billion at December 31, 2002 to $3.180 billion at December 31, 2003. The Qualified Plans paid out $292 million in benefits to plan participants during 2003 (the nonqualified plans paid out $7 million in benefits). Our plans remain in an underfunded position (plan assets are less than projected benefit obligations) of $508 million at December 31, 2003. Due to the pension plans currently being underfunded, we recorded a charge to Other Comprehensive Income (OCI) of $585 million in 2002, and recorded a Deferred Income Tax Asset of $315 million, offset by a Minimum Pension Liability of $662 million and a reduction to prepaid costs and adjustment for unrecognized costs of $238 million. In 2003, the income recorded in OCI was$154 million, and the reduction in the Deferred Income Tax Asset was $76 million, offset by a reduction in Minimum Pension Liability of $234 million and a reduction to adjustment for unrecognized costs of $4 million. The charge to OCI does not affect earnings or cash flow. Due to the current underfunded status of the Qualified Plans, we expect to make cash contributions to the pension plans of approximately $41 million in 2004.Certain of the defined benefit pension plans we sponsor and maintain contain a cash balance benefit feature. In recent years, cash balance benefit features have become a focus of scrutiny, as government regulators and courts consider how the Employee Retirement Income Security Act of 1974, as amended, the Age Discrimination in Employment Act, as amended, and other relevant federal employment laws apply to plans with such a cash balance plan feature.We believe that the defined benefit pension plans we sponsor and maintain are in substantial compliance with the applicable requirements of such laws.Nuclear Plant Outages In April 2003, engineers at STP, during inspections conducted regularly as part of refueling outages, found wall cracks in two bottom mounted instrument guide tubes of STP Unit 1. These tubes were repaired and the unit returned to service in August 2003. Our share of the cost of repair for this outage was approximately $6 million. We had commitments to provide power to customers during the outage. Therefore, we were subject to fluctuations in the market prices of electricity and purchased replacement energy.In April 2003, both units of Cook Plant were taken offline due to an influx of fish in the plant's cooling water system which caused a reduction in cooling water to essential plant equipment. After repair of damage caused by the fish intrusion, Cook Plant Unit I returned to service in May and Unit 2 returned to service in June following completion of a scheduled refueling outage.A-22 Litigation Feleral EPA Complaint and Notice of Violation See discussion of the Federal EPA Complaint and Notice of Violation within "Significant Factors -Environmental Matters." Entron Bankruptcy On October 15, 2002, certain subsidiaries of AEP filed claims against Enron and its subsidiaries in the bankruptcy proceeding filed by the Enron entities which are pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron's bankruptcy, certain subsidiaries of AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased Houston Pipe Line Company (HPL) from Enron. Various HPL related contingencies and indemnities from Enron remained unsettled at the date of Enron's bankruptcy. The timing of the resolution of the claims by the Bankruptcy Court is not certain.In connection with the 2001 acquisition of HPL, we acquired exclusive rights to use and operate the underground Bammel gas storage facility pursuant to an agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron. This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years and includes the use of the Bammel storage facility and the appurtenant pipelines. We have engaged in discussions with Enron concerning the possible purchase of the Bammel storage facility and related assets, the possible resolution of outstanding issues between AEP and Enron relating to our acquisition of HPL and the possible resolution of outstanding energy trading issues. We have considered the possible outcomes of these issues in our impairment analysis of HPL; however, actual results could differ from those estimates. We are unable to predict whether these discussions will lead to an agreement on these subjects. In January 2004, AEP and its subsidiaries filed an amended lawsuit against Enron and its subsidiaries in the U.S. Bankruptcy Court claiming that Enron does not have the right to reject the Bammel storage facility agreement or the cushion gas use agreement, described below. In February 2004 Enron filed Notices of Rejection regarding the cushion gas use agreement and other incidental agreements. We have objected to Enron's attempted rejection of these agreements. Management is unable to predict the outcome of these proceedings or the impact on results of operations, cash flows or financial condition. We also entered into an agreement with BAM Lease Company which grants HPL the exclusive right to use approximately 65 billion cubic feet of cushion gas required for the normal operation of the Bammel gas storage facility. The Bamimel Gas Trust (owned by Enron and Bank of America (BOA)) purports to have a lien on 55 billion cubic feet of this cushion gas. These banks claim to have certain rights to the cushion gas in certain events of default.In connection with our acquisition of HPL, the banks and Enron entered into an agreement granting HPL's exclusive use of 65 billion cubic feet of cushion gas. Enron and the banks released HPL from all prior and future liabilities and obligations in connection with the financing arrangement. After the Enron bankruptcy, HPL was informed by the banks of a purported default by Enron under the terms of the financing arrangement. In July 2002, the banks filed a lawsuit against HPL in the state court of Texas seeking a declaratory judgment that they have a valid and enforceable security interest in gas purportedly in the Bammel storage facility which would permit them to cause the %vithdrawal of up to 55 billion cubic feet of gas from the storage facility. In September 2002, HPL filed a general denial and certain counterclaims against the banks including that Enron was a necessary and indispensable party to the Texas state court proceeding initiated by BOA. HPL also filed a motion to dismiss, which was denied. In December 2003, the Texas state court granted partial summary judgment in favor of the banks. HPL appealed this decision. We have considered the possible outcomes of these issues in our impairment analysis of HPL; however, actual results could differ from those estimates. Management is unable to predict the outcome of this lawsuit or its impact on results of operations, cash flows and financial condition. In October 2003, AEP Energy Services Gas Holding Company filed a lawsuit against BOA in the United States District Court for the Southern District of Texas. On January 8, 2004, this lawsuit wvas amended and seeks damages for BOA's breach of contract, negligent misrepresentation and fraud in connection with transactions surrounding our acquisition of HPL from Enron including entering into the Barnmel storage facility lease arrangement with Enron and the cushion gas arrangements with BOA and Enron. BOA led a lending syndicate involving the 1997 gas monetization that Enron and its subsidiaries undertook and the leasing of the Bammel underground gas storage reservoir to HPL. The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote A-23 the stock sale of HPL, that BOA directly benefited from the sale of HPL and that AEP undertook the stock purchase and entered into the Bammel storage facility lease arrangement with Enron and the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron's financial condition that BOA knew or should have known were false including that the 1997 gas monetization did not contravene or constitute a default of any federal, state, or local statute, rule, regulation, code or any law.In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP's offsetting of receivables and payables and related collateral across various Enron entities and seeking payment of approximately $125 million plus interest in connection with gas related trading transactions. WVe will assert our right to offset trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. Management is unable to predict the outcome of this lawsuit or its impact on our results of operations, cash flows or financial condition. In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron's claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. Management is unable to predict the outcome of this lawsuit or its impact on our results of operations, cash flows or financial condition. During 2002 and 2001, we expensed a total of $53 million ($34 million net of tax) for our estimated loss from the Enron bankruptcy. The amount expensed was based on an analysis of contracts where AEP and Enron entities are counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities and management's analysis of the HPL related purchase contingencies and indemnifications. As noted above, Enron has challenged our offsetting of receivables and payables and the Bammel storage facility lease agreement and cushion gas agreement. Management is unable to predict the final resolution of these disputes, however the impact on results of operations, cash flows and financial condition could be material.Bank of Aontreal Claim In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals and claimed that we owed approximately $34 million. In April 2003, we filed a lawsuit against BOM claiming BOM had acted contrary to the appropriate trading contract and industry practice in terminating the contract and calculating termination and liquidation amounts and that BOM had acknowledged just prior to the termination and liquidation that it owed us approximately $68 million. We are claiming that BOM owes us at least $45 million. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition. Arbitration of Jillifams Claim In 2002, we filed a demand for arbitration with the American Arbitration Association to initiate formal arbitration proceedings in a dispute with the Williams Companies (Williams). The proceeding results from Williams'repudiation of its obligations to provide physical power deliveries to AEP and Williams' failure to provide the monetary security required for natural gas deliveries. AEP and Williams settled the dispute with AEP paying $90 million to Williams in June 2003. The settlement amount approximated the amount payable that, in the ordinary course of business, we recorded as part of our trading activity using MTM accounting. As a result, the resolution of this matter had an immaterial impact on results of operations and financial condition. See Note 7 for further discussion. Arbitration of PG&E Energy Trading, LLC Claim In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately $22 million was owed by AEP in connection with the termination and liquidation of all trading deals. In February 2003, PGET initiated arbitration proceedings. In July 2003, AEP and PGET agreed to a settlement with AEP paying approximately $11 million to PGET. The settlement amount approximated the amount payable that, in the ordinary course of business, we recorded as part of our trading activity using MTM accounting. As a result, the settlement payment did not have a material impact on results of operations, cash flows or financial condition. A-24 Energy AMarket Iniiestigations AEP and other energy market participants received data requests, subpoenas and requests for infornation from the FERC, the SEC, the PUCT, the U.S. Commodity Futures Trading Commission (CFTC), the U.S. Department of Justice and the California attorney general during 2002. Management responded to the inquiries and provided the requested information and has continued to respond to supplemental data requests in 2003 and 2004.In March 2003, -we received a subpoena from the SEC as part of the SEC's ongoing investigation of energy trading activities. In August 2002, we had received an informal data request from the SEC seeking that we voluntarily provide information. The subpoena sought additional information and is part of the SEC's formal investigation. We responded to the subpoena and will continue to cooperate with the SEC.On September 30, 2003, the CFTC filed a complaint against AEP and AEPES in federal district court in Columbus, Ohio. The CFTC alleges that AEP and AEPES provided false or misleading information about market conditions and prices of natural gas in an attempt to manipulate the price of natural gas in violation of the Commodity Exchange Act.The CFTC seeks civil penalties, restitution and disgorgement of benefits. The case is in the initial pleading stage with our response to the complaint currently due on May 18, 2004. Although management is unable to predict the outcome of this case, we recorded a provision in 2003 and the action is not expected to have a material effect on results of operations. In January 2004, the CFTC issued a request for documents and other information in connection with a CFTC investigation of activities affecting the price of natural gas in the fall of 2003. We are responding to that request.Management cannot predict what, if any further action, any of these governmental agencies may take with respect to these matters.Sharehoklers 'Litigation In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty for failure to establish and maintain adequate internal controls and violations of the Employee Retirement Income Security Act were filed against us, certain executives, members of the Board of Directors and certain investment banking firms. We intend to vigorously defend against these actions. See Note 7 for further discussion. California Lawsuit In 2002, the Lieutenant Governor of Califomia filed a lawsuit in California Superior Court against forty energy companies, including AEP, and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP has been dismissed from the case. See Note 7 for further discussion. Cornerstone Lawsuit In the third quarter of 2003, Cornerstone Propane Partners filed an action in the United States District Court for the Southern District of New York against forty companies, including AEP and AEPES seeking class certification and alleging unspecified damages from claimed price manipulation of natural gas futures and options on the NYMEX from January 2000 through December 2002. Shortly thereafter, a similar action was filed in the same court against eighteen companies including AEP and AEPES making essentially the same claims as Cornerstone Propane Partners and also seeking class certification. These cases are in the initial pleading stage. Management believes that the cases are without merit and intends to vigorously defend against them.TEMLitigation See discussion of TEM litigation within the "Financial Condition -Other" section of Management's Financial Discussion and Analysis.A-25 Texas Conmmercial EneriU LLP Lanwsit Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit against us and four AEP subsidiaries, certain unaffiliated energy companies and ERCOT alleging violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against the AEP companies, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy when it was unable to raise prices to its customers due to fixed price contracts. The suit alleges over$500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs.Management believes that the claims against us are without merit. We intend to vigorously defend against the claims.See Note 7 for further discussion. COLILitigation A decision by the U.S. District Court for the Southern District of Ohio in February 2001 that denied AEP's deduction of interest claimed on AEP's consolidated federal income tax returns related to a COLI program resulted in a $319 million reduction in AEP's Net Income for 2000. We filed an appeal of the U.S. District Court's decision with the U.S. Court of Appeals for the 6k" Circuit. In April 2003, the Appeals Court ruled against AEP. The U.S. Supreme Court has declined to hear this issue.Snoiioinis/h Settlement In February 2003, AEP and the Public Utility District No. I of Snohomish County, Washington (Snohomish) agreed to terminate their long-term contract signed in January 2001. Snohomish also agreed to withdraw its complaint before the FERC regarding this contract and paid $59 million to us. The settlement amount was less than the amount receivable that, in the ordinary course of business, we recorded using MTM accounting. As a result, we incurred a$10 million pre-tax loss.Other Litigation We are involved in a number of other legal proceedings and claims. While management is unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters will have a material adverse effect on results of operations, cash flows or financial condition. Potential Uninsured Losses Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to damage to the Cook Plant or STP and costs of replacement power in the event of a nuclear incident at the Cook Plant or STP. Future losses or liabilities which are not completely insured, unless recovered from customers, could have a material adverse effect on results of operations, cash flows and financial condition. Environmental Matters There are new environmental control requirements that we expect will result in substantial capital investments and operational costs. The sources of these future requirements include:*Legislative and regulatory proposals to adopt stringent controls on sulfur dioxide (SO 2), nitrogen oxide (NO,)and mercury emissions from coal-fired power plants,* New Clean Water Act rules to reduce the impacts of water intake structures on aquatic species at certain of our power plants, and* Possible future requirements to reduce carbon dioxide emissions to address concerns about global climatic change.In addition to achieving full compliance with all applicable legal requirements, we strive to go beyond compliance in an effort to be good environmental stewards. For example, we invest in research, through groups like the Electric A-26 Power Research Institute, to develop, implement and demonstrate new emission control technologies. We plan to continue in a leadership role to protect and preserve the environment while providing vital energy commodities and services to customers at fair prices. We have a proven record of efficiently producing and delivering electricity and gas while minimizing the impact on the environment. We invested over $2 billion, from 1990 through 2003, to equip many of our facilities with pollution control technologies. We will continue to make investments to improve the air emissions from our generating stations because this is the most cost-effective generation source for our customers electricity needs.The CurrentAir Quality Regulatory Framework The Clean Air Act (CAA) is the legislation that establishes the federal regulatory authority and oversight for emissions from our fossil-fired generating plants. The states, with oversight and approval from the Federal EPA, administer and enforce these laws and related regulations. Title I of the CAA National Ambient Air Ouality Standards: The Federal EPA periodically reviews the available scientific data for six pollutants and establishes a standard for concentration levels in ambient air for these substances to protect the public'welfare and public health with an extra margin for safety. These requirements are known as "national ambient air quality standards" (NAAQS).The states identify those areas within their state that meet the NAAQS (attainment areas) and those that do not (non-attainment areas). States must develop their individual state implementation plans (SlPs) with the intention of bringing non-attainment areas into compliance with the NAAQS. In developing a SIP each state must allow attainment areas to maintain compliance with the NAAQS. This is accomplished by controlling sources that emit one or more pollutants or precursors to those pollutants. The Federal EPA approves SIPs if they meet the minimum criteria in the CAA. Alternatively, the Federal EPA may prescribe a federal implementation plan if they conclude that a SIP is deficient. Additionally, the Federal EPA can impose sanctions, up to and including withholding of federal highway funds, in states that fail to submit an adequate SIP or a SIP that fails to bring non-attainment areas into NAAQS compliance within the time prescribed by the CAA.The CAA also establishes visibility goals, which are known as the regional haze program, for certain federally designated areas, including national parks. States are required to develop and submit SIP provisions that 'will demonstrate reasonable progress toward preventing the impairment and remedying any existing impairment of visibility in these federally designated areas.Each state's SIP must include requirements to control sources that emit pollutants in that state as well as requirements to control sources that significantly contribute to non-attainment areas in another state. If a state believes that its air quality is impacted by upwind sources outside their borders, that state can submit a petition that asks the Federal EPA to impose control requirements on specific sources in other states if those states' SIPs do not contain adequate requirements to control those sources. For example, the Federal EPA issued a NOx Rule in 1997, which affected 22 eastern states (including states in which AEP operates) and the District of Columbia. The NOx Rule asked these 23 jurisdictions to adopt requirements, for utility and industrial boilers and certain other emission sources, to employ cost-effective control technologies to reduce NOx emissions. The purpose of the request was to allow certain eastern states to reduce the contribution from these 23 jurisdictions to ozone non-attainment areas in certain eastern states.The Federal EPA also granted four petitions filed by certain eastern states seeking essentially the same levels of control on emission sources outside of their states and issued a Section 126 Rule. All of the states in which we operate that were subject to the NOx Rule have submitted the required SIP revisions. In response, the Federal EPA issued the NOx Rule and the Section 126 Rule, which are discussed below.The compliance date for the NOx Rule is May 31, 2004. In 2000, the Federal EPA also adopted a revised Section 126 Rule which granted petitions filed by four northeastern states. The revised Section 126 Rule imposes emissions reduction requirements comparable to the NOx Rule also beginning May 31, 2004, for most of our coal-fired generating units.A-27 In 2000, the Texas Commission on Environmental Quality adopted rules requiring significant reductions in NOx emissions from utility sources, including TCC and SWEPCo. The compliance requirements began in May 2003 for TCC and begin in May 2005 for SWEPCo.We are installing a variety of emission control technologies to improve NOx emissions standards and to comply with applicable state and federal NOx requirements. These include selective catalytic reduction (SCR) technology on certain units and other combustion control technologies on a larger number of units.AEP's electric utility units are currently subject to SIP requirements that control S02 and particulate matter emissions in all states, and that control NOx emissions in certain states. Our generating plants comply with applicable SIP limits for S02, NOx and particulate matter.Hazardous Air Pollutants: In 1990 Amendments to the CAA, Congress required the Federal EPA to identify the sources of 188 hazardous air pollutants (HAPs) and to develop regulations that prescribe a level of HAP emission reduction. These reductions must reflect the application of maximum achievable control technology (MACT).Congress also directed the Federal EPA to investigate HAP emissions from the electric utility sector and to submit a report to Congress. The Federal EPA's 1998 report to Congress identified mercury emissions from coal-fired electric utility units and nickel emissions from oil-fired utility units as sources of HAP emissions that warranted further investigation and possible control.New Source Performance Standards and New Source Review: The Federal EPA establishes New Source Performance Standards (NSPS) for 28 categories of major stationary emission sources that reflect the best demonstrated level of pollution control. Sources that are constructed or modified after the effective date of an NSPS standard are required to meet those limitations. For example, many electric utility units are regulated under the NSPS for SO 2 , NOx, and particulate matter. Similarly, each SIP must include regulations that require new sources, and major modifications at existing emission sources that result in a significant net increase in emissions, to submit a permit application and undergo a review of available technologies to control emissions of pollutants. These rules are called new source review (NSR) requirements. Different NSR requirements apply in attainment and non-attainment areas.In attainment areas:* An air quality review must be performed, and* The best available control technology must be employed to reduce new emissions. In non-attainment areas,* Requirements reflecting the lowest achievable emission rate are applied to new or modified sources, and* All new emissions must be offset by reductions in emissions of the same pollutant from other sources within the same control area.Neither the NSPS nor NSR requirements apply to certain activities, including routine maintenance, repair or replacement, changes in fuels or raw materials that a source is capable of accommodating, the installation of a pollution control project, and other specifically excluded activities. Title IVof the CAA (Acid Rain)The 1990 Amendments to the CAA included a market-based emission reduction program designed to reduce the amount of SO 2 emitted from electric utility units by approximately 50 percent from 1980 levels. This program also established a nationwide cap on utility SO 2 emissions of 8.9 million tons per year. The Federal EPA administers its SO 2 program through an allowance allocation and trading system. Allowances are allocated to specific units based on statutory formulas. Annually each utility unit must surrender one allowance for each ton of SO2 that it emits.Emission sources that install controls and no longer need all of their allowances can bank those allowances for future use or trade them to other emission sources.Title IV also contains requirements for utility sources to reduce NOx emissions through the use of available combustion controls. Units must meet NOx emission rates standards which are specific to that unit or units may participate in an annual averaging program for utility units that are under common control.A-28 Future Reduction Requirementsfor SO 2 , AN0x, an d Mercunry In 1997, the Federal EPA adopted new, more stringent NAAQS for fine particulate matter and ground-level ozone.The Federal EPA is in the process of developing final designations for fine particulate matter and ground-level ozone non-attainment areas. The Federal EPA has identified SO 2 and NOx emissions as precursors to the formation of fine particulate matter. NOx emissions are also identified as a precursor to the formation of ground-level ozone. As a result, requirements for future reductions in emissions of NOx and SO 2 from our generating units are highly probable.In addition, the Federal EPA has proposed a set of options for future mercury controls at coal-fired power plants.Multi-emission control legislation, known as the Clear Skies Act, was introduced in Congress and is supported by the Bush Administration. This legislation would regulate NOx, SO 2 , and mercury emissions from electric generating plants. We support enactment of this comprehensive, multi-emission legislation so that compliance planning can be coordinated and collateral emission reductions maximized. We believe the Bush Administration's Clear Skies Act would establish stringent emission reduction targets and achievable compliance timetables utilizing a cost-effective nationwide cap and trade program. Although the prospects for enactment of the Clear Skies Act are low, there are alternative regulatory approaches which will likely require us to substantially reduce SO2.NOx and mercury emissions over the next ten years.Regulatory Emissions Reductions On January 30, 2004, the Federal EPA published two proposed rules that would collectively require reductions of approximately 70% in emissions of SO 2 , NOx and mercury from coal-fired electric generating units by 2015 (2018 for mercury). This initiative has two major components:

The Federal EPA proposed an interstate air quality rule for reducing SO 2 and NOx emissions across the eastern half of the United States (29 states and the District of Columbia) to address attainment of the fine particulate matter and ground-level ozone NAAQS. These reductions could also satisfy these states'obligations to make reasonable progress towards the national visibility goal under the regional haze program.* The Federal EPA proposed to regulate mercury emissions from coal-fired electric generating units.The interstate air quality rule would require affected states to include, in their SIPs, a program to reduce NOx and SO 2 emissions from coal-fired electric utility units. SO 2 and NOx emissions would be reduced in two phases, which would be implemented through a cap-and-trade program. Regional SO 2 emissions would be reduced to 3.9 million tons by 2010 and to 2.7 million tons by 2015. Regional NOx emissions would be reduced to 1.6 million tons by 2010 and to 1.3 million tons by 2015. Rules to implement the SO 2 and NOx trading programs have not yet been proposed.To control and reduce mercury emissions, the Federal EPA published two alternative proposals.

The first option requires the installation of MACT on a site-specific basis. Mercury emissions would be reduced from 48 tons to approximately 34 tons by 2008. The Federal EPA believes, and the industry concurs, that there are no commercially available mercury control technologies in the marketplace today that can achieve the MACT standards for bituminous coals, but certain units have achieved comparable levels of mercury reduction by installing conventional SO2 (scrubbers) and NOx (SCR) emission reduction technologies. The proposed rule imposes significantly less stringent standards on generating plants that bum sub-bituminous coal or lignite, which standards potentially could be met without installation of mercury control technologies. The Federal EPA recommends, and we support, a second mercury emission reduction option. The second option would permit mercury emission reductions to be achieved from existing sources through a national cap-and-trade approach. The cap-and-trade approach would include a two-phase mercury reduction program for coal-fired utilities. This approach would coordinate the reduction requirements for mercury with the S02 and NOx reduction requirements imposed on the same sources under the proposed interstate air quality rule. Coordination is significantly more cost-effective because technologies like scrubbers and SCRs, that can be used to comply with the more stringent SO 2 and NOx requirements, have also proven highly effective in reducing mercury emissions on certain coal-fired units that bum bituminous coal. The second option contemplates reducing mercury emissions from 48 million tons to 34 million tons by 2010 and to 15 million tons by 2018.A-29 The Federal EPA's proposals are the beginning of a lengthy rulemaking process, which will involve supplemental proposals on many details of the new regulatory programs, written comments and public hearings, issuance of final rules, and potential litigation. In addition, states have substantial discretion in developing their rules to implement cap-and-trade programs, and will have 18 months after publication of the notice of final rulemaking to submit their revised SIPs. As a result, the ultimate requirements may not be known for several years and may depart significantly from the original proposed rules described here.While uncertainty remains as to whether future emission reduction requirements will result from new legislation or regulation, it is certain under either outcome that we will invest in additional conventional pollution control technology on a major portion of our fleet of coal-fired power plants. Finalization of new requirements for further S02, NOx and/or mercury emission reductions will result in the installation of additional scrubbers, SCR systems and/or the installation of emerging technologies for mercury control.Estiniated Air Qualit Envirowinteatl Imvestnteitts Each of the current and possible future environmental compliance requirements discussed above will require us to make significant additional investments, some of which are estimable. The proposed rules discussed above have not been adopted, will be subject to further revision, and will be the subject of a court challenge and further modifications. All of our estimates are subject to significant uncertainties about the outcome of several interrelated assumptions and variables, including:

Timing of implementation
Required levels of reductions
Allocation requirements of the new rules, and* Our selected compliance alternatives.

As a result, we cannot estimate our compliance costs with certainty, and the actual costs to comply could differ significantly from the estimates discussed below.All of the costs discussed below are incremental to our current investment base and operating cost structure. These expenditures for pollution control technologies, replacement generation and associated operating costs are recoverable from customers through regulated rates (in regulated jurisdictions) and should be recoverable through market prices (in deregulated jurisdictions). If not, those costs could adversely affect future results of operations and cash flows, and possibly financial condition. Estimated Investments for NOx Compliance We estimate that we will make future investments of approximately $600 million to comply with the Federal EPA's NOx Rule, the Texas Commission on Environmental Quality Rule and other final Federal EPA NOx-related requirements. Approximately $500 million of these investments are reflected in our estimated construction expenditures for 2004 -2006. As of December 31, 2003, we have invested approximately $1.1 billion to comply with various NOx requirements. Estimated Investments for S02 Compliance We are complying with Title IV S02 requirements by installing scrubbers, other controls and fuel switching at certain generating units. WVe also use S02 allowances that wve:* Receive in the annual allowance allocation by the Federal EPA,* Obtain through participation in the annual allowance auction,* Purchase in the allowance market, and* Obtained as bonus allowances for installing controls early.Decreasing SO2 allowance allocations, a diminishing S02 allowance bank, and increasing allowance prices in the market will require us to install additional controls on certain of our generating units. We plan to install 3,500 MW of A-30 additional scrubbers over the next 4 years to comply with our Title IV SO 2 obligations. In total we estimate these additional capital costs to be approximately $1.2 billion. Of this total, we estimate that $900 million will be expended during 2004-2006 and this amount is included in our total estimated construction expenditures for 2004 -2006.Estimated Investments to Conply with Future Reduction Requirements Our planning assumptions for the levels and timing of emissions reductions parallel the reduction levels and implementation time periods stated in the proposed rules issued by the Federal EPA in January 2004. We have also assumed that the Federal EPA will implement a mercury trading option and will design its proposed cap and trade mechanism for SO 2 , NOx and mercury emissions in a manner similar to existing cap and trade programs. Based on these assumptions, compliance would require additional capital investment of approximately $1.7 billion by 2010, the end of the first phase for each proposed rule. We also estimate that we would incur increases in variable operation and maintenance expenses of $150 million for the periods by 2010, due to the costs associated with the maintenance of additional control systems, disposal of scrubber by-products and the purchase of reagents. We estimate that we will invest $200 million of this amount through 2006, and this amount is included in our total estimated construction expenditures for 2004 -2006.If the Federal EPA's preferred mercury trading option is not implemented, then any alternative mercury control program requiring adherence to MACT standards would also have implementation costs that could be significant. We cannot currently estimate the nature or amount of these costs. Furthermore, scrubber and SCR technologies could not be deployed at every bituminous-fired plant that AEP operates within the three-year compliance schedule provided under the proposed MACT rule. These MACT compliance costs, %which we are not able to estimate, would be incremental to other cost estimates that we have discussed above.Beyond 2010, we expect to incur additional costs for pollution control technology retrofits and associated operation and maintenance of the equipment. We cannot estimate these additional costs because of the uncertainties associated with the final control requirements and our associated compliance strategy, but these capital and operating costs will be significant. New Source Review Litigation Under the CAA, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant.The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and other unaffiliated utilities modified certain units at coal-fired generating plants in violation of the NSRs of the CAA. The Federal EPA filed its complaints against our subsidiaries in U.S. District Court for the Southern District of Ohio. The court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications relate to costs that were incurred at our generating units over a 20-year period.We are unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the CAA proceedings. WVe are also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If we do not prevail, any capital and operating costs of additional pollution control equipment that may be required, as well as any penalties imposed, would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity. Superfund and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically disposed of or treated in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, PCBs and other hazardous and non-hazardous materials. We are currently incurring costs to safely dispose of these substances. A-31 Superfund addresses clean-up of hazardous substances at disposal sites and authorized the Federal EPA to administer the clean-up programs. As of year-end 2003, subsidiaries of AEP are named by the Federal EPA as a PRP for five sites. There are six additional sites for which our subsidiaries have received information requests which could lead to PRP designation. Our subsidiaries have also been named potentially liable at six sites under state law. Liability has been resolved for a number of sites with no significant effect on results of operations. In those instances where we have been named a PRP or defendant, our disposal or recycling activities were in accordance with the then-applicable laws and regulations. Unfortunately, Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. While the potential liability for each Superfund site must be evaluated separately, several general statements can be made regarding our potential future liability. Disposal of materials at a particular site is often unsubstantiated and the quantity of materials deposited at a site was small and often nonhazardous. Although superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. Therefore, our present estimates do not anticipate material cleanup costs for identified sites for which we have been declared PRPs. If significant cleanup costs were attributed to our subsidiaries in the future under Superfund, results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be included in our electricity prices.Global Climnate Change At the Third Conference of the Parties to the United Nations Framework Convention on Climate Change held in Kyoto, Japan in December 1997, more than 160 countries, including the U.S., negotiated a treaty requiring legally-binding reductions in emissions of greenhouse gases, chiefly C0 2 , which many scientists believe are contributing to global climate change. The U.S. signed the Kyoto Protocol on November 12, 1998, but the treaty was not submitted to the Senate for its advice and consent by President Clinton. In March 2001, President Bush announced his opposition to the treaty. Ratification of the treaty by a majority of the countries' legislative bodies is required for it to be enforceable. Enforceability of the protocol is now contingent on ratification by Russia, which has expressed concerns about doing so.On August 28, 2003, the Federal EPA issued a decision in response to a petition for rulemaking seeking reductions of C0 2 and other greenhouse gas emissions from mobile sources. The Federal EPA denied the petition and issued a memorandum stating that it does not have the authority under the Clean Air Act to regulate CO2 or other greenhouse gas emissions that may affect global warming trends. The Circuit Court of Appeals for the District of Columbia is reviewing these actions.We do not support the Kyoto Protocol but have been wvorking with the Bush Administration on a voluntary program aimed at meeting the President's goal of reducing the greenhouse gas intensity of the economy by 18% by 2012. For many years, we have been a leader in pursuing voluntary actions to control greenhouse gas emissions. We expanded our commitment in this area in 2002 by joining the Chicago Climate Exchange, a pilot greenhouse gas emission reduction and trading program, under which we are obligated to reduce or offset 18 million tons of CO 2 emissions during 2003-2006. We acquired 4,000 MW of coal-fired generation in the United Kingdom in December 2001. These assets may have future CO 2 emission control obligations beginning in 2005. We plan to dispose of our investment in this generation during 2004.Costsfor Spent Nuclear Fuel and Decomindssioning 1&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP, have a significant future financial commitment to safely dispose of SNF and to decommission and decontaminate the plants. The Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of SNF and high-level radioactive waste. By law I&M and TCC participate in the DOE's SNF disposal program which is described in Note 7. Since 1983 I&M has collected $316 million from customers for the disposal of nuclear fuel consumed at the Cook Plant. We deposited $117 million of these funds in external trust funds to provide for the future disposal of SNF and remitted$199 million to the DOE. TCC has collected and remitted to the DOE, $56 million for the future disposal of SNF since STP began operation in the late 1980s. Under the provisions of the Nuclear Waste Policy Act, collections from A-32 customers are to provide the DOE with money to build a permanent repository for spent fuel. However, in 1996, the DOE notified the companies that it would be unable to begin accepting SNF by the January 1998 deadline required by law. To date DOE has failed to comply with the requirements of the Nuclear Waste Policy Act.As a result of DOEs failure to make sufficient progress toward a permanent repository or othervise assume responsibility for SNF, AEP on behalf of I&M and STPNOC on behalf of TCC and the other STP owners, along with a number of unaffiliated utilities and states, filed suit in the D.C. Circuit Court requesting, among other things, that the D.C. Circuit Court order DOE to meet its obligations under the law. The D.C. Circuit Court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal. DOE estimates its planned site for the nuclear waste will not be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S. Court of Federal Claims seeking damages in excess of $150 million due to the DOEIs partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by other utilities. In August 2000, in an appeal of related cases involving other unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held that the delays clause of the standard contract between utilities and the DOE did not apply to DOE's complete failure to perform its contract obligations, and that the utilities' suits against DOE may continue in court. On January 17, 2003, the U.S. Court of Federal Claims ruled in favor of I&M on the issue of liability. The case continues on the issue of damages owed to I&M by the DOE with a trial scheduled in March 2004. As long as the delay in the availability of a government approved storage repository for SNF continues, the cost of both temporary and permanent storage of SNF and the cost of decommissioning will continue to increase.The cost to decommission nuclear plants is affected by both NRC regulations and the delayed SNF disposal program.Studies completed in 2003 estimate the cost to decommission the Cook Plant ranges from $821 million to $1.08 billion in 2003 non-discounted dollars. External trust funds have been established with amounts collected from customers to decommission the plant. At December 31, 2003, the total decommissioning trust fund balance for Cook Plant was $720 million which includes earnings on the trust investments. Studies completed in 1999 for STP estimate TCC's share of decommissioning cost to be $289 million in 1999 non-discounted dollars. Amounts collected from customers to decommission STP have been placed in an external trust. At December 31, 2003, the total decommissioning trust fund for TCC's share of STP was $125 million which includes earnings on the trust investments. Estimates from the decommissioning studies could continue to escalate due to the uncertainty in the SNF disposal program and the length of time that SNF may need to be stored at the plant site. I&M and TCC will work with regulators and customers to recover the remaining estimated costs of decommissioning Cook Plant and STP. However, our future results of operations, cash flows and possibly financial condition would be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. Clean Water Act Regulation On February 16, 2004, the Federal EPA signed a rule pursuant to the Clean Water Act that will require all large existing power plants to meet certain performance standards to reduce the mortality ofjuvenile and adult fish or other larger organisms pinned against a plant's cooling water intake screens. A subset of these plants that are located on sensitive water bodies will be required to meet additional performance standards for reducing the number of smaller organisms passing through the water screens and the cooling system. Sensitive water bodies are defined as oceans, estuaries, the Great Lakes, and small rivers with large plants. These rules will result in additional capital and operation and maintenance expenses to ensure compliance. OtherEnvironnmental Concerns We perform environmental reviews and audits on a regular basis for the purpose of identifying, evaluating and addressing environmental concerns and issues. In addition to the matters discussed above we are managing other environmental concerns which we do not believe are material or potentially material at this time. If they become significant or if any new matters arise that we believe could be material, they could have a material adverse effect on results of operations, cash flows and possibly financial condition. Critical Accounting Policies In the ordinary course of business, we use a number of estimates and assumptions relating to the reporting of results of operations and financial condition in the preparation of our financial statements in conformity with accounting A-33 principles generally accepted in the United States of America, including amounts related to legal matters and contingencies. Actual results can differ significantly from those estimates under different assumptions and conditions. We believe that the following discussion addresses the most critical accounting policies, which are those that are most important to the portrayal of the financial condition and results and require management's most difficult, subjective and complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain. Revenue Recognition RegulatotyAccoumting Our consolidated financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. We recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation. Specifically, we match the timing of our expense recognition with the recovery of such expense in regulated revenues. Likewise, we match income with its passage to customers through regulated revenues in the same accounting period. We also record regulatory liabilities for refunds, or probable refunds, to customers that have not yet been made.When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. NVe test for probability of recovery whenever new events occur, for example, issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, we write-off that regulatory asset as a charge against earnings. A write-off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates.Traditional Electricity Supply and Delivery Activities We recognize revenues on the accrual or settlement basis for normal retail and wholesale electricity supply sales and electricity transmission and distribution delivery services. That is, we recognize and record revenues when the energy is delivered to the customer and include estimated unbilled as well as billed amounts. In general, expenses are recorded when purchased electricity is received and when expenses are incurred.Domestic Gas Pipeline and Storage.Activities We recognize revenues from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided, with the exception of certain physical forward gas purchase and sale contracts that are derivatives and are required to be accounted for using mark-to-market accounting (Resale Gas Contracts). Energy Marketing and Risk Management Activities Wve engage in wholesale electricity, natural gas and coal marketing and risk management activities. Effective in October 2002, these activities were focused on wholesale markets where we own assets. Our activities include the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options, and over-the-counter options and swaps. Prior to October 2002, we recorded wholesale marketing and risk management activities using the mark-to-market method of accounting. In October 2002, EITE 02-3 precluded mark-to-market accounting for risk management contracts that were not derivatives pursuant to SFAS 133. WVe implemented this standard for all non-derivative wholesale and risk management transactions occurring on or after October 25, 2002. For non-derivative risk management transactions entered into prior to October 25, 2002, we implemented this standard on January 1, 2003 and reported the effects of implementation as a cumulative effect of an accounting change.After January 1, 2003, we use mark-to-market accounting for wholesale marketing and risk management transactions that are derivatives unless the derivative is designated for hedge accounting or the normal purchase and sale A-34 exemption. Revenues and expenses are recognized from wholesale marketing and risk management transactions that are not derivatives when the commodity is delivered. See discussion of EITF 02-3 and Rescission of EITF 98-10 in Note 2.Accounting for Derivative Instnrments For derivative contracts that are not designated as hedges or normal purchase and sale transactions we recognize unrealized gains and losses prior to settlement based on changes in fair value during the period in our results of operations. When we settle mark-to-market derivative contracts and realize gains and losses, we reverse previously recorded unrealized gains and losses from mark-to-market valuations. We designate certain derivative instruments as hedges of forecasted transactions or future cash flows (cash flow hedges) or as a hedge of a recognized asset, liability or firm commitment (fair value hedge). We report changes in the fair value of these instruments on our balance sheet. We do not recognize changes in the fair value of the derivative instrument designated as a hedge in the current results of operations until earnings are impacted by the hedged item.We also recognize any changes in the fair value of the hedging instrument that are not offset by changes in the fair value of the hedged item immediately in earnings.We measure the fair values of derivative instruments and hedge instruments accounted for using mark-to-market accounting based on exchange prices and broker quotes. If a quoted market price is not available, we estimate the fair value based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data, and other assumptions. We reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality. There are inherent risks related to the underlying assumptions in models used to fair value open long-term derivative contracts. We have independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile. Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and at the time a contract settles. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices are not consistent with our approach at estimating current market consensus for forward prices in the current period. This is particularly true for long-term contracts. We recognize all derivative instruments at fair value in our Consolidated Balance Sheets as either "Risk Management Assets" or "Risk Management Liabilities." We do not consider contracts that have been elected normal purchase or normal sale under SFAS 133 to be derivatives. Unrealized and realized gains and losses on all derivative instruments are ultimately included in Revenues in the Consolidated Statement of Operations on a net basis, with the exception of physically settled Resale Gas Contracts for the purchase of natural gas. The unrealized and realized gains and losses on these Resale Gas Contracts are presented as Purchased Gas for Resale in the Consolidated Statement of Operations. Long-LivedAssets Long-lived assets are evaluated periodically for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable. If the canying amount is not recoverable, an impairment is recorded to the extent that the fair value of the asset is less than its book value.Pensions Bentefits We sponsor pension and other retirement plans in various forms covering all employees who meet eligibility requirements. We use several statistical and other factors which attempt to anticipate future events in calculating the expense and liability related to our plans. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as estimated by management, within certain guidelines. In addition, our actuarial consultants use subjective factors such as withdrawal and mortality rates to estimate these factors. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension expense recorded. See "Pension Plans" in Significant Factors section of Management's Financial Discussion and Analysis.A-35 Neew Accounting Pronountcements Effective July 1, 2003, we implemented FIN 46, "Consolidation of Variable Interest Entities." As a result of the implementation, we consolidated two entities, Sabine Mining Company ($77.8 million) and JMG ($469.6 million), which were previously off-balance sheet. These entities were consolidated with SWEPCo and OPCo, respectively. There is no change in net income due to the consolidations. In addition, we deconsolidated Cadis Partners, LLC and the trusts which hold mandatorily redeemable trust preferred securities which were previously reported as Minority Interest in Finance Subsidiary ($533 million) and Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such Subsidiaries ($321 million), respectively. As a result of the deconsolidation these amounts are now included in Long-term Debt. In December 2003, the FASB issued FIN 46R which replaces FIN 46. The FASB and other accounting constituencies continue to interpret the application of FIN 46R. As a result, we are continuing to review the application of this new interpretation and expect to adopt FIN 46R by March 31, 2004.See Notes I and 2 to the consolidated financial statements for a discussion of significant accounting policies and additional impacts of new accounting pronouncements. Other Matters FERC Proposed Standard Mlarket Design In July 2002, the FERC issued its Standard Market Design (SMD) notice of proposed rulemaking, which sought to standardize the structure and operation of wholesale electricity markets across the country. Key elements of FERC's proposal included standard rules and processes for all users of the electricity transmission grid, new transmission rules and policies, and the creation of certain markets to be operated by independent administrators of the grid in all regions. The FERC issued a "white paper" on the proposal in April 2003, in response to the numerous comments that the FERC received on its proposal. Management does not know if or when the FERC will finalize a rule for SMD.Until any potential rule is finalized, management cannot predict its effect on cash flows and results of operations. FERC Alrket Poiwer Afitigation A FERC order issued in November 2001 on AEP's triennial market based wholesale power rate authorization update required certain mitigation actions that AEP would need to take for sales/purchases within its control area and required AEP to post information on its website regarding its power system's status. As a result of a request for rehearing filed by AEP and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. Management is unable to predict the timing of any further action by the FERC or its affect of future results of operations and cash flows.Seasonality The sale of electric power in our service territories is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of our facilities and the terms of power contracts into which we enter. In addition, we have historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish our results of operations and may impact cash flows and financial condition. Non-Core Investments Additional market deterioration associated with our non-core wholesale investments (all operations outside our traditional domestic regulated utility operations), including our U.K. operations, merchant generation facilities, and certain gas storage and pipeline assets, could have an adverse impact on future results of operations and cash flows.Further changes in external market conditions could lead to additional write-offs and further divestitures of our wholesale investments, including, but not limited to, the U.K. operations, merchant generation facilities, and our gas A-36 storage and pipeline operations. See Note 10 for additional information regarding assets and investments currently recorded as held for sale.Itwesinentis Limitations Our investment, including guarantees of debt, in certain types of activities is limited by PUHCA. SEC authorization under PUHCA limits us to issuing and selling securities in an amount up to 100% of our average quarterly consolidated retained earnings balance for investment in EWGs and FUCOs. At December 31, 2003, our investment in EWGs and FUCOs %vas $1.7 billion, including guarantees of debt, compared to our limit of $2.1 billion.SEC Rule 58, under the general rules and regulations of the PUHCA, permits us to invest up to 15% of consolidated capitalization (such amount was $3.4 billion at December 31, 2003) in energy-related companies, including marketing and/or risk management activities in electricity, gas and other energy commodities. As of December 31, 2003 AEP has invested $2.8 billion in these energy-related companies. A-37 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES Market Risks As a major power producer and marketer of wholesale electricity and natural gas, we have certain market risks inherent in our business activities. These risks include commodity price risk, interest rate risk, foreign exchange risk and credit risk. They represent the risk of loss that may impact us due to changes in the underlying market prices or rates.We have established policies and procedures which allow us to identify, assess, and manage market risk exposures in our day-to-day operations. Our risk policies have been reviewed with our Board of Directors and approved by our Risk Executive Committee. Our Chief Risk Officer administers our risk policies and procedures. The Risk Executive Committee establishes risk limits, approves risk policies, and assigns responsibilities regarding the oversight and management of risk and monitors risk levels. Members of this committee receive daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. Our committee meets monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior financial and operating managers.We actively participate in the Committee of Chief Risk Officers (CCRO) to develop standard disclosures for risk management activities around risk management contracts. The CCRO is composed of the chief risk officers of major electricity and gas companies in the United States. The CCRO adopted disclosure standards for risk management contracts to improve clarity, understanding and consistency of information reported. Implementation of the disclosures is voluntary. We support the work of the CCRO and have embraced the disclosure standards. The following tables provide information on our risk management activities. A-38 Mark-to-Market Risk Management Contract Net Assets (Liabilities) This table provides detail on changes in our mark-to-market (MTM) net asset or liability balance sheet position from one period to the next.MTM Risk Management Contract Net Assets (Liabilities) Year Ended December 31,2003 Utility Operations Investments Investments Gas UK Operations Operations (in millions)$(155) $ 45 Beginning Balance December 31, 2002 (Gain) Loss from Contracts Realized/Settled During the Period (a)Fair Value of New Contracts When Entered Into During the Period (b)Net Option Premiums Paid/(Received) (c)Change in Fair Value Due to Valuation Methodology Changes Effect of EITF 98-10 Rescission (d)Changes in Fair Value of Risk Management Contracts (e)Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)UK Generation Hedges (g)$360 (107)(19)43 Consolidated $250 59 175 23 ((40)(9)4 (14)4 9 (14)((32)(134)(131)9 (124)9 (124 Total MTM Risk Management Contract Net Assets (Liabilities), excluding Cash Flow Hedges Net Cash Flow Hedge Contracts (h)Net Risk Management Liabilities Held for Sale (i)Ending Balance December 31,2003$28-6 $ $(2A 45 (134)383$294 (a) "(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 and entered into prior to 2003.(b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value at inception of long-term contracts entered into with customers during 2003. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location.(c) "Net Option Premiums Paid'(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts entered into in 2003.(d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and Cumulative Effect." (e) "Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.(f) "Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Operations. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.(g) "UK Generation Hedges" represent amounts previously classified as hedges of forecasted U.K. power sales relating to the fourth quarter of 2004 and beyond. Given the expected disposition of our U.K. generation in 2004, the forecasted sales are no longer probable of occurring. Therefore, these amounts have been reclassified from hedge accounting to mark-to-market accounting.(h) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed in detail within the following pages.(i) See Note 10 for discussion on Assets Held for Sale.A-39 Detail on MTM Risk Management Contract Net Assets (Liabilities) As of Dccember 31,2003 Utility Operations Investments Investments Gas UK Operations Operations (in millions)$417 $560 215 274$632 $834 Current Assets Non Current Assets Total Assets$323 279$602 Consolidated $1,300 768$ 2,068$(1,265)(758)$(2,023)Current Liabilities Non Current Liabilities Total Liabilities $(216)(100)$(316)$(403)(224)$(627)$(646)(434)$(1.080)Total Net Assets (Liabilities), excluding Cash Flow Hedges $2S $5 $(24 Reconciliation of MTM Risk Management Contracts to Consolidated Balance Sheets As of December 31,2003 Risk Management Contracts* Cash Flow Assets Held Hledges for Sale (in millions)$26 $(560)-(274)$26 $(834)Current Assets Non Current Assets Total Assets$1,300 768$2,068 Consolidated $766 494$1(260$(631)(335)$(966)Current Liabilities Non Current Liabilities Total Liabilities $(1,265)(758)$(2,023)$(148)(12)_$(160)$782 435$1,217 Total Net Assets (Liabilities) $45 _(-- $383* Excluding Cash Flow Hedges.Maturitv and Source of Fair Value of MTM Risk Management Contract Net Assets (Liabilities) The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information.

The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
The maturity, by year, of our net assets/liabilities, giving an indication of when these TM amounts will settle and generate cash.A-40 Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets (Liabilities)

Fair Value of Contracts as of December 31,2003 After 2008 2008(c)2004 2005 2006 2007 (in millions)Total (d)Utility Operations: Prices Actively Quoted -Exchange Traded Contracts Prices Provided by Other External Sources -OTC Broker Quotes (a)Prices Based on Models and Other Valuation Methods (b)Total$44 78$(4)38$(l)$- $39 29 13 6 164 (15) 7 15 19 16 41 83$107 $41 $43 $32 $22 $41 $286 Investments -Gas Operations: Prices Actively Quoted -Exchange Traded Contracts Prices Provided by Other External Sources -OTC Broker Quotes (a)Prices Based on Models and Other Valuation Methods (b)Total Investments -UK Operations: Prices Actively Quoted -Exchange Traded Contracts Prices Provided by Other External Sources -OTC Broker Quotes (a)Prices Based on Models and Other Valuation Methods (b)Total$49$14$(l)$- $62 (27)(27)(8! (7 (6)$14 $7 $(7!(1!$(1!(3)$(3!(5!$(5)(30)$5 (60)(26$(86)(101)(46)(207)(9) (2)$(110) $(48)(2!$(2!--(39)$- $- $(249 Consolidated: Prices Actively Quoted -Exchange Traded Contracts Prices Provided by Other External Sources -OTC Broker Quotes (a)Prices Based on Models and Other Valuation Methods (b)Total$93$10$(2)$- $101-(70)(9) (63)(17)13 6 (49) (9! 7 16 13_$35 ~$(62 --$LL9 $s 36 14 (a) Prices provided by other external sources -Reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.(b) Modeled -In the absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled.(c) For Utility Operations, there is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2008. $17 million of this mark-to-market value is in 2009 and $16 million of this mark-to-market value is in 2010.(d) Amounts exclude Cash Flow Hedges.A-41 The determination of the point at which a market is no longer liquid for placing it in the Modeled category in the preceding table varies by market. The following table reports an estimate of the maximum tenors (contract maturities) of the liquid portion of each energy market.Maximum Tenor of the Liquid Portion of Risk Management Contracts As of December 31,2003 Domestic Transaction Class Market/Region Tenor (in months)Natural Gas Futures Physical Forwards Swaps Swaps Exchange Option Volitility NYMEX Henry Hub Gulf Coast, Texas Gas East -Northeast, Mid-continent Gulf Coast, Texas Gas West -Rocky Mountains,\Vest Coast NYMEX/Henry Hub 72 12 15 15 12 Power Futures Physical Forwards Physical Fonvards Physical Forwards Physical Forwards Physical Forwards Physical Forwards Physical Forwards Physical Forwards Physical Forwards Peak Power Volatility (Options)Peak Power Volatility (Options)Crude Oil Swaps Power East -PJM Power East -Cinergy Power East -PJM Power East -NYPP Power East -NEPOOL Power East -ERCOT Power East -TVA Power East -Corn Ed Power East -Entergy Power West-PV, NP15, SP15, MidC, Mead Cinergy PJM West Texas Intermediate 24 60 48 24 12 24 48 24 48 60 12 12 36 Emissions Credits S02 24 Coal Physical Forwards PRB,NYMEX,CSX 24 International Power Coal Forwards and Options Forward Purchases and Sales United Kingdom United Kingdom 24 15 Swaps Europe 36 Freight Swaps Europe 24 Cash Flow Hedees Included in Accumulated Other Comprehensive Income (Loss) on the Balance Sheet We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments such as cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.We employ fair value hedges and cash flow hedges to mitigate changes in interest rates or fair values on short and long-term debt when management deems it necessary. We do not hedge all interest rate risk.A-42 We employ forward contracts as cash flow hedges to lock-in prices on certain transactions which have been denominated in foreign currencies where deemed necessary. International subsidiaries use currency swaps to hedge exchange rate fluctuations of debt denominated in foreign currencies. We do not hedge all foreign currency exposure.The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place (However, given that under SFAS 133 only cash flow hedges are recorded in Accumulated Other Comprehensive Income (AOCI), the table does not provide an all-encompassing picture of our hedging activity). The table further indicates what portions of these hedges are expected to be reclassified into net income in the next 12 months. The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll off of hedges).Information on energy merchant activities is presented separately from interest rate, foreign currency risk management activities and other hedging activities. In accordance with GAAP, all amounts are presented net of related income taxes.Cash Flow Hedges included in Accumulated Other Comprehensive Income (Loss)On the Balance Sheet as of December 31, 2003 Accumulated Other Portion Expected to Comprehensive be Reclassified to Income Earnings During the (Loss) After Tax (a) Next 12 Months (b)(in millions)Power and Gas $(65) $(58)Foreign Currency (20) (20)Interest Rate (9! (8)Total M2US .$Total Accumulated Other Comprehensive Income (Loss) Activity Year Ended December 31, 2003 Power Foreign and Gas Currencv Interest Rate Consolidated (in millions)Beginning Balance, December31, 2002 $(3) $(1) $(12) $(16)Changes in Fair Value (c) (64) (19) 4 (79)Reclassifications from AOCI to Net Income (d) 2 -(I) 1 Ending Balance, December 31, 2003 6 $ _ )= _ $(94)(a) "Accumulated Other Comprehensive Income (Loss) After Tax" -Gains/losses are net of related income taxes that have not yet been included in the determination of net income; reported as a separate component of shareholders' equity on the balance sheet.(b) "Portion Expected to be Reclassified to Earnings During the Next 12 Months" -Amount of gains or losses (realized or unrealized) from derivatives used as hedging instruments that have been deferred and are expected to be reclassified into net income during the next -12 months at the time the hedged transaction affects net income.(c) "Changes in Fair Value" -Changes in the fair value of derivatives designated as cash flow hedges not yet reclassified into net income, pending the hedged items affecting net income. Amounts are reported net of related income taxes.(d) "Reclassifications from AOCI to Net Income" -Gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above.A-43 Credit Risk We limit credit risk by assessing creditworthiness of potential counterparties before entering into transactions with them and continue to evaluate their creditworthiness after transactions have been initiated. Only after an entity has met our internal credit rating criteria will we extend unsecured credit. We use Moody's Investor Service, Standard and Poor's and qualitative and quantitative data to independently assess the financial health of counterparties on an ongoing basis. Our independent analysis, in conjunction with the rating agencies' information, is used to determine appropriate risk parameters. WVe also require cash deposits, letters of credit and parentalaffiliate guarantees as security from counterparties depending upon credit quality in our normal course of business.We have risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. We believe that credit exposure with any one counterparty is not material to our financial condition at December 31, 2003. At December 31, 2003, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 16%, expressed in terms of net MTM assets and net receivables. The increase in non-investment grade credit quality was largely due to an increase in coal and freight exposures related to our U.K. investments. As of December 31, 2003, the following table approximates our counterparty credit quality and exposure based on netting across commodities and instruments: Number of Net Exposure of Counterparty Exposure Before Credit Net Counterparties Counterparties Credit Oualiht: Credit Collateral Collateral Exposure > 10% > 10%(in millions)Investment Grade $931 $29 $902 1 $135 Split Rating 47 -47 1 40 Non-Investment Grade 276 136 140 2 71 No External Ratings: Internal Investment Grade 480 5 475 3 207 Internal Non-Investment Grade 185 48 137 2 51 Total $1,919 21 $1_$Generation Plant Hedling Information This table provides information on operating measures regarding the proportion of output of our generation facilities (based on economic availability projections) economically hedged. This information is forward-looking and provided on a prospective basis through December 31, 2006. Please note that this table is a point-in-time estimate, subject to changes in market conditions and our decisions on how to manage operations and risk. "Estimated Plant Output Hedged," represents the portion of megawatt hours of future generation/production for which we have sales commitments or estimated requirement obligations to customers. Generation Plant Hedging Information Estimated Next Three Years As of December 31,2003 2004 2005 2006 Estimated Plant Output Hedged 90% 92% 92%VaR Associated with Risk Management Contracts We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance -covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at December 31, 2003, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition. A-44 The following table shows the end, high, average, and low market risk as measured by VaR year-to-date: VaR Model December 31, 2003 December 31,2002 (in millions) (in millions)End Hijh Average Low End lliah Avera.e Low$11 $19 $ 7 $4 $5 $24 $12 $4 The high VaR for 2003 occurred in late February 2003 during a period when natural gas and power prices experienced high levels and extreme volatility. Within a few days, the VaR returned to levels more representative of the average VaR for the year.Our VaR model results are adjusted using standard statistical treatments to calculate the CCRO VaR reporting metrics listed below.CCRO VaR Metrics Average for Year-to-Date High for Low for December 31, 2003 2003 Year-to-Date 2003 Year-to-Date2003 (in millions)95% Confidence Level, Ten-Day Holding Period $41 $27 $71 $16 99% Confidence Level, One-Day Holding Period $17 $11 $30 $7 We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The volatilities and correlations were based on three years of daily prices. The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $1.013 billion at December 31, 2003 and $527 million at December 31, 2002. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not materially affect our results of operations or consolidated financial position.We are exposed to risk from changes in the market prices of coal and natural gas used to generate electricity where generation is no longer regulated or where existing fuel clauses are suspended or frozen. The protection afforded by fuel clause recovery mechanisms has either been eliminated by the implementation of customer choice in Ohio (effective January 1, 2001) and in the ERCOT area of Texas (effective January 1, 2002) or frozen by a settlement agreement in West Virginia. To the extent the fuel supply of the generating units in these states is not under fixed price long-term contracts eve are subject to market price risk. We continue to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas.Fuel clauses are active again in Michigan and Texas, effective January 1, 2004 and March 1, 2004, respectively. We employ risk management contracts including physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, s'waps, and other derivative contracts to offset price risk where appropriate. We engage in risk management of electricity, gas and to a lesser degree other commodities, principally coal and freight.As a result, we are subject to price risk. The amount of risk taken is controlled by risk management operations and our Chief Risk Officer and his staff. When risk management activities exceed certain predetermined limits, the positions are modified or hedged to reduce the risk to be within the limits unless specifically approved by the Risk Executive Committee. A-45 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF OPERATIONS For the Years Ended December 31, 2003,2002 and 2001 (in millions, except per-share amounts)2003 2002 2001 REVENUES Utility Operations Gas Operations Other TOTAL EXPENSES$10,871 3,097 577 14.545$10,446 2,071 791 13.308$10,546 1,797 410 12.753 Fuel for Electric Generation Purchased Electricity for Resale Purchased Gas for Resale Maintenance and Other Operation Asset Impairments and Other Related Charges Depreciation and Amortization Taxes Other Than Income Taxes TOTAL 3,053 707 2,850 3,673 650 1,299 681 12.913 2,577 532 1,946 4,065 318 1,348 718 11.504 3,225 296 1,443 3,666 1,233 667 10Q530 OPERATING INCOME 1.632 Other Income 387 461 371 INTEREST AND OTHER CHARGES Investment Value Losses Other Expenses Interest Preferred Stock Dividend Requirements of Subsidiaries Minority Interest in Finance Subsidiary TOTAL INCOME BEFORE INCOME TAXES Income Taxes INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT 70 227 814 9 19 1.139 880 358 522 321 323 775 11 35 1,465 800 315 485 225 833 10 13 1.081 1,513 553 960 DISCONTINUED OPERATIONS (Net of Tax)EXTRAORDINARY LOSS (Net of Tax)(605)(654)41 (48)CUMULATIVE, EFFECT OF ACCOUNTING CHANGES (Net of Tax)Goodwill and Other Intangible Assets Accounting for Risk Management Contracts Asset Retirement Obligations NET INCO'ME (LOSS)(49)242 (350)18 AVERAGE NUMBER OF SHARES OUTSTANDING EARNINGS (LOSSI PER SHARE Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect of Accounting Changes Discontinued Operations Extraordinary Loss Cumulative Effect of Accounting Changes TOTAL EARNINGS PER SHARE (BASIC AND DILUTIVE)$1.35 (1.57)0.51$Q22$1A6 (1.97)(1.06)$2.98 0.13 (0.16)0.06 S3.0 CASH DIVIDENDS PAID PER SHARE See Notes to Consolidated Financial Statements. A-46 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS ASSETS December 31,2003 and 2002 2003 2002 (in millions)CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable: Customers Accrued Unbilled Revenues Miscellaneous Allowance for Uncollectible Accounts Total Receivables Fuel, Materials and Supplies Risk Management Assets Margin Deposits Other TOTAL$1,182$1,199 1,155 596 83 (124)1.710 991 766 119 129 4.897 1,553 551 93 (108)2.089 938 850 110 132 5.318 PROPERTY. PLANT AND EOUIPMENT Electric: Production Transmission Distribution Other (including gas, coal mining and nuclear fuel)Construction Work in Progress TOTAL Less: Accumulated Depreciation and Amortization TOTAL-NET 15,112 6,130 9,902 3,584 1.305 36,033 14,004 22.029 13,678 5,866 9,573 3,656 1.354 34,127 13.539 20.588 OTIIER NON-CUJRRENT ASSETS Regulatory Assets Securitized Transition Assets Spent Nuclear Fuel and Decommissioning Trusts Investments in Power and Distribution Projects Goodwill Long-term Risk Management Assets Other TOTAL 3,548 689 982 212 78 494 733 6.736 2,688 735 871 283 241 758 792 6.368 Assets Held for Sale Assets of Discontinued Operations 3,082 3,601 15 TOTAL ASSETS See Notes to Consolidated Financial Statements. A-47 AMERICAN ELECTRIC POWVER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS LIABILITIES AND SHAREHOLDERS' EQUITY December 31, 2003 and 2002 2003 2002 (in millions)CURRENT LIABILITIES Accounts Payable $1,337 $1,892 Short-term Debt 326 2,739 Long-term Debt Due Within One Year* 1,779 1,327 Risk Management Liabilities 631 961 Accrued Taxes 620 556 Accrued Interest 207 181 Customer Deposits 379 186 Other 703 814 TOTAL 5.982 8.656 NON-CURRENT LIABILITIES Long-term Debt* 12,322 8,863 Long-term Risk Management Liabilities 335 435 Deferred Income Taxes 3,957 3,916 Regulatory Liabilities and Deferred Investment Tax Credits 2,259 939 Asset Retirement Obligations and Nuclear Decommissioning Trusts 651 638 Employee Benefits and Pension Obligations 667 987 Deferred Gain on Sale and Leaseback -Rockport Plant Unit 2 176 185 Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption 76 Deferred Credits and Other 508 1.691 TOTAL 20.951 17.654 Liabilities Ileld for Sale 1,876 1,279 Liabilities of Discontinued Operations -12 TOTAL LIABILITIES 28.809 27.601 Cumulative Preferred Stocks of Subsidiaries not Subject to Mandatory Redemption 61 Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such Subsidiaries -321 Minority Interest in Finance Subsidiary 759 Cumulative Preferred Stocks of Subsidiaries 145 Commitments and Contingencies COMMON ShIAREHIOLDERS' EOUITY Common Stock-Par Value $6.50: 2003 2002 Shares Authorized .......... 600,000,000 600,000,000 Shares Issued .......... 404,016,413 347,835,212 (8,999,992 shares were held in treasury at December 31, 2003 and 2002) 2,626 2,261 Paid-in Capital 4,184 3,413 Retained Earnings 1,490 1,999 Accumulated Other Comprehensive Income (Loss) (426) (609)TOTAL 7.874 7.064 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY* See Accompanying Schedules See Notes to Consolidated Financial Statements. A-48 AMERICAN ELECTRIC POWVER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2003, 2002 and 2001 OPERATING ACTIVITIES 2003 2002 (in millions)$110 $(519)605 654 715 135 Net Income (Loss)Plus: Discontinued Operations Income from Continuing Operations Adjustments for Noncash Items: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax Credits Pension and Postemployment Benefits Reserves Cumulative Effect of Accounting Changes Asset and Investment Value Impairments and Other Related Charges Extraordinary Loss Amortization of Deferred Property Taxes Amortization of Cook Plant Restart Costs Mark to Market of Risk Management Contracts Changes in Certain Current Assets and Liabilities: Accounts Receivable, net Fuel, Materials and Supplies Accounts Payable Taxes Accrued Over/Under Fuel Recovery Change in Other Assets Change in Other Liabilities Net Cash Flows From Operating Activities 1,299 163 (33)(74)(193)720 (2)40 (122)363 (71)(632)87 138 (162)72 2.308 1,375 63 (31)39 350 639 (16)40 275 (238)(102)(21)(222)13 (78)(154)2.067 2001$971 (41)930 1,267 151 (29)(234)(18)48 43 40 (294).1,769 (82)(469)(150)340 (171)(323)2.818 INVF.STING ACTIVITIES Construction Expenditures Business Acquisitions Investment in Discontinued Operations, net Proceeds from Sale of Assets Other Net Cash Flows Used For Investing Activities (1,358)(615)82 3 (1.888)(1,685)1,263 44 (378)(1,646)(1,269)(983)648 (42)(3.292)FINANCING ACTIVITIES Issuance of Common Stock Issuance of Long-term Debt Issuance of Minority Interest Issuance of Equity Unit Senior Notes Change in Short-term Debt, net Retirement of Long-term Debt Retirement of Preferred Stock Retirement of Minority Interest Dividends Paid on Common Stock Net Cash Flows From (Used For) Financing Activities Effect of Exchange Rate Change on Cash Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Net Increase (Decrease) in Cash and Cash Equivalents from Discontinued Operations Cash and Cash Equivalents from Discontinued Operations-Beginning of Period Cash and Cash Equivalents from Discontinued Operations -End of Period See Notes to Consolidated Financial Statements. 1,142 4,761 (2,781)(2,707)(9)(225)(618)(437)656 2,893 334 (1,248)(2,513)(10)(793)(681)I1 2,787 744 (778)(1,549)(5)(773)437 (3) (1)(17)1.199_$1,182$(10)23 1,005 194 S(116)139__S23 (38)232$124 S29 110 A49 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)(in millions)Accumulated Other Paid-in Retained Comprehensive Capital Earnings Income (Loss)Common Stock Shares Amount Total DECEMBER 31,2000 331 $2,152 S2,915 $3,090 S(103) $8,054 Issuance of Common Stock Common Stock Dividends Other TOTAL I 9 (773)8 10 (773)(10)7,281 (18)COMPREHENSIVE INCOME (LOSS)Other Comprehensive Income (Loss), Net of Taxes: Foreign Currency Translation Adjustments Unrealized Losses on Cash Flow Hedges Minimum Pension Liability NET INCOME TOTAL COMPREHENSIVE INCOME (14)(3)(6)(14)(3)(6)971 948 971 DECEMBER31,2001 331 $2,153 $2,906 $3,296$(126) $8,229 Issuance of Common Stock Common Stock Dividends Common Stock Expense Other TOTAL 17 108 568 (30)(31)(793)15 676 (793)(30)(16)8,066 COMPREHENSIVE INCOME (LOSS)Other Comprehensive Income (Loss), Net of Taxes: Foreign Currency Translation Adjustments Unrealized Losses on Cash Flow Hedges Unrealized Losses on Securities Available for Sale Minimum Pension Liability NET LOSS TOTAL COMIPREIIENSIVE INCOME (LOSS)117 (13)(2)(585)117 (13)(2)(585)(519)(1.002)(519)DECEMBER 31,2002 348 $2,261 $3,413 $1,999 S(609) $7,064 Issuance of Common Stock Common Stock Dividends Common Stock Expense Other TOTAL 56 365 812 (35)(6)(618)(I)1,177 (618)(35)(7)7,581 COMPREHENSIVE INCOME (LOSS)Other Comprehensive Income (Loss), Net of Taxes: Foreign Currency Translation Adjustments Unrealized Losses on Cash Flow Hedges Unrealized Gains on Securities Available for Sale Minimum Pension Liability NET INCOME TOTAL COMPREIIENSIVE INCOME 106 (78)154 106 (78)154 110 293 110 DECEMBER31,2003 __$Z6 _.4 -I _ _===(42 See Notes to Consolidated Financial Statements. A-50 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES December 31, 2003 and 2002 December 31, 2003 Call Shares Shares Amount Price Per Share(a) Authorized(b) Outstandin2(d) (in millions)Not Subject to Mandatory Redemption: 4.00% -5.00% $102-S110 1,525,903 607,940 $61 Subject to Mandatory Redemption: 5.90% -5.92% (c) $100 1,950,000 278,100 28 6.25% -6.875% (c) $100 1,650,000 482,450 48 Total Subject to Mandatory Redemption (c) 76 Total Preferred Stock $ 137(e)December 31.2002 Call Shares Shares Amount Price Per Share(a) Authorized(b) Outstandine(d) (in millions)Not Subject to Mandatory Redemption: 4.00%-5.00% $102-$110 1,525,903 608,150 $61 Subject to Mandatory Redemption: 5.90% -5.92% (c) $100 1,950,000 333,100 33 6.02% -6.875% (c) $100 1,650,000 513,450 51 Total Subject to Mandatory Redemption (c) 84 Total Preferred Stock $145 (a) At the option of the subsidiary, the shares may be redeemed at the call price plus accrued dividends. The involuntary liquidation preference is $100 per share for all outstanding shares.(b) As of December 31, 2003, the subsidiaries had 13,780,352 shares of $100 par value preferred stock, 22,200,000 shares of$25 par value preferred stock and 7,768,561 shares of no par value preferred stock that were authorized but unissued.(c) Shares outstanding and related amounts are stated net of applicable retirements through sinking funds (generally at par)and reacquisitions of shares in anticipation of future requirements. The subsidiaries reacquired enough shares in 1997 to meet all sinking fund requirements on certain series until 2008 and on certain series until 2009 when all remaining outstanding shares must be redeemed.(d) The number of shares of preferred stock redeemed is 86,210 shares in 2003, 106,458 shares in 2002 and 50,000 shares in 2001.(e) Due to the implementation of SFAS 150 in July 2003, Cumulative Preferred Stocks of Subsidiaries is no longer presented as one line item on the balance sheet. SFAS 150 has required us to present Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption as a liability. Cumulative Preferred Stocks of Subsidiaries Not Subject to Mandatory Redemption will continue to be reported on the balance sheet in the "mezzanine" section.A-51 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE OF CONSOLIDATED LONG-TERM DEBT December 31, 2003 and 2002 Nlaturity Weighted Average Interest Rate December 31, 2003 Interest Rates at December 31.2003 2002 December 31., 2003 2002 (in millions)FIRST MORTGAGE BONDS (a)2003-2004 2005-2008 2022-2025 7.40%6.90%7.28%6.125%-7.85% 6.200/%-8.00% 6.8750/o-8.00% 6.000%-7.85% 6.200/%-8.00% 6.8750/%-8.70%/o $231 463 246$648 463 773 INSTALLMENT PURCHASE CONTRACTS (b)(f)2003-2009 2011-2030 3.74%4.92%2.150/0-6.90% 3.750/%-7.70% 395 1.10%-0/8.20% 1.35%/o8.200/o 1,631 396 1,284 NOTES PAYABLE (cXf)2003-2017 5.20%SENIOR UNSECURED NOTES 2003-2005 2006-2015 2032-2038 1.537%-I15.45% 2.430/%-7.45% 3.60%/0-6.91% 5.6250/%-7.375% 6.225%/0-9.60% 2.120/%-7.45% 4.3 1%/6-6.91% 6.000/%-7.375%

5. 1 0/5.49%6.41%1,518 1,359 4,873 1,765 214 1,834 2,295 690 JUNIOR DEBENTURES 2025-2038 205 SECURITIZATION BONDS 2005-2016 5.53%3.54%-6.25%

3.54%-6.25% 746 797 NOTES PAYABLE TO TRUST (d)2037-2043 7.06%5.25-8.00% 331 EQUITY UNIT SENIOR NOTES (e)2007 5.75%5.75%5.75%345 345 OTHER LONG-TERNI DEBT (g)Equity Unit Contract Adjustment Payments Unamortized Discount (net)Total Long-term Debt Outstanding Less Portion Due Within One Year Long-term Portion 247 247 19 (68)14,101 1,779 31 (32)10,190 1.327 (a) First mortgage bonds are secured by first mortgage liens on electric property, plant and equipment.(b) For certain series of installment purchase contracts, interest rates are subject to periodic adjustment. Certain series

ill be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and standby bond purchase agreements support certain series.(c) Notes payable represent outstanding promissory notes issued under term loan agreements and revolving credit agreements with a number of banks and other financial institutions.

At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates.(d) Notes Payable to Trust is a result of a deconsolidation of TCC, PSO and SWEPCo's trusts effective July 1, 2003 due to the implementation of FIN 46. See Notes 2 and 17 for further information.(e) In May 2005, the interest rate on these Equity Unit Senior Notes can be reset through a remarketing.(f) Installment Purchase Contracts and Notes Payable include $257 million and $185 million, respectively, due to the implementation of FIN 46 (see Note 2). Notes Payable includes $496 million of a merchant power generation facility which was consolidated as of December 31, 2003 (see Notes 10 and 16).(g) Other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear fuel (see Note 7) and a financing obligation under a sale and leaseback agreement. LONG-TERNI DEBT OUTSTANDING AT DECEMBER 31,2003 IS PAYABLE AS FOLLOWS: 2004 2005 2006 2007 (in millions);2,187 $1,124 2008 ImterYears TOTAL, Principal Amount Equity Unit Contract Adjustment Payments Unamortizcd Discount S1,779 $1,273 1$587$7,200 $14,150 19.(684 A-52 AMERICAN ELECTRIC POWVER, INC. AND SUBSIDIARY COMPANIES INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies 2. New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes 3. Goodwill and Other Intangible Assets 4. Rate Matters 5. Effects of Regulation

6. Customer Choice and Industry Restructuring

7. Commitments and Contingencies

8. Guarantees

9. Sustained Earnings Improvement Initiative

10. Acquisitions, Dispositions, Discontinued Operations, Impairments, Assets Held for Sale and Assets Held and Used 11. Benefit Plans 12. Stock-Based Compensation

13. Business Segments 14. Derivatives, Hedging and Financial Instruments

15. Income Taxes 16. Leases 17. Financing Activities

18. Unaudited Quarterly Financial Information

19. Subsequent Events (Unaudited)

A-53 AMERICAN ELECTRIC PONVER COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ORGANIZATION AND

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES ORGANIZATION Our principal business conducted by our eleven domestic electric utility operating companies is the generation, transmission and distribution of electric power. These companies are subject to regulation by the FERC under the Federal Power Act and maintain accounts in accordance with 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 and Europe. In addition, our domestic operations include non-regulated independent power and cogeneration facilities, coal mining and intra-state natural gas operations in Louisiana and Texas.International operations include the generation and supply of power in the United Kingdom, and to a lesser extent in Mexico, Australia and China. These operations are either wholly-owned or partially-owned by our various subsidiaries. We also conduct domestic barging operations, provide various energy related services and furnish communications-related services domestically. During 2003 we announced plans to significantly restructure and dispose of many of our non-regulated operations. See Note 10 for a discussion of the impacts of these plans on our organization. Certain previously reported amounts have been reclassified to conform to current classifications with no effect on net income or shareholders' equity.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES Rate Regulation We are subject to regulation by the SEC under the PUHCA. The rates charged by the domestic utility subsidiaries are approved by the FERC and the state utility commissions. The FERC regulates w*holesale electricity operations and transmission rates and the state commissions regulate retail rates. The prices charged by foreign subsidiaries located in China and Mexico are regulated by the authorities of those countries and are generally subject to price controls.Principles of Consolidation Our consolidated financial statements include AEP and its wholly-owned and majority-owned subsidiaries consolidated with their wholly-owned subsidiaries or substantially controlled variable interest entities. Intercompany items are eliminated in consolidation. Equity investments not substantially controlled that are 50% or less owned are accounted for using the equity method of accounting; equity earnings are included in Other Income. We also have generating units that are jointly owned with unaffiliated companies. The proportionate share of the operating costs associated with such facilities is included in our Consolidated Statements of Operations and the investments are reflected in our Consolidated Balance Sheets.Accouwnting for the Effects of Cost-Based Regulation As the owner of cost-based rate-regulated electric public utility companies, our consolidated financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues. We discontinued the application of SFAS 71 for the generation portion of our business as follows: in Ohio by OPCo and CSPCo in September 2000, in Virginia and WVest Virginia by APCo in June A-54 2000, in Texas by TCC, TNC, and SWVEPCo in September 1999, in Arkansas by SWEPCo in September 1999 and in the FERC jurisdiction for TNC in December 2003. During 2003, APCo reapplied SFAS 71 for West Virginia and SWVEPCo reapplied SFAS 71 for Arkansas.Use of Estinates The preparation of these financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include but are not limited to inventory valuation, allowance for doubtful accounts, goodwill and intangible asset impairment, unbilled electricity revenue, values of long-term energy contracts, the effects of regulation, long-lived asset recovery, the effects of contingencies and certain assumptions made in accounting for pension benefits. Actual results could differ from those estimates. Property, Plant and Equipmnent Domestic electric utility property, plant and equipment are stated at original purchase cost. Property, plant and equipment of the non-regulated operations and other investments are stated at their fair market value at acquisition (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. For cost-based rate-regulated operations, retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreciation. For non-regulated operations, retirements from the plant accounts and associated salvage are deducted from accumulated depreciation and removal costs are charged to expense. The costs of labor, materials and overhead incurred to operate and maintain plant are included in operating expenses. Assets are tested for impairment as required under SFAS 144 (see Note 10).Allowance for Fund(ts Used During Construction (AFUDC) and Interest Capitalization AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. For non-regulated operations, interest is capitalized during construction in accordance with SFAS 34, "Capitalization of Interest Costs." Capitalized interest is also recorded for domestic generating assets in Ohio, Texas and Virginia, effective with the discontinuance of SFAS 71 regulatory accounting. The amounts of AFUDC and interest capitalized ,were not material in 2003, 2002 and 2001.Depreciation, Depletion andAmortization We provide for depreciation of property, plant and equipment on a straight-line basis over the estimated useful lives of property, excluding coal-mining properties, generally using composite rates by functional class as follows: Functional Class of Properht Annual Composite Depreciation Rates Ranges 2003 2002 2001 Production: Steam-Nuclear 2.5% to 3.4% 2.5% to 3.4% 2.5% to 3.4%Steam-Fossil-Fired 2.3% to 4.6% 2.6% to 4.5% 2.5% to 4.5%Hydroelectric-Conventional and Pumped Storage 1.9% to 3.4% 1.9% to 3.4% 1.9% to 3.4%Transmission 1.7%to 2.8% 1.7%to 3.0% 1.7%to 3.1%Distribution 3.3% to 4.2% 3.3% to 4.2% 2.7% to 4.2%Other 1.8%to 16.7% 1.8%to 9.9%0 1.8%to 15.0%We provide for depreciation, depletion and amortization of coal-mining assets over each asset's estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. We use either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. We include these costs in the cost of coal charged to fuel expense. Average amortization rates for coal rights and mine development costs were $0.25 per ton in 2003, $0.32 per ton in 2002 and $2.06 per ton in 2001. In 2002, certain coal-mining assets were impaired by $60 A-55 million leading to the decline in amortization rates in 2003. In 2001, an AEP subsidiary sold coal mines in Ohio and West Virginia leading to the decline in amortization rates in 2002.Valuation of Nlon-Derivative Financial Instruentes The book values of Cash and Cash Equivalents, Accounts Receivable, Short-term Debt and Accounts Payable approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value.Cash and Cash Equivaleitts Cash and cash equivalents include temporary cash investments with original maturities of three months or less.Inventory Except for PSO, TCC and TNC, the regulated domestic utility companies value fossil fuel inventories using a weighted average cost method. PSO, TCC and TNC, utilize the LIFO method to value fossil fuel inventories. For those domestic utilities whose generation is unregulated, inventory of coal and oil is carried at the lower of cost or market. Coal mine inventories are also carried at the lower of cost or market. Materials and supplies inventories are carried at average cost. Non-trading gas inventory is carried at the lower of cost or market. During 2003 a fair value hedging strategy was implemented for certain non-trading gas and coal inventory. Changes in the fair value of hedged inventory are recorded to the extent offsetting hedges are designated against that inventory. Accounts Receivable Customer accounts receivable primarily includes receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to our risk management activities and customer receivables primarily related to other revenue-generating activities. We recognize revenue from electric power and gas sales when we deliver power or gas to our customers. To the extent that deliveries have occurred but a bill has not been issued, *ve accrue and recognize, as Accrued Unbilled Revenues, an estimate of the revenues for energy delivered since the latest billings.AEP Credit, Inc. factors accounts receivable for certain registrant subsidiaries. These subsidiaries include CSPCo, I&M, KPCo, OPCo, PSO, SWVEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in all of its regulatory jurisdictions, only a portion of APCo's accounts receivable are sold to AEP Credit. AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140, allowing the receivables to be taken off of the company's balance sheet. See Note 17 "Financing Activities" for further details.Foreitgn Currency Translation The financial statements of subsidiaries outside the U.S. which are included in our consolidated financial statements are measured using the local currency as the functional currency and translated into U.S. dollars in accordance with SFAS 52 "Foreign Currency Translation." Although the effects of foreign currency fluctuations are mitigated by the fact that expenses of foreign subsidiaries are generally incurred in the same currencies in which sales are generated, the reported results of operations of our foreign subsidiaries are affected by changes in foreign currency exchange rates and, as compared to prior periods, will be higher or lower depending upon a weakening or strengthening of the U.S. dollar. Revenues and expenses are translated at monthly average foreign currency exchange rates throughout the year. Assets and liabilities are translated into U.S. dollars at year-end foreign currency exchange rates. Accordingly, our consolidated common shareholders' equity will fluctuate depending on the relative strengthening or weakening of the U.S. dollar versus relevant foreign currencies. Currency translation gain and loss adjustments are recorded in shareholders' equity as Accumulated Other Comprehensive Income (Loss). The impact of the changes in exchange rates on cash, resulting from the translation of items at different exchange rates, is shown on our Consolidated A-56 Statements of Cash Flows in Effect of Exchange Rate Change on Cash. Actual currency transaction gains and losses are recorded in income when they occur.Deferred Fuel Costs The cost of fuel consumed is charged to expense when the fuel is burned. Where applicable under governing state regulatory commission retail rate orders, fuel cost over-recoveries (the excess of fuel revenues billed to ratepayers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to ratepayers) are deferred as regulatory assets. These deferrals are amortized when refunded or billed to customers in later months with the regulator's review and approval. The amounts of an over-recovery or under-recovery can also be affected by actions of regulators. When these actions become probable we adjust our deferrals to recognize these probable outcomes. The amount of under-recovered fuel costs deferred under fuel clauses as a regulatory asset was $51 million at December 31, 2003 and $148 million at December 31, 2002. The amount of over-recovered fuel costs deferred under fuel clauses as a regulatory liability wvas $132 million at December 31, 2003 and $90 million at December 31, 2002. See Note 5 "Effects of Regulation" for further information. In general, changes in fuel costs in Kentucky for KPCo, the SPP area of Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo are timely reflected in rates through the fuel cost adjustment clauses in place in those states. Where fuel clauses have been eliminated due to the transition to market pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective January 1, 2002) changes in fuel costs impact earnings. In other state jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have been frozen or suspended for a period of years, fuel cost changes have also impacted earnings. The Michigan fuel clause suspension ended December 31, 2003, and the Indiana freeze is scheduled to end on March 1, 2004. Changes in fuel costs also impact earnings for certain of our Independent Power Producer generating units that do not have long-term contracts for their fuel supply. See Note 4, "Rate Matters" and Note 6, "Customer Choice and Industry Restructuring" for further information about fuel recovery.Revenue Recognition Regulatory Accontling Our consolidated financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period and by matching income with its passage to customers through regulated revenues in the same accounting period. Regulatory liabilities or regulatory assets are also recorded for unrealized gains or losses that occur due to changes in the fair value of physical and financial contracts that are derivatives and that are subject to the regulated ratemaking process.When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example, issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against earnings. A write-off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates.Traditional Electricity Supply and DeliveryActivities Revenues are recognized on the accrual or settlement basis for normal retail and wholesale electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our statement of operations when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when purchased electricity is received and when expenses are incurred.A-57 Domestic Gas Pipeline and Storage Activities Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided, with the exception of certain physical forward gas purchase and sale contracts that are derivatives and that are accounted for using mark-to-market accounting (Resale Gas Contracts). Energy Marketing and Risk Management Activities We engage in wholesale electricity, natural gas and coal marketing and risk management activities. Effective in October 2002, these activities were focused on wholesale markets where we own assets. Our activities include the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options, and over-the-counter options and swaps. Prior to October 2002, we recorded wholesale marketing and risk management activities using the mark-to-market method of accounting. In October 2002, EITF 02-3 precluded mark-to-market accounting for risk management contracts that were not derivatives pursuant to SFAS 133. We implemented this standard for all non-derivative wholesale and risk management transactions occurring on or after October 25, 2002. For non-derivative risk management transactions entered into prior to October 25, 2002, we implemented this standard on January 1, 2003 and reported the effects of implementation as a cumulative effect of an accounting change.After January 1, 2003, we use mark-to-market accounting for wholesale marketing and risk management transactions that are derivatives unless the derivative is designated for hedge accounting or the normal purchase and sale exemption. Revenues and expenses are recognized from wholesale marketing and risk management transactions that are not derivatives when the commodity is delivered. See discussion of EITF 02-3 and Rescission of EITF 98-10 in Note 2.Accountingfor Derivative Instruments We use the mark-to-market method of accounting for derivative contracts. Unrealized gains and losses prior to settlement, resulting from revaluation of these contracts to fair value during the period, are recognized currently. When the derivative contracts are settled and gains and losses are realized, the previously recorded unrealized gains and losses from mark-to-market valuations are reversed.Certain derivative instruments are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge) or as a hedge of a recognized asset, liability or firm commitment (fair value hedge). The gains or losses on derivatives designated as fair value hedges are recognized in Revenues in the Consolidated Statement of Operations in the period of change together with the offsetting losses or gains on the hedged item attributable to the risks being hedged. For derivatives designated as cash flow hedges, the effective portion of the derivative's gain or loss is initially reported as a component of Accumulated Other Comprehensive Income and subsequently reclassified into Revenues in the Consolidated Statement of Operations when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is recognized in Revenues in the Consolidated Statement of Operations immediately (see Note 14).The fair values of derivative instruments accounted for using mark-to-market accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by the appropriate valuation adjustments for items such as discounting, liquidity and credit quality.Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term risk management contracts. We have independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile. Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a A-58 contract's term and at the time a contract settles. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices are not consistent with our approach at estimating current market consensus for forward prices in the current period. This is particularly true for long-term contracts. We recognize all derivative instruments at fair value in our Consolidated Balance Sheets as either "Risk Management Assets" or "Risk Management Liabilities." We do not consider contracts that have been elected normal purchase or normal sale under SFAS 133 to be derivatives. Unrealized and realized gains and losses on all derivative instruments are ultimately included in Revenues in the Consolidated Statement of Operations on a net basis, with the exception of physically settled Resale Gas Contracts for the purchase of natural gas. The unrealized and realized gains and losses on these Resale Gas Contracts are presented as Purchased Gas for Resale in the Consolidated Statement of Operations. Construction Projects for Outside Parties Our entities engage in construction projects for outside parties that are accounted for on the percentage-of-completion method of revenue recognition. This method recognizes revenue in proportion to costs incurred compared to total estimated costs.Debt Instrument Hedging and Related Activities In order to mitigate the risks of market price and interest rate fluctuations, we enter into contracts to manage the exposure to unfavorable changes in the cost of debt to be issued. These anticipatory hedges are entered into in order to manage the change in interest rates between the time a debt offering is initiated and the issuance of the debt (usually a period of 60 days). Gains or losses from these transactions are deferred and amortized over the life of the debt issuance with the amortization included in interest charges. There were no such forward contracts outstanding at December 31, 2003 or 2002.Mlaintenance Maintenance costs are expensed as incurred. If it becomes probable that we will recover specifically incurred costs through future rates a regulatory asset is established to match the expensing of maintenance costs with their recovery in cost-based regulated revenues.Other Income and Other Expenses Non-operational revenue including the nonregulated business activities of our utilities, equity earnings of non-consolidated subsidiaries, gains on dispositions of property, interest and dividends, AFUDC and miscellaneous income, are reported in Other Income. Non-operational expenses including nonregulated business activities of our utilities, losses on dispositions of property, miscellaneous amortization, donations and various other non-operating and miscellaneous expenses, are reported in Other Expenses.A-59 AEP Consolidated Other Income and Deductions: December 31, 2003 2002 2001 (in millions)Other Income: Equity Earnings (Loss) $10 $(15) $30 Non-operational Revenue 129 201 184 Interest 42 26 48 Gain on Sale of Frontera --73 Gain on Sale of REPs (Mutual Energy Companies) 39 129 -Other 167 120 36 Total Other Income $8 $461 .$37J Other Expenses: Property Taxes $20 $20 $15 Non-operational Expenses 112 179 76 Fiber Optic and Datapult Exit Costs --49 Provision for Loss -Airplane --14 Other 95 124 71 Total Other Expenses $223 3-23 .$225 Income Taves and Investnnentt Tax Credits We use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are being amortized over the life of the regulated plant investment. £-cise Tares We act as an agent for some state and local governments and collect from customers certain excise taxes levied by those state or local governments on our customer. We do not recognize these taxes as revenue or expense.Debt and Preferred Stock Gains and losses from the reacquisition of debt used to finance domestic regulated electric utility plant are generally deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt, associated with the regulated business, is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. We report gains and losses on the reacquisition of debt for operations that are not subject to cost-based rate regulation in Other Income and Other Expenses.Debt discount or premium and debt issuance expenses are deferred and amortized utilizing the effective interest rate method over the term of the related debt. The amortization expense is included in interest charges.Where reflected in rates, redemption premiums paid to reacquire preferred stock of certain domestic utility subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in A-60 rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings consistent with the timing of its inclusion in rates in accordance with SFAS 71.Goodwill and Intangible Assets Wohen wve acquire businesses we record the fair value of any acquired goodwill and other intangible assets. Purchased goodwill and intangible assets with indefinite lives are not amortized. We test acquired goodwill and other intangible assets with indefinite lives for impairment at least annually. Intangible assets with finite lives are amortized over their respective estimated lives to their estimated residual values.The policies described above became effective with our adoption of a new accounting standard for goodwill (SFAS 142). For all business combinations with an acquisition date before July 1, 2001, we amortized goodwill and intangible assets with indefinite lives through December 2001, and then ceased amortization. The goodwill associated with those business combinations with an acquisition date before July 1, 2001 was amortized on a straight-line basis generally over 40 years except for the portion of goodwill associated with gas trading and marketing activities which was amortized on a straight-line basis over 10 years. Intangible assets with finite lives continue to be amortized over their respective estimated lives ranging from 2 to 10 years.Nuclear Trust Funds Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions have allowed us to collect through rates to fund future decommissioning and spent fuel disposal liabilities. By rules or orders, the state jurisdictional commissions (Indiana, Michigan and Texas) and the FERC have established investment limitations and general risk management guidelines. In general, limitations include:* Acceptable investments (rated investment grade or above)* Maximum percentage invested in a specific type of investment

Prohibition of investment in obligations of the applicable company or its affiliates Trust funds are maintained for each regulatory jurisdiction and managed by investment managers external to AEP, who must comply with the guidelines and rules of the applicable regulatory authorities.

The trust assets are invested in order to optimize the after-tax earnings of the trust, giving consideration to liquidity, risk, diversification, and other prudent investment objectives. Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are included in Spent Nuclear Fuel and Decommissioning Trusts for amounts relating to the Cook Plant and are included in Assets Held for Sale for amounts relating to the Texas Plants. See "Assets Held for Sale" section of Note 10 for further information regarding the Texas Plants. These securities are recorded at market value. Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. Unrealized gains and losses from securities in these trust funds are reported as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates.Comprehensive Income (Loss)Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to. ovners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).A-61 Componetits ofAccumidated Other Comprehensive Itcome (Loss)Accumulated Other Comprehensive Income (Loss) is included on the balance sheet in the equity section. The following table provides the components that constitute the balance sheet amount in Accumulated Other Comprehensive Income (Loss): Components Foreign Currency Translation Adjustments Unrealized Losses on Securities Available for Sale Unrealized Losses on Cash Flow Hedges Minimum Pension Liability Total December 31, 2003 2002 2001 (in millions)$110 $4 $(113)(1) (2) -(94) (16) (3)(441] (f95) (10)$(6) $)Stock Based Conypeisation Plans At December 31, 2003, we have tvo stock-based employee compensation plans with outstanding stock options, which are described more fully in Note 12. No stock option expense is reflected in our earnings, as all options granted under these plans had exercise prices equal to or above the market value of the underlying common stock on the date of grant.We also grant performance share units, phantom stock units, restricted shares and restricted stock units to employees, as xvell as stock units to non-employee members of the Board of Directors. The Deferred Compensation and Stock Plan for Non-Employee Directors permits directors to choose to defer up to 100 percent of their annual Board retainer in stock units, and the Stock Unit Accumulation Plan for Non-Employee Directors awards stock units to directors. Compensation cost is included in Net Income for the performance share units, phantom stock units, restricted shares, restricted stock units and the Director's stock units.We do not currently intend to adopt the fair-value-based method of accounting for stock options. The following table shows the effect on our Net Income (Loss) and Earnings (Loss) per Share as if we had applied fair value measurement and recognition provisions of FASB Statement No. 123, "Accounting for Stock-Based Compensation," to stock-based employee compensation awards: Year Ended December 31, 2003 2002 2001 (in millions, except per share data)$110 $(519) $971 Net Income (Loss), as reported Add: Stock-based compensation expense included in reported net income, net of related tax effects Deduct: Stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects Pro Forma Net Income (Loss)Earnings (Loss) per Share: Basic -as Reported Basic -Pro Forma (a)2-(7!$l05-(5)-(4)3 (15)$95$3.01$2.98$0.29 $(1.57)$0.27 $(1.59)Diluted -as Reported Diluted -Pro Forma (a)$0.29 $(1.57)$0.27 $(1.59)$3.01$2.97 (a) The pro forma amounts are not representative of the effects on reported net income for future years.A-62 Earnings Per Share (EPS)Basic earnings (loss) per common share is calculated by dividing net earnings (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The effects of stock options have not been included in the fiscal 2002 diluted loss per common share calculation as their effect would have been anti-dilutive. The calculation of our basic and diluted earnings (loss) per common share (EPS) is based on weighted average common shares shown in the table below: 2003 2002 2001 (in millions -except per share amounts)Weighted Average Shares: Average Common Shares Outstanding 385 332 322 Assumed Conversion of Dilutive Stock Options (see Note 12) --1 Diluted Average Common Shares Outstanding 385 332 323 The assumed conversion of stock options does not affect net earnings (loss) for purposes of calculating diluted earnings per share. Our basic and diluted EPS are the same in 2003, 2002 and 2001 since the effect on weighted average common shares outstanding is minimal.Had we reported net income in fiscal 2002, incremental shares attributable to the assumed exercise of outstanding stock options would have increased diluted common shares outstanding by 398,000 shares.Options to purchase 5.6 million, 8.8 million and 0.7 million shares of common stock were outstanding at December 31, 2003, 2002 and 2001, respectively, but were not included in the computation of diluted earnings per share because the options' exercise prices were greater than the year-end market price of the common shares and, therefore, the effect would be antidilutive. In addition, there is no effect on diluted earnings per share related to our equity units (issued in 2002) unless the market value of our common stock exceeds $49.08 per share. There were no dilutive effects from equity units at December 31, 2003 and 2002. If our common stock value exceeds $49.08 we would apply the treasury stock method to the equity units to calculate diluted earnings per share. This method of calculation theoretically assumes that the proceeds received as a result of the forward purchase contracts are used to repurchase outstanding shares. Also see Note 17.Sqppletnenfary Informntion Year Ended December 31, 2003 2002 2001 (in millions)AEP Consolidated Purchased Power -Ohio Valley Electric Corporation (44.2% owned by AEP System) $147 $142 $127 Cash was paid for: Interest (net of capitalized amounts) $741 $792 $972 Income Taxes $163 $336 $569 Noncash Investing and Financing Activities: Acquisitions under Capital Leases $25 $6 $17 Assumption of Liabilities Related to Acquisitions $- $1 $171 Increase in assets and liabilities resulting from: Consolidation of VIEs due to the adoption of FIN 46 (see Note 2) $547 $- $-Consolidation of merchant power generation facility (see Note 16) $496 $- $-Exchange of Communication Investment for Common Stock $- $- $5 A-63 Pois'er Projects We own interests of 50% or less in domestic unregulated power plants with a capacity of 1,043 MW located in Colorado, Florida and Texas. In addition to the domestic projects, we have interests of 50% or less in international power plants totaling 1,1 13 MW (see Note 10, "Acquisitions, Dispositions, Discontinued Operations, Impairmnents, Assets Held for Sale and Assets Held and Used").Investments in power projects that are 50% or less owned are accounted for by the equity method and reported in Investments in Power and Distribution Projects on our Consolidated Balance Sheets (see "Eastex" within the Dispositions section of Note 10). At December 31, 2003, five domestic power projects and three international power investments are accounted for under the equity method. The five domestic projects are combined cycle gas turbines that provide steam to a host commercial customer and are considered either Qualifying Facilities (QFs) or Exempt Wholesale Generators (EWGs) under PURPA. The three international power investments are classified as Foreign Utility Companies (FUCO) under the Energy Policies Act of 1992. Two of the international investments are power projects and the other international investment is a company which owns an interest in four additional power projects.All of the power projects accounted for under the equity method have unrelated third-party partners.Seven of the above power projects have project-level financing, -which is non-recourse to AEP. AEP or AEP subsidiaries have guaranteed $8 million of domestic partnership obligations for performance under power purchase agreements and for debt service reserves in lieu of cash deposits. In addition, AEP has issued letters of credit with maximum future payments of $23 million for domestic power projects and $69 million for international power investments. Reclassyflcations Certain prior period financial statement items have been reclassified to conform to current period presentation. Such reclassifications had no impact on previously reported Net Income (Loss).2. NEW ACCOUNTING PRONOUNCEMENTS, EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGES NEW ACCOUNTING PRONOUNCEMENTS SFAS 132 (revised 2003) "Employers' Disclosure about Pensions and Other Postretirentent Beneflis" In December 2003 the FASB issued SFAS 132 (revised 2003), which requires additional footnote disclosures about pensions and postretirement benefits, some of which are effective beginning with the year-end 2003 financial statements. Other additional disclosures will begin with our 2004 quarterly financial statements or our 2004 year-end financial statements. We will implement new quarterly disclosures when they become effective in the first quarter of 2004, including (a)the amount of net periodic benefit cost for each period for which an income statement is presented, showing separately each component thereof, and (b) the amount of employer contributions paid and expected to be paid during the current year, if significantly different from amounts disclosed at the most recent year-end.We will implement the new year-end disclosure when it becomes effective in the fourth quarter of 2004, concerning information about foreign plans, if appropriate. See Note 11 for these additional 2003 disclosures. SFAS 142 "Goodwill and Other Intangible Assets" SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, and that goodwill and intangible assets be tested annually for impairment. The implementation of SFAS 142 resulted in a$350 million after tax net transitional loss in 2002 for the U.K. and Australian operations and is reported in our Consolidated Statements of Operations as a cumulative effect of accounting change. See Note 3 for further information on goodwill and other intangible assets.A-64 SFAS 143 "AccoatntingforAssel Retirement Obligations" We implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003, which requires entities to record a liability at fair value for any legal obligations for asset retirements in the period incurred.Upon establishment of a legal liability, SFAS 143 requires a corresponding asset to be established which wvill be depreciated over its useful life. SFAS 143 requires that a cumulative effect of change in accounting principle be recognized for the cumulative accretion and accumulated depreciation that would have been recognized had SFAS 143 been applied to existing legal obligations for asset retirements. In addition, the cumulative effect of change in accounting principle is favorably affected by the reversal of accumulated removal cost. These costs had previously been recorded for generation and did not qualify as a legal obligation although these costs were collected in depreciation rates by certain formerly regulated subsidiaries. We completed a review of our asset retirement obligations and concluded that we have related legal liabilities for nuclear decommissioning costs for our Cook Plant and our partial ownership in the South Texas Project, as well as liabilities for the retirement of certain ash ponds, wind farms, the U.K. Plants, and certain coal mining facilities. Since we presently recover our nuclear decommissioning costs in our regulated cash flow and have existing balances recorded for such nuclear retirement obligations, we recognized the cumulative difference between the amount already provided through rates and the amount as measured by applying SFAS 143 as a regulatory asset or liability. Similarly, a regulatory asset was recorded for the cumulative effect of certain retirement costs for ash ponds related to our regulated operations. In 2003, we recorded an unfavorable cumulative effect of $45.4 million after tax for our non-regulated operations ($38.0 million related to Ash Ponds in the Utility Operations segment, $7.2 million related to U.K. Plants in the Investments -UK Operations segment and $0.2 million for Wind Mills in the Investments -Other segment).Certain of our utility operating companies have collected removal costs from ratepayers for certain assets that do not have associated legal asset retirement obligations. To the extent that operating companies have now been deregulated we reversed the balance of such removal costs, totaling $287.2 million, after tax, which resulted in a net favorable cumulative effect in 2003. We have reclassified approximately $1.2 billion of removal costs for our utility operations from accumulated depreciation to Regulatory Liabilities and Deferred Investment Tax Credits in 2003 and to Deferred Credits and Other in 2002. In addition, $9 million is classified as held-for-sale related to the TCC generation assets as of December 31, 2003 and 2002.The net favorable cumulative effect of the change in accounting principle for the year ended December 31, 2003 consists of the following: Pre-tax After-tax Income (Loss) Income (Loss)(in millions)Ash Ponds $(62.8) $(38.0)U.K. Plants, Wind Mills and Coal Operations (11.3) (7.4)Reversal of Cost of Removal 472.6 287.2 Total $398.5 $241.8 We have identified, but not recognized, asset retirement obligation liabilities related to electric transmission and distribution and gas pipeline assets, as a result of certain easements on property on which we have assets. Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property's use. The retirement obligation is not estimable for such easements since we plan to use our facilities indefinitely. The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements. A-65 The following is a reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations: U.K Plants, Wind Mills Nuclear Ash and Coal Decommissioning Ponds Operations Total (in millions)Asset Retirement Obligation Liability at January 1, 2003 $718.3 $69.8 $37.2 $825.3 Accretion Expense 52.6 5.6 2.3 60.5 Liabilities Incurred -8.3 8.3 Foreign Currency Translation --5.3 5.3 Asset Retirement Obligation Liability at December 31, 2003 including Held for Sale 770.9 75.4 53.1 899.4 Less Asset Retirement Obligation Liability Held for Sale: South Texas Project (218.8) --(218.8)U.K. Plants --(28.8) (28.8)Asset Retirement Obligation Liability at December 31,2003 _$75.4 .24.$l Accretion expense is included in Maintenance and Other Operation expense in our accompanying Consolidated Statements of Operations. As of December 31, 2003 and 2002, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $845 million and $716 million, respectively, of which $720 million and$618 million relating to the Cook Plant was recorded in Spent Nuclear Fuel and Decommissioning Trusts in our Consolidated Balance Sheets. The fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities for the South Texas Project totaling $125 million and $98 million as of December 31, 2003 and 2002, respectively, was classified as Assets Held for Sale in our Consolidated Balance Sheets.Pro forma net income and earnings per share are not presented for the years ended December 31, 2002 and 2001 because the pro forma application of SFAS 143 would result in pro forma net income and earnings per share not materially different from the actual amounts reported during those periods.As of December 31, 2002 and 2001, the pro forma liability for asset retirement obligations which has been calculated as if SFAS 143 had been adopted at the beginning of each period was $825 million and $769 million, respectively. SFAS 144 "Accounting for the Inpairment or Disposal of Long-livedAssets" In August 2001, the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-lived Assets" which sets forth the accounting to recognize and measure an impairment loss. This standard replaced, SFAS 121,"Accounting for Long-lived Assets and for Long-lived Assets to be Disposed Of." We adopted SFAS 144 effective January 1, 2002. See Note 10 for discussion of impairments recognized in 2003 and 2002.SFAS 145 "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Techmnical Corrections" In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections" (SFAS 145). SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt," effective for fiscal years beginning after May 15, 2002. SFAS 4 required gains and losses from extinguishment of debt to be aggregated and classified as an extraordinary item if material. In 2003, A-66 we reclassified Extraordinary Losses (Net of Tax) on TCC's reacquired debt of $2 million for 2001 to Other Expenses.SFAS 146 "Accounting for Costs Associated with Exit or DisposalActivities" In June 2002, FASB issued SFAS 146 which addresses accounting for costs associated with exit or disposal activities. This statement supersedes previous accounting guidance, principally EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." Under EITF No. 94-3, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. SFAS 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. SFAS 146 also establishes that the liability should initially be measured and recorded at fair value. The time at which we recognize future costs related to exit or disposal activities, including restructuring, as well as the amounts recognized may be affected by SFAS 146. We adopted the provisions of SFAS 146 for exit or disposal activities initiated after December 31, 2002.SFAS 149 "Aniendlnzent of Statement 133 on Derivative Instrunents and Hedging Activities" On April 30, 2003, the FASB issued Statement No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends SEAS 133 to clarify the definition of a derivative and the requirements for contracts to qualify for the normal purchase and sale exemption. SFAS 149 also amends certain other existing pronouncements. Effective July 1, 2003, we implemented SFAS 149 and the effect was not material to our results of operations, cash flows or financial condition. SFAS 150 "Accounting for Certain Financial Instruments wvith Characteristics of Both Liabilities and Equity" We implemented SFAS 150 effective July 1, 2003. SFAS 150 is the first phase of the FASB's project to eliminate from the balance sheet the "mezzanine" presentation of items with characteristics of both liabilities and equity, including: (1) mandatorily redeemable shares, (2) instruments other than shares that could require the issuer to buy back some of its shares in exchange for cash or other assets and (3) certain obligations that can be settled with shares.Measurement of these liabilities generally is to be at fair value, with the payment or accrual of "dividends" and other amounts to holders reported as interest cost.Beginning with our third quarter 2003 financial statements, we present Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption as a Non-Current Liability. Beginning July 1,2003, we classify dividends on these mandatorily redeemable preferred shares as interest expense. In accordance with SFAS 150, dividends from prior periods remain classified as preferred stock dividends (a component of Preferred Stock Dividend Requirements of Subsidiaries). FIN 45 "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" In November 2002, the FASB issued FIN 45 which clarifies the accounting to recognize liabilities related to issuing a guarantee, as well as additional disclosures of guarantees. We implemented FIN 45 as of January 1, 2003, and the effect was not material to our results of operations, cash flows or financial condition. See Note 8 for further disclosures. FIN 46 (revised December 2003) "Consolidation of Variable Interest Entities" and FIN 46 "Consolidation of Variable Interest Entities" We implemented FIN 46, "Consolidation of Variable Interest Entities," effective July 1, 2003. FIN 46 interprets the application of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. Due to the prospective application of FIN 46, we did not reclassify prior period amounts.A-67 On July 1, 2003, wve deconsolidated Caddis Partners, LLC (Caddis). At December 31, 2002 $759 million was reported as a Minority Interest in Finance Subsidiary. At December 31, 2003 $527 million is reported as a note payable to Caddis, a component of Long-Term Debt. See Note 17 "Financing Activities" for further disclosures. On July 1, 2003, we also deconsolidated the trusts which hold mandatorily redeemable trust preferred securities. Therefore, of the $321 million net amount reported as "Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such Subsidiaries" at December 31, 2002, $331 million is reported as Notes Payable to Trust (included in Long-term Debt) and $10 million is reported in Other Non-Current Assets at December 31, 2003.Effective July 1, 2003, SWVEPCo consolidated Sabine Mining Company (Sabine), a contract mining operation providing mining services to SWEPCo. Upon consolidation, SWEPCo recorded the assets and liabilities of Sabine ($77.8 million). Also, after consolidation, SNVEPCo currently records all expenses (depreciation, interest and other operation expense) of Sabine and eliminates Sabine's revenues against SWVEPCo's fuel expenses. There is no cumulative effect of accounting change recorded as a result of our requirement to consolidate, and there is no change in net income due to the consolidation of Sabine.Effective July 1, 2003, OPCo consolidated JMG. Upon consolidation, OPCo recorded the assets and liabilities of JMG ($469.6 million). OPCo now records the depreciation, interest and other operating expenses of JMG and eliminates JMG's revenues against OPCo's operating lease expenses. There is no cumulative effect of accounting change recorded as a result of our requirement to consolidate JMG, and there is no change in net income due to the consolidation of JMG. See Note 16 "Leases" for further disclosures. In December 2003, the FASB issued FIN 46 (revised December 2003) (FIN 46R) which replaces FIN 46. The FASB and other accounting constituencies continue to interpret the application of FIN 46R. As a result, we are continuing to review the application of this new interpretation and expect to adopt FIN 46R by March 31, 2004.EITF 02-3 and Rescission of EITF 98-10 In October 2002, the Emerging Issues Task Force of the FASB reached a final consensus on Issue No. 02-3. EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. Under EITF 02-3, mark-to-market accounting is precluded for risk management contracts that are not derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 also eliminated the recognition of physical inventories at fair value other than as provided by GAAP. We have implemented this standard for all physical inventory and non-derivative risk management transactions occurring on or after October 25, 2002. For physical inventory and non-derivative risk management transactions entered into prior to October 25, 2002, we implemented this standard on January 1, 2003 and reported the effects of implementation as a cumulative effect of an accounting change. We recorded a $49 million loss, net of income tax, as a cumulative effect of accounting change.Effective January 1, 2003, EITF 02-3 requires that gains and losses on all derivatives, whether settled financially or physically, be reported in the income statement on a net basis if the derivatives are held for risk management purposes. Previous guidance in EITF 98-10 permitted contracts that were not settled financially to be reported either gross or net in the income statement. Prior to the third quarter of 2002, we recorded and reported upon settlement, sales under fonvard risk management contracts as revenues; we also recorded and reported purchases under forward risk management contracts as purchased energy expenses. Effective July 1, 2002, we reclassified such forward risk management revenues and purchases on a net basis. The reclassification of such risk management activities to a net basis of reporting resulted in a substantial reduction in both revenues and purchased energy expense, but did not have any impact on our financial condition, results of operations or cash flows.EITF 03-11 "Reporting Realized Gains and Losses on Derivative Instrwnnents That Are Subject to FASB Statentent No. 133 and Not "Heldfor Trading Purposes" as Defined in Issue No. 02-3" In July 2003, the EITF reached consensus on Issue No. 03-11. The consensus states that realized gains and losses on derivative contracts not "held for trading purposes" should be reported either on a net or gross basis based on the relevant facts and circumstances. Reclassification of prior year amounts is not required. The adoption of EITF 03-11 did not have a material impact on our results of operations, financial position or cash flows.A-68 FASB Staff Position No. 106-1, Accounting and Disclosure Requiremnents Related to the AMedicare Prescription Drug Inmprotensent anAl Modernization Act of 2003 On January 12, 2004, the FASB Staff issued FSP 106-1, which allows a one-time election to defer accounting for any effects of the prescription drug subsidy under the Medicare Prescription Drug Improvement and Modemization Act of 2003 (the Act), enacted on December 8, 2003. There are significant uncertainties as to whether our plan will be eligible for a subsidy under future federal regulations that have not yet been drafted. The method of accounting for any such subsidy and, therefore, the subsidy's possible reduction to our accumulated postretirement benefit obligation and periodic postretirement benefit costs has not been resolved by the FASB or other professional accounting standard setting authority. Accordingly, we elected to defer any potential effects of the Act until authoritative guidance on the accounting for the federal subsidy is issued. Our measurements of the accumulated postretirement benefit obligation and periodic postretirement benefit cost included in these financial statements do not reflect any potential effects of the Act. We cannot determine what impact, if any, new authoritative guidance on the accounting for the federal subsidy may have on our results of operations or financial condition. FutureAccounting Changes The FASB's standard-setting process is ongoing. Until new standards have been finalized and issued by FASB, we cannot determine the impact on the reporting of our operations that may result from any such future changes.CUMULATIVE EFFECT OF ACCOUNTING CHANGES Accouiitingfor Risk AManagement Contracts EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. We recorded a $49 million after tax charge against net income as Accounting for Risk Management Contracts in our Consolidated Statements of Operations in Cumulative Effect of Accounting Changes in the first quarter of 2003 ($12 million in Utility Operations, $22 million in Investments -Gas Operations and $15 million in Investments -UK Operations segments). This amount will be realized when the positions settle.The FASB's Derivative Implementation Group (DIG) issued accounting guidance under SFAS 133 for certain derivative fuel supply contracts with volumetric optionality and derivative electricity capacity contracts. This guidance, effective in the third quarter of 2001, concluded that fuel supply contracts with volumetric optionality cannot qualify for a normal purchase or sale exclusion from mark-to-market accounting and provided guidance for determining when certain option-type contracts and forward contracts in electricity can qualify for the normal purchase or sale exclusion. The effect of initially adopting the DIG guidance at July 1, 2001 wvas a favorable earnings mark-to-market after tax effect of $18 million (net of tax of $2 million). It was reported as a cumulative effect of an accounting change on our Consolidated Statements of Operations (included in Investments -Other segment).Asset Retirement Obligations (SFAS 143)In the first quarter of 2003, we recorded $242 million in after-tax income as a cumulative effect of accounting change for Asset Retirement Obligations. Goodwill and Other Intangible Assets SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized and be tested annually for impairment. The implementation of SFAS 142 in 2002 resulted in a $350 million net transitional loss for our U.K. and Australian operations (included in the Investments -Other segment) and is reported in our Consolidated Statements of Operations as a cumulative effect of accounting change (see Note 3, "Goodwill and Other Intangible Assets" for further details).A-69 See table below for details of the Cumulative Effect of Accounting Changes: YearEnded December31, Description 2003 2002 2001 (in millions)Accounting for Risk Management Contracts (EITT 02-3) $(49) $- $-Asset Retirement Obligations (SFAS 143) 242 -Goodwill and Other Intangible Assets -(350)Accounting for Risk Management Contracts (DIG Guidance) -18 Total $121 $(2)EXTRAORDINARY ITEMS In 2001, we recorded an extraordinary item for the discontinuance of regulatory accounting under SFAS 71 for the generation portion of our business in the Ohio state jurisdiction. OPCo and CSPCo recognized an extraordinary loss of $48 million (net of tax of $20 million) for unrecoverable Ohio Public Utility Excise Tax (commonly known as the Gross Receipts Tax -GRT) net of allowable Ohio coal credits. This loss resulted from regulatory decisions in connection with Ohio deregulation wvhich stranded the recovery of the GRT. Effective with the liability affixing on May 1, 2001, CSPCo and OPCo recorded an extraordinary loss under SFAS 101. Both Ohio companies appealed to the Ohio Supreme Court the PUCO order on Ohio restructuring that the Ohio companies believe failed to provide for recovery for the final year of the GRT. In April 2002, the Ohio Supreme Court denied recovery of the final year of the GRT.A-70

3. GOODWILL AND OTHER INTANGIBLE ASSETS GOODWILL The changes in our carrying amount of goodwill for the years ended December 31, 2003 and 2002 by operating segment are: Investments Utility Gas UK AEP Operations Operations Operations Other Consolidated (in millions)Balance at January 1,2002 (including Assets Held for Sale) $37.1 $340.1 $- $14.9 $392.1 Goodwill acquired --2.3 -2.3 Changes to Goodwill due to Purchase price adjustments

-(33.8) 172.5 42.4 181.1 Impairment losses --(170.0) (15.9) (185.9)Foreign currency exchange rate changes --6.4 -6.4 Balance at December31, 2002 (including Assets Held for Sale) 37.1 306.3 11.2 41.4 396.0 Less: Assets Held for Sale, Net (a) -(143.8) (11.2) -(155.0 Balance at December 31, 2002 (excluding Assets Held for Sale) S11- $162 $ $4114 $2AL9 Balance at January 1,2003 (including Assets Held for Sale) $37.1 $3063 $11.2 $41.4 $396.0 Impairment losses -(291.4) (12.2) (303.6)Foreign currency exchange rate changes --1.0 -1.0 Balance at December 31, 2003 (including Assets Held for Sale) 37.1 14.9 -41.4 93.4 Less: Assets Held for Sale, Net (a) -(14.9) _ (14.9 Balance at December 31,2003 (excluding Assets Held for Sale) $SLL .$-. .$:- $414. _$78&5 (a) On our Consolidated Balance Sheets, amounts related to entities classified as held for sale are excluded from Goodwill and are reported within Assets Held for Sale (see Note 10). The following entities classified as held for sale had goodwill or goodwill impairments during the years ended December 31, 2003 or 2002:* Jefferson Island (Investments -Gas Operations segment)- $14.4 million and $143.3 million balances in goodwill at December 1, 2003 and 2002, respectively. During 2003, we recognized a goodwill impairment loss of $128.9 million.* LIG Chemical (Investments -Gas Operations segment) -$0.5 million balance in goodwill at December 31, 2003 and 2002.* U.K. Coal Trading (Investments -UK Operations segment) -$11.2 million balance in goodwill at December 31, 2002. In 2003, we recognized a goodwill impairment loss of $12.2 million related to the impairment study (impairment in 2003 nwas greater than December 31, 2002 balance due to changes in foreign currency translation rates).* U.K. Generation (Investments -UK Operations segment) -No goodwill balances at December 31, 2003 or 2002. In 2002, we recognized a goodwill impairment loss of $166.0 million related to the impairment study.* AEP Coal (Investments -Other segment) -No goodwill balances at December 31, 2003 or 2002. In 2002, we recognized a $3.6 million impairment loss related to the impairment study.A-71 Accumulated amortization of goodwill vas approximately $1 million and $9 million at December 31, 2003 and 2002, respectively. The decrease of $8 million between years is related to the impairment of goodwill on Houston Pipe Line Company and AEP Energy Services.In the fourth quarter of 2003, we prepared our annual goodwill impairment tests. The fair values of the operations were estimated using cash flow projections and other market value indicators. As a result of the tests, we recognized a $162.5 million goodwill impairment loss related to Houston Pipe Line Company ($150.4 million) and AEP Energy Services ($12.1 million).During 2002, changes to goodwill were due to purchase price adjustments of $6.7 million primarily related to our acquisition of Houston Pipe Line Company, MEMCO and Nordic Trading (see Note 10).In the first quarter of 2002, we recognized a goodwill impairment loss of $12.3 million for all goodwill related to Gas Power Systems (see Note 10).In the fourth quarter of 2002, we prepared our annual goodwill impairment tests. The fair values of the operations were estimated using cash flow projections. As a result of the tests, we recognized a goodwill impairment loss of $4.0 million related to Nordic Trading (see Note 10).The transitional impairment loss related to SEEBOARD and CitiPower goodwill, which is reported as Cumulative Effect of Accounting Changes in 2002, is excluded from the above schedule.The following tables show the transitional disclosures to adjust our reported net income (loss) and earnings (loss) per share to exclude amortization expense recognized in prior periods related to goodwill and intangible assets that are no longer being amortized. Net Income (Loss) Year Ended December 31, 2003 2002 2001 (in millions)Reported Net Income (Loss) $110 $(519) $971 Add back: Goodwill amortization --39(a)Add back: Amortization for intangibles with indefinite lives --8(b)Adjusted Net Income (Loss) $110 JJ10 SI.Earnings (Loss) Per Share (Basic and Dilutive) Year Ended December 31, 2003 2002 2001 Reported Earnings (Loss) per Share $0.29 $(1.57) $3.01 Add back: Goodwill amortization --0.12(c)Add back: Amortization for intangibles with indefinite lives --0.02(b)Adjusted Earnings (Loss) per Share 2(1 MM) $215 (a) This amount includes $34 million in 2001 related to SEEBOARD and CitiPower amortization expense included in Discontinued Operations on our Consolidated Statements of Operations.(b) The amounts shown for 2001 relate to CitiPower amortization expense included in Discontinued Operations on our Consolidated Statements of Operations.(c) This amount includes $0.10 in 2001 related to SEEBOARD and CitiPower amortization expense included in Discontinued Operations on our Consolidated Statements of Operations. A-72 OTHER INTANGIBLE ASSETS Acquired intangible assets subject to amortization are $34 million at December 31, 2003 and $37 million at December 31, 2002, net of accumulated amortization. The gross carrying amount, accumulated amortization and amortization life by major asset class are: Software and customer list (a)Software acquired (b)Patent Easements Trade name and administration of contracts Purchased technology Advanced royalties Amortization Life (in years)2 3 5 10 7 10 10 December31, 2003 Gross Carrying Accumulated Amount Amortization (in millions)0.5 0.3 0.1 2.2 0.3 December 31, 2002 Gross Carrying Accumulated Amount Amortization (in millions)$0.5 $0.2 0.5 0.1 2.4 10.9 29.4 0.9 2.2 7.7 2.4 10.3 29.4 0.6 1.0 4.7 Total$W5-S$1.(a) This asset was disposed of in the second quarter of 2003.(b) This asset relates to U.K. Generation Plants and is included in Assets Balance Sheets.Held for Sale on our Consolidated Amortization of intangible assets was $5 million and $4 million for the twelve months ended December 31, 2003 and 2002, respectively. Our estimated aggregate amortization expense is $5 million for each year 2004 through 2007, $4 million for 2008 through 2010 and $3 million in 2011.4. RATE MATTERS In certain jurisdictions, we have agreed to base rate or fuel recovery limitations usually under terms of settlement agreements. See Note 5 for a discussion of those terms related to Nuclear Plant Restart and Merger with CSW.Fuel in SPPArea of Texas In 2001, the PUCT delayed the start of customer choice in the SPP area of Texas. In May 2003, the PUCT ordered that competition would not begin in the SPP areas before January 1, 2007. TNC filed with the PUCT in 2002 to determine the most appropriate method to reconcile fuel costs in TNC's SPP area. In April 2003, the PUCT issued an order adopting the methodology proposed in TNC's filing, with adjustments, for reconciling fuel costs in the SPP area. The adjustments removed $3.71 per MWH from reconcilable fuel expense. This adjustment will reduce revenues received by Mutual Energy SWEPCo who now serves TNC's SPP customers by approximately $400,000 annually. In October 2003, Mutual Energy SWEPCo agreed with the PUCT staff and the Office of Public Utility Counsel (OPC) to file a fuel reconciliation proceeding for the period January 2002 through December 2003 by March 31, 2004 and the PUCT ordered that the filing be made.TNC Fuel Reconciliations In June 2002, TNC filed with the PUCT to reconcile fuel costs, requesting to defer any unrecovered portion applicable to retail sales within its ERCOT service area for inclusion in the 2004 true-up proceeding. This reconciliation for the period of July 2000 through December 2001 will be the final fuel reconciliation for TNC's ERCOT service territory. At December 31, 2001, the deferred under-recovery balance associated with TNC's ERCOT service area was $27.5 million including interest. During the reconciliation period, TNC incurred $293.7 million of eligible fuel costs serving both ERCOT and SPP retail customers. TNC also requested authority to surcharge its SPP customers for under-recovered fuel costs. TNC's SPP customers will continue to be subject to fuel reconciliations until competition A-73 begins in the SPP area as described above. The under-recovery balance at December 31, 2001 for TNC's service within SPP was $0.7 million including interest.In March 2003, the AU1 in this proceeding filed a Proposal for Decision (PFD) with a recommendation that TNC's under-recovered retail fuel balance be reduced. In March 2003, TNC established a reserve of $13 million based on the recommendations in the PFD. In May 2003, the PUCT reversed the AU on certain matters and remanded TNC's final fuel reconciliation to the AU to consider two issues. The issues are the sharing of off-system sales margins from AEP's trading activities with customers for five years per the PUCT's interpretation of the Texas AEP/CSW merger settlement and the inclusion of January 2002 fuel factor revenues and associated costs in the determination of the under-recovery. The PUCT proposed that the sharing of off-system sales margins for periods beyond the termination of the fuel factor should be recognized in the final fuel reconciliation proceeding. This would result in the sharing of margins for an additional three and one half years after the end of the Texas ERCOT fuel factor.On December 3, 2003, the AU issued a PFD in the remand phase of the TNC fuel reconciliation recommending additional disallowances for the two remand issues. TNC filed responses to the PFD and the PUCT announced a final ruling in the fuel reconciliation proceeding on January 15, 2004 accepting the PFD. TNC is waiting for a written order, after which it will request a rehearing of the PUCT's ruling. While management believes that the Texas merger settlement only provided for sharing of margins during the period fuel and generation costs were regulated by the PUCT, an additional provision of$10 millionwasrecorded in December2003. Based on the decisionsofthe PUCT, TNC's final under-recovery including interest at December 31, 2003 was $6.2 million.In February 2002, TNC received a final order from the PUCT in a previous fuel reconciliation covering the period July 1997 to June 2000 and reflected the order in its financial statements. This final order was appealed to the Travis County District Court. In May 2003, the District Court upheld the PUCT's final order. That order is currently on appeal to the Third Court of Appeals.TCC Fuel Reconciliation In December 2002, TCC filed its final fuel reconciliation with the PUCT to reconcile fuel costs to be included in its deferred over-recovery balance in the 2004 true-up proceeding. This reconciliation covers the period of July 1998 through December 2001. At December 31, 2001, the over-recovery balance for TCC was $63.5 million including interest. During the reconciliation period, TCC incurred $1.6 billion of eligible fuel and fuel-related expenses.Based on the PUCT ruling in the TNC proceeding relating to similar issues, TCC established a reserve for potential adverse rulings of $81 million during 2003. In July 2003, the AU requested that additional information be provided in the TCC fuel reconciliation related to the impact of the TNC orders, referenced above, on TCC. On February 3, 2004, the AU issued a PFD recommending that the PUCT disallow $140 million in eligible fuel costs including some new items not considered in the TNC case, and other items considered but not disallowed in the TNC ruling. At this time, management is unable to predict the outcome of this proceeding. An adverse ruling from the PUCT, disallowing amounts in excess of the established reserve could have a material impact on future results of operations, cash flows and financial condition. Additional information regarding the 2004 true-up proceeding for TCC can be found in Note 6 "Customer Choice and Industry Restructuring." SIVEPCo Texas Fuel Reconciliation In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs in SPP. This reconciliation covers the period of January 2000 through December 2002. At December 31, 2002, SWEPCo's filing included a $2 million deferred over-recovery balance including interest. During the reconciliation period, SWVEPCo incurred $435 million of Texas retail eligible fuel expense. In November 2003, intervenors and the PUCT Staff recommended fuel cost disallowances of more than $30 million. In December 2003, SWEPCo agreed to a settlement in principle with all parties in the fuel reconciliation. The settlement provides for a disallowance in fuel costs of $8 million which was recorded in December 2003. In addition, the settlement provides for the deferral as a regulatory asset of costs of a new lignite mining agreement in excess of a specified benchmark for lignite at SWVEPCo's Dolet Hills Plant. The settlement provides for recovery of the deferred costs over a period ending in April 2011 as cost savings are realized under the new mining agreement. The settlement also will allow future recovery of litigation costs associated with the A-74 termination of a previous lignite mining agreement if future costs savings are adequate. The settlement will be filed with the PUCT for approval.ERCOTPrice-to-Beat (PTB) Fitel Factor Appeal Several parties including the Office of Public Utility Counsel (OPC) and cities served by both TCC and TNC appealed the PUCT's December 2001 orders establishing initial PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU. On June 25, 2003, the District Court ruled in both appeals. The Court ruled in the Mutual Energy WTU case that the PUCT lacked sufficient evidence to include unaccounted for energy in the fuel factor, and that the PUCT improperly shifted the burden of proof and the record lacked substantial evidence on the effect of loss of load due to retail competition on generation requirements. The Court upheld the initial PTB orders on all other issues. In the Mutual Energy CPL proceeding, the Court ruled that the PUCT improperly shifted the burden of proof and the record lacked substantial evidence on the effect of loss of load due to retail competition on generation requirements. The amount of unaccounted for energy built into the PTB fuel factors wvas approximately $2.7 million for Mutual Energy WTU. At this time, management is unable to estimate the potential financial impact related to the loss of load issue. The District Court decision was appealed to the Third Court of Appeals by Mutual Energy CPL, Mutual Energy WVTU and other parties. Management believes, based on the advice of counsel, that the PUCT's original decision will ultimately be upheld. If the District Court's decisions are ultimately upheld, the PUCT could reduce the PTB fuel factors charged to retail customers in 2002 and 2003 resulting in an adverse effect on future results of operations and cash flows.Unbimudled Cost of Service (UCOS) Appeal The UCOS proceeding established the regulated wires rates to be effective when retail electric competition began.TCC placed new transmission and distribution rates into effect as of January 1, 2002 based upon an order issued by the PUCT resulting from TCC's UCOS proceeding. TCC requested and received approval from the FERC of wholesale transmission rates determined in the UCOS proceeding; Regulated. delivery charges include the retail transmission and distribution charge and, among other items, a nuclear decommissioning fund charge, a municipal franchise fee, a system benefit fund fee, a transition charge associated with securitization of regulatory assets and a credit for excess earnings. Certain rulings of the PUCT in the UCOS proceeding, including the initial determination of stranded costs, the requirement to refund TCC's excess earnings, regulatory treatment of nuclear insurance and distribution rates charged municipal customers, were appealed to the Travis County District Court by TCC and other parties to the proceeding. The District Court issued a decision on June 16, 2003, upholding the PUCT's UCOS order with one exception. The Court ruled that the refund of the 1999 through 2001 excess earnings, solely as a credit to non-bypassable transmission and distribution rates charged to REPs, discriminates against residential and small commercial customers and is unlawful. The distribution rate credit began in January 2002. This decision could potentially affect the PTB rates charged by Mutual Energy CPL and could result in a refund to certain of its customers. Mutual Energy CPL wvas a subsidiary of AEP until December 23, 2002 when it was sold. Management estimates that the effect of a decision to reduce the PTB rates for the period prior to the sale is approximately $11 million pre-tax. The District Court decision was appealed to the Third Court of Appeals by TCC and other parties.Based on advice of counsel, management believes that it will ultimately prevail on appeal. If the District Court's decision is ultimately upheld on appeal or the Court of Appeals reverses the District Court on issues adverse to TCC, it could have an adverse effect on future results of operations and cash flows.TCC Rate Case On June 26, 2003, the City of McAllen, Texas requested that TCC provide justification showing that its transmission and distribution rates should not be reduced. Other municipalities served by TCC passed similar rate review resolutions. In Texas, municipalities have original jurisdiction over rates of electric utilities within their municipal limits. Under Texas law, TCC must provide support for its rates to the municipalities. TCC filed the requested support for its rates based on a test year ending June 30, 2003 with all of its municipalities and the PUCT on November 3, 2003. TCC's proposal would decrease its wholesale transmission rates by $2 million or 2.5% and increase its retail energy delivery rates by $69 million or 19.2%. On February 9, 2004, eight intervening parties filed testimony recommending reductions to TCC's requested $67 million rate increase. The recommendations range from a decrease in existing rates of approximately $100 million to an increase in TCC's current rates of approximately $27 million. The PUCT Staff filed testimony, on February 17, 2004, recommending reductions to TCC's request of A-75 approximately $51 million. TCC's rebuttal testimony was filed on February 26, 2004. Hearings are scheduled for March 2004 with a PUCT decision expected in May 2004. Management is unable to predict the ultimate effect of this proceeding on TCC's rates or its impact on TCC's results of operations, cash flows and financial condition. Louisiana FuelAutfit The LPSCis performing an audit of SVEPCo's historical fuel costs. In addition, five SVEPCo customers filed a suit in the Caddo Parish District Court in January 2003 and filed a complaint with the LPSC. The customers claim that SWEPCo has over charged them for fuel costs since 1975. The LPSC consolidated the customer complaint and audit.In January 2004, a procedural schedule was issued requiring LPSC Staff and intervenor testimony to be filed in June 2004 and scheduling hearings for October 2004. Management believes that SWVEPCo's fuel costs were proper and those costs incurred prior to 1999 have been approved by the LPSC. Management is unable to predict the outcome of these proceedings. If the actions of the LPSC or the Court result in a material disallowance of recovery of SWEPCo's fuel costs from customers, it could have an adverse impact on results of operations and cash flows.Louisiana Conpliance Filing In October 2002, SWVEPCo filed with the LPSC detailed financial information typically utilized in a revenue requirement filing, including ajurisdictional cost of service. This filing was required by the LPSC as a result of their order approving the merger bet~veen AEP and CSW. The LPSC's merger order also provides that SWVEPCo's base rates are capped at the present level through mid 2005. The filing indicates that SWEPCo's current rates should not be reduced. In 2004 the LPSC required SWEPCo to file updated financial information with a test year ending December 31, 2003 before April 16, 2004. If, after review of the updated information, the LPSC disagrees with our conclusion, they could order SWEPCo to file all documents for a full cost of service revenue requirement review in order to determine whether SWEPCo's capped rates should be reduced which would adversely impact results of operations and cash flows.FERC kWholesale Fuel Conplaints Certain TNC wholesale customers filed a complaint with FERC alleging that TNC had overcharged them through the fuel adjustment clause for certain purchased power costs since 1997.Negotiations to settle the complaint and update the contracts resulted in new contracts. The FERC approved an offer of settlement regarding the fuel complaint and new contracts at market prices in December 2003. Since TNC had recorded a provision for refund in 2002, the effect of the settlement wvas a $4 million favorable adjustment recorded in December 2003.Environnmental Surcharge Filing In September 2002, KPCo filed with the KPSC to revise its environmental surcharge tariff (annual revenue increase of approximately $21 million) to recover the cost of emissions control equipment being installed at the Big Sandy Plant.See NOx Reductions in Note 7.In March 2003, the KPSC granted approximately $18 million of the request. Annual rate relief of $1.7 million became effective in May 2003 and an additional $16.2 million became effective in July 2003. The recovery of such amounts is intended to offset KPCo's cost of compliance with the Clean Air Act.PSO Rate Review In February 2003, the Director of the OCC filed an application requiring PSO to file all documents necessary for a general rate review. In October 2003, PSO filed financial information and supporting testimony in response to the OCC's requirements. PSO's response indicates that its annual revenues are $36 million less than costs. As a result, PSO is seeking OCC approval to increase its base rates by that amount, which is a 3.6% increase over PSO's existing revenues. Hearings are scheduled for October 2004. Management is unable to predict the ultimate effect of this review on PSO's rates or its impact on PSO's results of operations, cash flows and financial condition. A-76 PSO Futel and Purchased Po)ver PSO had a $44 million under-recovery of fuel costs resulting from a 2002 reallocation among AEP WVest companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO filed with the OCC seeking recovery of the $44 million over an 18-month time period. In August 2003, the OCC Staff filed testimony recommending PSO be granted recovery of $42.4 million over three years. In September 2003, the OCC expanded the case to include a full review of PSO's 2001 fuel and purchased power practices. PSO filed its testimony in February 2004 and hearings will occur in June 2004. If the OCC determines as a result of the review that a portion of PSO's fuel and purchased power costs should not be recovered, there will be an adverse effect on PSO's results of operations, cash flows and possibly financial condition. Virginia Fuel Factor Filing APCo filed with the Virginia SCC to reduce its fuel factor effective August 1, 2003. The requested fuel rate reduction wvas approved by the Virginia SCC and is effective for 17 months (August 1, 2003 to December 31, 2004) and is estimated to reduce revenues by $36 million during that period. This fuel factor adjustment will reduce cash flows vithout impacting results of operations as any over-recovery or under-recovery of fuel costs would be deferred as a regulatory liability or a regulatory asset.FERCLong-ferni Contracts In 2002, the FERC set for hearing complaints filed by certain wvholesale customers located in Nevada and Washington that sought to break long-term contracts which the customers alleged were "high-priced." At issue were long-term contracts entered into during the California energy price spike in 2000 and 2001. The complaints alleged that AEP sold power at unjust and unreasonable prices.In February 2003, AEP and one of the customers agreed to terminate their contract. The customer withdrew its FERC complaint and paid $59 million to AEP. As a result of the contract termination, AEP reversed $69 million of unrealized mark-to-market gains previously recorded, resulting in a $10 million pre-tax loss.In December 2002, a FERC ALJ ruled in favor of AEP and dismissed a complaint filed by two Nevada utilities. In 2000 and 2001, we agreed to sell power to the utilities for future delivery. In 2001, the utilities filed complaints asserting that the prices for power supplied under those contracts should be lowered because the market for power was allegedly dysfunctional at the time such contracts were executed. The ALJ rejected the utilities' complaint, held that the markets for future delivery were not dysfunctional, and that the utilities had failed to demonstrate that the public interest required that changes be made to the contracts. In June 2003, the FE-RC issued an order affirming the AL's decision. The utilities requested a rehearing which the FERC denied. The utilities' appeal of the FERC order is pending before the U.S. Court of Appeals for the Ninth Circuit. Management is unable to predict the outcome of this proceeding and its impact on future results of operations and cash flows.RTO Forination/ntegration Costs With FERC approval, AEP East companies have been deferring costs incurred under FERC orders to form an RTO (the Alliance RTO) orjoin an existing RTO (PJM). In July 2003, the FERC issued an order approving our continued deferral of both our Alliance formation costs and our PJM integration costs including the deferral of a carrying charge. The AEP East companies have deferred approximately $28 million of RTO formation and integration costs and related carrying charges through December 31, 2003. As a result of the subsequent delay in the integration of AEP's East transmission system into PJM, FERC declined to rule, in its July order, on our request to transfer the deferrals to regulatory assets, and to maintain the deferrals until such time as the costs can be recovered from all users of AEP's East transmission system. The AEP East companies wvill apply for permission to transfer the deferred formation/integration costs to a regulatory asset prior to integration with PJM. In August 2003, the Virginia SCC filed a request for rehearing of the July order, arguing that FERC's action was an infringement on state jurisdiction, and that FERC should not have treated Alliance RTO startup costs in the same manner as PJM integration costs. On October 22, 2003, FERC denied the rehearing request.A-77 In its July 2003 order, FERC indicated that it would review the deferred costs at the time they are transferred to a regulatory asset account and scheduled for amortization and recovery in the open access transmission tariff (OATT) to be charged by PJM. Management believes that the FERC wvill grant permission for the deferred RTO costs to be amortized and included in the OATT. Whether the amortized costs will be fully recoverable depends upon the state regulatory commissions' treatment of AEP East companies' portion of the OATT at the time they join PJM.Presently, retail base rates are frozen or capped and cannot be increased for retail customers of CSPCo, I&M and OPCo. APCo's Virginia retail base rates are capped with an opportunity for a one-time increase in non-generation rates after January 1, 2004. We intend to file an application with FERC seeking permission to delay the amortization of the deferred RTO formation/integration costs until they are recoverable from all users of the transmission system including retail customers. Management is unable to predict the timing of when AEP will join PJM and if upon joining PJM whether FERC will grant a delay of recovery until the rate caps and freezes end. If the AEP East companies do not obtain regulatory approval to join PJM, we are committed to reimburse PJM for certain project implementation costs (presently estimated at $24 million for the entire PJM integration project). Management intends to seek recovery of the deferred RTO formation/integration costs and project implementation cost reimbursements, if incurred. If the FERC ultimately decides not to approve a delay or the state commissions deny recovery, future results of operations and cash flows could be adversely affected.In the first quarter of 2003, the state of Virginia enacted legislation preventing APCo from joining an RTO prior to July 1, 2004 and thereafter only with the approval of the Virginia SCC, but required such transfers by January 1, 2005. In January 2004, APCo filed with the Virginia SCC a cost/benefit study covering the time period through 2014 as required by the Virginia SCC. The study results show a net benefit of approximately $98 million for APCo over the 11-year study period from AEP's participation in PJM.In July 2003, the KPSC denied KPCo's request to join PJM based in part on a lack of evidence that it would benefit Kentucky retail customers. In August 2003, KPCo sought and was granted a rehearing to submit additional evidence.In December 2003, AEP filed with the KPSC a cost/benefit study showing a net benefit of approximately $13 million for KPCo over the five-year study period from AEP's participation in PJM. A hearing has been scheduled in April 2004.In September 2003, the IURC issued an order approving l&M's transfer of functional control over its transmission facilities to PJM, subject to certain conditions included in the order. The IURC's order stated that AEP shall request and the IURC shall complete a review of Alliance formation costs before any deferral of the costs for future recovery.In November 2003, the FERC issued an order preliminarily finding that AEP must fulfill its CSW merger condition to join an RTO by integrating into PJM (transmission and markets) by October 1, 2004. The order was based on PURPA 205(a), which allows FERC to exempt electric utilities from state law or regulation in certain circumstances. The FERC set for public hearing before an AU several issues. Those issues include whether the laws, rules, or regulations of Virginia and Kentucky are preventing AEP from joining an RTO and whether the exceptions under PURPA apply. The FERC directed the AU to issue his initial decision by March 15, 2004.FERC Order on Regional Through and Out Rates In July 2003, the FERC issued an order directing PJM and the Midwest ISO to make compliance filings for their respective Open Access Transmission Tariffs to eliminate, by November 1, 2003, the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within the proposed Midwest ISO and PJM expanded regions (RTO Footprint). In October 2003, the FERC postponed the November 1, 2003 deadline to eliminate T&O rates. The elimination of the T&O rates will reduce the transmission service revenues collected by the RTOs and thereby reduce the revenues received by transmission owners under the RTOs'revenue distribution protocols. The order provided that affected transmission owners could file to offset the elimination of these revenues by increasing rates or utilizing a transitional rate mechanism to recover lost revenues that result from the elimination of the T&O rates. The FERC also found that the T&O rates of some of the former Alliance RTO companies, including AEP, may be unjust, unreasonable, and unduly discriminatory or preferential for energy delivered in the RTO Footprint. FERC initiated an investigation and hearing in regard to these rates. We made a filing with the FERC to support the justness and reasonableness of our rates. We also made ajoint filing with unaffiliated utilities proposing a regional revenue replacement mechanism for the lost revenues, in the event that FERC eliminated all T&O rates for delivery points within the RTO Footprint. In orders issued in November 2003, the FERC dismissed the joint filing, but adopted a new regional rate design substantially in the form proposed in the joint A-78 filing. The orders directed each transmission provider to file compliance rates to eliminate T&O rates prospectively within the region and simultaneously implement new seams elimination cost allocation (SECA) rates to mitigate the lost revenues for a two-year transition period beginning April 1, 2004. The FERC did not indicate the recovery method for the revenues after the two-year period. As required by the FERC, we filed compliance tariff changes in January 2004 to eliminate the T&O charges within the RTO Footprint. The SECA rate issues that remain unresolved have been set before an AU for settlement procedures, and the effective date of the T&O rate elimination and SECA rates were delayed until May 1, 2004. The November orders have been appealed by a number of parties. The AEP East companies received approximately $150 million of T&O rate revenues from transactions delivering energy to customers in the RTO Footprint for the twelve months ended June 30, 2003. At this time, management is unable to predict whether the new SECA rates will fully compensate the AEP East companies for their lost T&O rate revenues and, consequently, their impact on our future results of operations, cash flows and financial condition. Indiana Fuel Ordler On July 17, 2003, I&M filed a fuel adjustment clause application requesting authorization to implement the fixed fuel adjustment charge (fixed pursuant to a prior settlement of the Cook Nuclear Plant Outage) for electric service for the billing months of October 2003 through February 2004, and for approval of a new fuel cost adjustment credit for electric service to be applicable during the March 2004 billing month.On August 27, 2003, the IURC issued an order approving the requested fixed fuel adjustment charge for October 2003 through February 2004. The order further stated that certain parties must negotiate the appropriate action on fuel to commence on March 1, 2004. Such negotiations are ongoing. The IURC deferred ruling on the March 2004 factor until after January 1, 2004.AMichigan 2004 Fuel Recovery Plan The MPSC's December 16, 1999 order approved a Settlement Agreement regarding the extended outage of the Cook Plant and fixed I&M Powver Supply Cost Recovery (PSCR) factors for the St. Joseph and Three Rivers rate areas through December 2003. In accordance with the settlement, PSCR Plan cases were not required to be filed through the 2003 plan year. As required, I&M filed its 2004 PSCR Plan with the MPSC on September 30, 2003 seeking new fuel and power supply recovery factors to be effective in 2004. The case has been scheduled for hearing. As allowed by Michigan law, the proposed factors were effective on January 1, 2004, subject to review and possible adjustment based on the results of the hearing.A-79

5. EFFECTS OF REGULATION Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: December 31, 2003 2002 (in millions)Regulatory Assets: Income Tax-related Regulatory Assets, Net Transition Regulatory Assets Regulatory Assets Designated for Securitization Texas Wholesale Capacity Auction True-Up Unamortized Loss on Reacquired Debt Cook Nuclear Plant Restart Costs Cook Nuclear Plant Refueling Outage Levelization Deferred Fuel Costs CSW Merger Costs Deferred Fuel Costs (TNC)DOE Decontamination and Decommissioning Assessment Other Total Regulatory Assets Regulatory Liabilities:

Asset Removal Costs Deferred Investment Tax Credits Excess ARO for Nuclear Decommissioning Liability Deferred Over-Recovered Fuel Costs (TCC)Deferred Over-Recovered Fuel Costs Texas Retail Clawback Other Total Regulatory Liabilities $728 529 1,253 480 116 57 24 23 27 21 290$3-548$1,233 422 216 69 63 57 199$2.259$639 743 331 262 83 40 30 121 32 27 26 354$2"68 455 69 21 66 328-$93-9 Future Recovery/Refund Period Various Periods (a)Up to 5 Years (a)(b)(c)Up to 40 Years (d)N/A (e)I Year (a)Up to 5 Years (a)(c)Up to 5 Years (a)Various Periods (f)(h)Up to 26 Years (a)(g)(c)(a)(c)Various Periods (1)(a) Amount does not earn a return.(b) Will be included in TCC's PUCT 2004 true-up proceeding and is designated for possible securitization during 2005.(c) Amount will be included in TCC's and TNC's 2004 true-up proceedings for future recovery/payment over a time period to be determined in a future PUCT proceeding.(d) Amount effectively earns a retum.(e) Amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage and does not earn a return.(f) These regulatory assets and liabilities include items both earning and not earning a return.(g) Amounts are accrued monthly and wvill be paid when the nuclear plant is decommissioned. This also earns a return.(h) The liability for removal costs will be discharged as removal costs are incurred over the life of the plant.Texas Restructuring Related Regulatory Assets and Liabilities Regulatory Assets Designated for Securitization, Texas Wholesale Capacity Auction True-up regulatory assets, Deferred Over-Recovered Fuel Costs and Texas Retail Clawback regulatory liabilities are not being currently recovered from or returned to ratepayers. Management believes that the laws and regulations, established in Texas for industry restructuring, provide for the recovery from ratepayers of these net amounts. See Note 6 for a complete discussion of our plans to recover these regulatory assets, net of regulatory liabilities. A-80 Nuclear Plant Restart I&M completed the restart of both units of the Cook Plant in 2000. Settlement agreements in the Indiana and Michigan retail jurisdictions that addressed recovery of Cook Plant related outage restart costs were approved in .1999 by the IURC and MPSC.The amount of deferrals amortized to other O&M expenses were $40 million in 2003, 2002 and 2001. Also pursuant to the settlement agreements, accrued fuel-related revenues of approximately $37 million in 2003 and $38 million in 2002 and 2001 'vere amortized as a reduction of revenues.The amortization of O&M costs and fuel-related revenues deferred under Indiana and Michigan retail jurisdictional settlement agreements adversely affected results of operations through December 31, 2003 when the amortization period ended.Alerger with csMV On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned subsidiary of AEP. The following table summarizes significant merger-related agreements: Summary of key provisions of Merger Rate Agreements: State/Company Texas -SWEPCo, TCC, TNC Indiana -I&M Michigan -I&M Kentucky -KPCo Oklahoma -PSO Arkansas -SWEPCo Louisiana -SWEPCo Ratemaking Provisions $221 million rate reduction over 6 years. No base rate increases for 3 years post merger.$67 million rate reduction over 8 years.Extension of base rate freeze until January 1, 2005. Requires additional annual deposits of $6 million to the nuclear decommissioning trust fund for the years 2001 through 2003.Customer billing credits of approximately $14 million over 8 years. Extension of base rate freeze until January 1, 2005.Rate reductions of approximately $28 million over 8 years. No base rate increases for 3 years post merger.Rate reductions of approximately $28 million over 5 years. No base rate increase before January 1, 2003.Rate reductions of $6 million over 5 years.No base rate increase before June 15, 2003 Rate reductions to share merger savings estimated to be $18 million over 8 years. Base rate cap until June 2005.If actual merger savings are significantly less than the merger savings rate reductions required by the merger settlement agreements in the eight-year period following consummation of the merger, future results of operations, cash flows and possibly financial condition could be adversely affected.See Note 7, "Commitments and Contingencies" for information on a court decision concerning the merger.A-81

6. CUSTONER CHOICE AND INDUSTRY RESTRUCTURING Prior to 2003, retail customer choice began in four of the eleven state retail jurisdictions (Michigan, Ohio, Texas and Virginia) in which the AEP domestic electric utility companies operate. The following paragraphs discuss significant events related to customer choice and industry restructuring.

OHIO RESTRUCTURING On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy Users-Ohio and American Municipal Power-Ohio filed a complaint with the PUCO alleging that CSPCo and OPCo have violated the PUCO's orders regarding implementation of their transition plan and violated the applicable law by failing to participate in an RTO.The complainants seek, among other relief, an order from the PUCO:* suspending collection of transition charges by CSPCo and OPCo until transfer of control of their transmission assets has occurred* requiring the pricing of standard offer electric generation effective January 1, 2006 at the market price used by CSPCo and OPCo in their 1999 transition plan filings to estimate transition costs and* imposing a $25,000 per company forfeiture for each day AEP fails to comply with its commitment to transfer control of transmission assets to an RTO Due to FERC, state legislative and regulatory developments, CSPCo and OPCo have been delayed in the implementation of their RTO participation plans. We continue to pursue integration of CSPCo, OPCo and other AEP East companies into PJM. In this regard, on December 19, 2002, CSPCo and OPCo filed an application with the PUCO for approval of the transfer of functional control over certain of their transmission facilities to PJM. In February 2003, the PUCO consolidated the June 2002 complaint with our December application. CSPCo's and OPCo's motion to dismiss the complaint has been denied by the PUCO and the PUCO affirmed that ruling in rehearing. All further action in the consolidated case has been stayed "until more clarity is achieved regarding matters pending at the FERC and elsewhere." Management is currently unable to predict the timing of the AEP East companies' (including CSPCo and OPCo) participation in PJM, the outcome of these proceedings before the PUCO or their impact on results of operations and cash flows.In October 2002, the PUCO-initiated an investigation of the financial condition of Ohio's regulated public utilities. The PUCO's goal is to identify measures available to the PUCO to ensure that the regulated operations of Ohio's public utilities are not impacted by adverse financial consequences of parent or affiliate company unregulated operations and take appropriate corrective action, if necessary. The utilities and other interested parties were requested to provide comments and suggestions by November 12, 2002, with reply comments by November 22, 2002, on the type of information necessary to accomplish the stated goals, the means to gather the required information from the public utilities and potential courses of action that the PUCO could take. In January 2004, the PUCO staff issued a report recommending that the PUCO seek more authority from the Ohio Legislature on this issue. The PUCO has taken no further action in this proceeding. Management is unable to predict the outcome of the PUCO's investigation or its impact on results of operations, cash flows and business practices, if any.On March 20, 2003, the PUCO commenced a statutorily required investigation concerning the desirability, feasibility and timing of declaring retail ancillary, metering or billing and collection service, supplied to customers within the certified territories of electric utilities, a competitive retail electric service. The PUCO sent out a list of questions and set June 6, 2003 and July 7, 2003 as the dates for initial responses and replies, respectively. CSPCo and OPCo filed comments and responses in compliance with the PUCO's schedule. Management is unable to predict the timing or the outcome of this proceeding or its impact on results of operations or cash flows.The Ohio Act provides for a Market Development Period (MDP) during which retail customers can choose their electric power suppliers or receive Default Service at frozen generation rates from the incumbent utility. The MDP began on January 1, 2001 and is scheduled to terminate no later than December 31, 2005. The PUCO may terminate the MDP for one or more customer classes before that date if it determines either that effective competition exists in the incumbent utility's certified territory or that there is a twenty percent switching rate of the incumbent utility's load by customer class. Following the MDP, retail customers will receive distribution and transmission service from the incumbent utility whose distribution rates will be approved by the PUCO and whose transmission rates will be A-82 approved by the FERC. Retail customers will continue to have the right to choose their electric power suppliers or receive Default Service, which must be offered by the incumbent utility at market rates. On December 17, 2003, the PUCO adopted a set of rules concerning the method by which it will determine market rates for Default Service following the MDP. The rule provides for a Market Based Standard Service Offer which would be a variable rate based on a transparent forward market, daily market, and/or hourly market prices. The rule also requires a fixed-rate Competitive Bidding Process for residential and small nonresidential customers and permits a fixed-rate Competitive Bidding Process for large general service customers and other customer classes. Customers who do not switch to a competitive generation provider can choose between the Market Based Standard Service Offer or the Competitive Bidding Process. Customers who make no choice will be served pursuant to the Competitive Bidding Process.On February 9, 2004, CSPCo and OPCo filed their rate stabilization plan with the PUCO addressing rates following the end of the MDP, which ends December 31, 2005. If approved by the PUCO, rates would be established pursuant to the plan for the period from January 1, 2006 through December 31, 2008 instead of the rates discussed in the previous paragraph. The plan is intended to provide rate stability and certainty for customers, facilitate the development of a competitive retail market in Ohio, provide recovery of environmental and other costs during the plan period and improve the environmental performance of AEP's generation resources that serve Ohio customers. The plan includes annual, fixed increases in the generation component of all customers' bills (3% annually for CSPCo and 7% annually for OPCo), and the opportunity for additional generation-related increases upon PUCO review and approval. For residential customers, however, if the temporary 5% generation rate discount provided by the Ohio Act were eliminated on June 30, 2004, the fixed increases would be 1.6% for CSPCo and 5.7% for OPCo. The generation-related increases under the plan would be subject to caps. The plan would maintain distribution rates through the end of 2008 for CSPCo and OPCo at the level effective on December 31, 2005. Such rates could be adjusted for specified reasons through a PUCO filing. Transmission charges can be adjusted to reflect applicable charges approved by the FERC related to open access transmission, net congestion, and ancillary services. The plan also provides for continued recovery of transition regulatory assets and deferral of regulatory assets in 2004 and 2005 for RTO costs and carrying costs on required environmental expenditures. A procedural schedule has not been established for this filing. Management cannot predict whether the plan will be approved as submitted, modified by the PUCO, or its impacts on results of operation and cash flows.As provided in stipulation agreements approved by the PUCO in 2000, we are deferring customer choice implementation costs and related carrying costs that are in excess of $40 million. The agreements provide for the deferral of these costs as a regulatory asset until the next distribution base rate cases. The February 2004 filing provides for the continued deferral of customer choice implementation costs during the rate stabilization plan period.At December 31, 2003, we have incurred $66 million and deferred $26 million of such costs. Recovery of these regulatory assets will be subject to PUCO review in future Ohio filings for new distribution rates. If the rate stabilization plan is approved, it would defer recovery of these amounts until after the end of the rate stabilization period. Management believes that the customer choice implementation costs were prudently incurred and the deferred amounts should be recoverable in future rates. If the PUCO determines that any of the deferred costs are unrecoverable, it would have an adverse impact on future results of operations and cash flows.TEXAS RESTRUCTURING Texas Legislation enacted in 1999 provided the framework and timetable to allow retail electricity competition for all customers. On January 1, 2002, customer choice of electricity supplier began in the ERCOT area of Texas. Customer choice has been delayed in the SPP area of Texas until at least January 1, 2007.The Texas Legislation, among other things:* provides for the recovery of regulatory assets and other stranded costs through securitization and non-bypassable wires charges;* requires each utility to structurally unbundle into a retail electric provider, a power generation company and a transmission and distribution (T&D) utility;* provides for an earnings test for each of the years 1999 through 2001 and;* provides for a 2004 true-up proceeding. See 2004 true-up proceeding discussion below.The Texas Legislation required vertically integrated utilities to legally separate their generation and retail-related assets from their transmission and distribution-related assets. Prior to 2002, TCC and TNC functionally separated A-83 their operations to comply with the Texas Legislation requirements. AEP formed new subsidiaries to act as affiliated REPs for TCC and TNC effective January 1, 2002 (the start date of retail competition). In December 2002, AEP sold the affiliated REPs to an unaffiliated company.In 1999, TCC filed with the PUCT to securitize $1.27 billion of its retail generation-related regulatory assets and $47 million in other qualified restructuring costs. The PUCT authorized the issuance of up to $797 million of securitization bonds ($949 million of generation-related regulatory assets and $33 million of qualified refinancing costs offset by $185 million of customer benefits for accumulated deferred income taxes). TCC issued its securitization bonds in February 2002. The amount not approved for securitization will be included in regulatory assets/stranded costs in TCC's 2004 true-up proceeding. TEXAS 2004 TRUE-UP PROCEEDING A 2004 true-up proceeding will determine the amount and recovery of:* net stranded generating plant costs and generation-related regulatory assets (stranded costs),* a true-up of actual market prices determined through legislatively-mandated capacity auctions to the power costs used in the PUCT's ECOM model for 2002 and 2003 (wholesale capacity auction true-up),* final approved deferred fuel balance,* unrefunded accumulated excess earnings,* excess of price-to-beat revenues over market prices subject to certain conditions and limitations (retail clawback)and* other restructuring true-up items The PUCT adopted a rule in 2003 regarding the timing of the 2004 true-up proceedings scheduling TNC's filing in May 2004 and TCC's filing in September 2004 or 60 days after the completion of the sale of TCC's generation assets, if later.Stranded Costs and Generation-RelatedRegulatoryAssets Restructuring legislation required utilities with stranded costs to use market-based methods to value certain generating assets for determining stranded costs. TCC is the only AEP subsidiary that has stranded costs under the Texas Legislation. We have elected to use the sale of assets method to determine the market value of all of our generation assets for stranded cost purposes. When completed, the sale of our generation assets will substantially complete the required separation of generation assets from transmission and distribution assets. For purposes of the 2004 true-up proceeding, the amount of stranded costs under this market valuation methodology will be the amount by which the book value of TCC's generating assets, including regulatory assets and liabilities that were not securitized, exceeds the market value of the generation assets as measured by the net proceeds from the sale of the assets. It is anticipated that any such sale will result in significant stranded costs for purposes of TCC's 2004 true-up proceeding. In December 2002, TCC filed a plan of divestiture with the PUCT seeking approval of a sales process for all of its generating facilities. In March 2003, the PUCT dismissed TCC's divestiture filing, determining that it wvas more appropriate to address allowable valuation methods for the nuclear asset in a rulemaking proceeding. The PUCT approved a rule, in May 2003, which allows the market value obtained by selling nuclear assets to be used in determining stranded costs. Although the PUCT declined to review TCC's proposed sale of assets process, the PUCT has hired a consultant to advise TCC during the sale of the generation assets. TCC's sale of its generating assets w ill be subject to a review in the 2004 true-up proceeding. In June 2003, we began actively seeking buyers for 4,497 megawatts of TCC's generating capacity in Texas. In order to sell these assets, we anticipate retiring TCC's first mortgage bonds by making open market purchases or defeasing the bonds. Bids were received for all of TCC's generating plants. In January 2004, TCC agreed to sell its 7.8%ownership interest in the Oklaunion Power Station to an unaffiliated third party for $43 million. The sale of TCC's remaining generation is pending. Additional regulatory approvals will be required to complete the sale of the generation assets, including NRC approval of the transfer of our interest in STP.In the 2004 true-up proceeding, the amount of stranded costs under this market valuation methodology will be the amount by which the book value of TCC's generating assets, including regulatory assets and liabilities that were not A-84 securitized and reduced by mitigation including unrefunded excess earnings, exceeds the market value of the generation assets as measured by the net proceeds from the sale of the assets. It is anticipated that any such sale will result in significant stranded costs for purposes of TCC's 2004 true-up proceeding. After the 2004 true-up proceeding, TCC may seek to issue securitization revenue bonds for its stranded costs and recover the costs of the securitization bonds through transmission and distribution rates. Based upon the Oklaunion sale and the bid information for the remaining generation, we recorded an impairment of generating assets of $938 million in December 2003 as a regulatory asset (see Note 10). The recovery of the regulatory asset will be subject to review and approval by the PUCT as a stranded cost in the 2004 true-up proceeding. Wholesale Capacity Auction True-uip Texas Legislation also requires that electric utilities and their affiliated power generation companies (PGC) offer for sale at auction, in 2002 and 2003 and after, at least 15% of the PGC's Texas jurisdictional installed generation capacity in order to promote competitiveness in the wholesale market through increased availability of generation. Actual market power prices received in the state mandated auctions will be used to calculate the wholesale capacity auction true-up adjustment for TCC for the 2004 true-up proceeding. TCC recorded a $480 million regulatory asset and related revenues which represent the quantifiable amount of the wholesale capacity auction true-up for the years 2002 and 2003. In TCC's UCOS proceeding, the PUCT estimated that TCC had negative stranded costs. In its true-up rule, the PUCT determined that the wholesale capacity auction true-up proceeds should be offset against negative stranded costs. However, in March 2003, the Texas Court of Appeals ruled that under the restructuring legislation, other 2004 true-up items, including the -wholesale capacity auction true-up regulatory asset, could be recovered regardless of the level of stranded costs.In the fourth quarter of 2003, the PUCT approved a true-up filing package containing calculation instructions similar to the methodology employed by TCC to calculate the amount recorded for recovery under its wholesale capacity auction true-up. The PUCT will review the $480 million wholesale capacity regulatory asset for recovery as part of the 2004 true-up proceeding. Fuel Balance Recoveries In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to establish its deferred unrecovered fuel balance applicable to retail sales within its ERCOT service area for inclusion in the 2004 true-up proceeding. In January 2004, the PUCT announced a final ruling in TNC's fuel reconciliation case that established TNC's unrecovered fuel balance, including interest for the ERCOT service territory, at $6.2 million. This balance wvill be included in TNC's 2004 true-up proceeding. TNC is waiting for a written order from the PUCT, after which it will request a rehearing. In 2002, TCC filed with the PUCT to reconcile fuel costs and to establish its deferred over-recovery of fuel balance for inclusion in the 2004 true-up proceeding. In February 2004, an ALJ issued recommendations finding a $205 million over-recovery in this fuel proceeding. Management is unable to predict the amount of TCC's fuel over-recovery which will be included in its 2004 true-up proceeding. See TCC Fuel Reconciliation and TNC Fuel Reconciliation in Note 4 "Rate Matters" for further discussion. Un refuinded Ercess Earnings The Texas Legislation provides for the calculation of excess earnings for each year from 1999 through 2001. The total excess earnings determined for the three year period were $3 million for SWVEPCo, $47 million forTCC and $19 million for TNC. TCC, TNC and SWEPCo challenged the PUCT's treatment of fuel-related deferred income taxes and appealed the PUCT's final 2000 excess earnings to the Travis County District Court which upheld the PUCT ruling. The District Court's ruling was appealed to the Third Court of Appeals. In August 2003, the Third Court of Appeals reversed the PUCT order and the District Court's judgment. The PUCT's request for rehearing of the Appeals Court's decision was denied and the PUCT chose not to appeal the ruling any further. Appeal of the same issue from the PUCT's 2001 order is pending before the District Court. Since an expense and regulatory liability had A-85 been accrued in prior years in compliance with the PUCT orders, the companies reversed a portion of their regulatory liability for the years 2000 and 2001 consistent with the Appeals Court's decision and credited amortization expense during the third quarter of 2003. Pre-tax amounts reversed by company were $5 million for TCC, $3 million for TNC and $1 million for SWVEPCo.In 2001, the PUCT issued an order requiring TCC to return estimated excess earnings by reducing distribution rates by approximately $55 million plus accrued interest over a five-year period beginning January 1, 2002. Since excess earnings amounts were expensed in 1999, 2000 and 2001, the order has no additional effect on reported net income but will reduce cash flows for the five-year refund period. The amount to be refunded is recorded as a regulatory liability. Management believes that TCC will have stranded costs and that it wvas inappropriate for the PUCT to order a refund prior to TCC's 2004 true-up proceeding. TCC appealed the PUCT's refund of excess earnings to the Travis County District Court. That court affirmed the PUCT's decision and further ordered that the refunds be provided to customers. TCC has appealed the decision to the Court of Appeals.Retail Clanwback The Texas Legislation provides for the affiliated PTB REP serving residential and small commercial customers to refund to its T&D utility the excess of the PTB revenues over market prices (subject to certain conditions and a limitation of $150 per customer). This is the retail clawback. If, prior to January 1, 2004, 40% of the load for the residential or small commercial classes is served by competitive REPs, the retail clawback is not applicable for that class of customer. During 2003, TCC and TNC filed to notify the PUCT that competitive REPs serve over 40% of the load in the small commercial class. The PUCT approved TCC's and TNC's filings in December 2003. In 2002, AEP had accrued a regulatory liability of approximately $9 million for the small commercial retail clawback on its REP's books. When the PUCT certified that the REP's in TCC and TNC service territories had reached the 40% threshold, the regulatory liability was no longer required for the small commercial class and was reversed in December 2003. At December 31, 2003, the remaining retail clawback regulatory liability was $57 million.When the 2004 true-up proceeding is completed, TCC intends to file to recover PUCT-approved stranded costs and other true-up amounts that are in excess of current securitized amounts, plus appropriate carrying charges and other true-up amounts, through non-bypassable competition transition charge in the regulated T&D rates. TCC may also seek to securitize certain of the approved stranded plant costs and regulatory assets that were not previously recovered through the non-bypassable transition charge. The annual costs of securitization are recovered through a non-bypassable rate surcharge collected by the T&D utility over the term of the securitization bonds.In the event we are unable, after the 2004 true-up proceeding, to recover all or a portion of our stranded plant costs, generation-related regulatory assets, unrecovered fuel balances, w*holesale capacity auction true-up regulatory assets, other restructuring true-up items and costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. MICHIGAN RESTRUCTURING Customer choice commenced for I&M's Michigan customers on January 1, 2002. Effective with that date the rates on I&M's Michigan customers' bills for retail electric service were unbundled to allow customers the opportunity to evaluate the cost of generation service for comparison with other offers. I&M's total rates in Michigan remain unchanged and reflect cost of service. At December 31, 2003, none of I&M's customers have elected to change suppliers and no alternative electric suppliers are registered to compete in I&M's Michigan service territory. Management has concluded that as of December 31, 2003 the requirements to apply SFAS 71 continue to be met since I&M's rates for generation in Michigan continue to be cost-based regulated. ARKANSAS RESTRUCTURING In February 2003, Arkansas repealed customer choice legislation originally enacted in 1999. Consequently, SWEPCo's Arkansas operations reapplied SFAS 71 regulatory accounting, which had been discontinued in 1999.The reapplication of SFAS 71 had an insignificant effect on results of operations and financial condition. As a result of reapplying SFAS 71, derivative contract gains/losses for transactions within AEP's traditional marketing area A-86 allocated to Arkansas will not affect income until settled. That is, such positions will be recorded on the balance sheet as either a regulatory asset or liability until realized.WVEST VIRGINIA RESTRUCTURING APCo reapplied SFAS 71 for its West Virginia (WV) jurisdiction in the first quarter of 2003 after new developments during the quarter prompted an analysis of the probability of restructuring becoming effective. In 2000, the NWVPSC issued an order approving an electricity restructuring plan, which the NWV Legislature approved by joint resolution. The joint resolution provided that the WVPSC could not implement the plan until the NWV legislature made tax law changes necessary to preserve the revenues of state and local governments. In the 2001 and 2002 legislative sessions, the NWV Legislature failed to enact the required legislation that would allow the WVPSC to implement the restructuring plan. Due to this lack of legislative activity, the VWPSC closed two proceedings related to electricity restructuring during the summer of 2002.In the 2003 legislative session, the NWV Legislature failed to enact the required tax legislation. Also, legislation enacted in March 2003 clarified the jurisdiction of the WVPSC over electric generation facilities in WV. In March 2003, APCo's outside counsel advised us that restructuring in WVV was no longer probable and confirmed facts relating to the NVVPSC's jurisdiction and rate authority over APCo's WV generation. APCo has concluded that deregulation of the WV generation business is no longer probable and operations in NWV meet the requirements to reapply SFAS 71.Reapplying SFAS 71 in WV had an insignificant effect on results of operations and financial condition. As a result, derivative contract gains/losses related to transactions within AEP's traditional marketing area allocated to WV will not affect income until settled. That is, such positions will be recorded on the balance sheet as either a regulatory asset or liability until realized. Positions outside AEP's traditional marketing area will continue to be marked-to-market.7. COMMITMIENTS AND CONTINGENCIES ENWIRONMENTAL Federal EPA Complaint and Notice of Violation The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and other unaffiliated utilities modified certain units at coal-fired generating plants in violation of the NSRs of the CAA. The Federal EPA filed its complaints against our subsidiaries in U.S. District Court for the Southern District of Ohio. The court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications relate to costs that were incurred at our generating units over a 20-year period.Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In 2001, the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief.On August 7, 2003, the District Court issued a decision following a liability trial in a case pending in the Southern District of Ohio against Ohio Edison Company, an unaffiliated utility. The District Court held that replacements of major boiler and turbine components that are infrequently performed at a single unit, that are performed with the assistance of outside contractors, that are accounted for as capital expenditures, and that require the unit to be taken out of service for a number of months are not "routine" maintenance, repair, and replacement. The District Court also held that a comparison of past actual emissions to projected future emissions must be performed prior to any non-A-87 routine physical change in order to evaluate whether an emissions increase will occur, and that increased hours of operation that are the result of eliminating forced outages due to the repairs must be included in that calculation. Based on these holdings, the District Court ruled that all of the challenged activities in that case were not routine, and that the changes resulted in significant net increases in emissions for certain pollutants. A remedy trial is scheduled for July 2004.Management believes that the Ohio Edison decision fails to properly evaluate and apply the applicable legal standards. The facts in our case also vary widely from plant to plant. Further, the Ohio Edison decision is limited to liability issues, and provides no insight as to the remedies that might ultimately be ordered by the Court.On August 26, 2003, the District Court for the Middle District of South Carolina issued a decision on cross-motions for summary judgment prior to a liability trial in a case pending against Duke Energy Corporation, an unaffiliated utility. The District Court denied all the pending motions, but set forth the legal standards that will be applied at the trial in that case. The District Court determined that the Federal EPA bears the burden of proof on the issue of whether a practice is "routine maintenance, repair, or replacement" and on whether or not a "significant net emissions increase" results from a physical change or change in the method of operation at a utility unit. However, the Federal EPA must consider whether a practice is "routine within the relevant source category" in determining if it is "routine." Further, the Federal EPA must calculate emissions by determining first whether a change in the maximum achievable hourly emission rate occurred as a result of the change, and then must calculate any change in annual emissions holding hours of operation constant before and after the change. The Federal EPA has requested reconsideration of this decision, or in the alternative, certification of an interlocutory appeal to the Fourth Circuit Court of Appeals.On June 24, 2003, the United States Court of Appeals for the 11th Circuit issued an order invalidating the administrative compliance order issued by the Federal EPA to the Tennessee Valley Authority for alleged Clean Air Act violations. The 11th Circuit determined that the administrative compliance order was not a final agency action, and that the enforcement provisions authorizing the issuance and enforcement of such orders under the Clean Air Act are unconstitutional. On June 26, 2003, the United States Court of Appeals for the District of Columbia Circuit granted a petition by the Utility Air Regulatory Group (UARG), of which our subsidiaries are members, to reopen petitions for review of the 1980 and 1992 Clean Air Act rulemakings that are the basis for the Federal EPA claims in our case and other related cases. On August 4, 2003, UARG filed a motion to separate and expedite review of their challenges to the 1980 and 1992 rulemakings from other unrelated claims in the consolidated appeal. The Circuit Court denied that motion on September 30, 2003. The central issue in these petitions concerns the lawfulness of the emissions increase test, as currently interpreted and applied by the Federal EPA in its utility enforcement actions. A decision by the D. C.Circuit Court could significantly impact further proceedings in our case.On August 27, 2003, the Administrator of the Federal EPA signed a final rule that defines "routine maintenance repair and replacement" to include "functionally equivalent equipment replacement." Under the new final rule, replacement of a component within an integrated industrial operation (defined as a "process unit") with a new component that is identical or functionally equivalent will be deemed to be a "routine replacement" if the replacement does not change any of the fundamental design parameters of the process unit, does not result in emissions in excess of any authorized limit, and does not cost more than twenty percent of the replacement cost of the process unit. The new rule is intended to have prospective effect, and will become effective in certain states 60 days after October 27, 2003, the date of its publication in the Federal Register, and in other states upon completion of state processes to incorporate the new rule into state law. On October 27, 2003 twelve states, the District of Columbia and several cities filed an action in the United States Court of Appeals for the District of Columbia Circuit seeking judicial review of the new rule.The UARG has intervened in this case. On December 24, 2003, the Circuit Court granted a motion from the petitioners to stay the effective date of this rule, which had been December 26, 2003.We are unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the CAA proceedings. We are also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If we do not prevail, any capital and operating costs of additional pollution control equipment that may be required, as well as any penalties imposed, would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity. A-88 In December 2000, Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement with the Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its future results of operations and cash flows.NUCLEAR Nuclear Plants I&M owns and operates the two-unit 2,11 0 MWV Cook Plant under licenses granted by the NRC. TCC owns 25.2% of the tvo-unit 2,500 MW STP. STPNOC operates STP on behalf of the joint owners under licenses granted by the NRC. The operation of a nuclear facility involves special risks, potential liabilities, and specific regulatory and safety requirements. Should a nuclear incident occur at any nuclear power plant facility in the U.S., the resultant liability could be substantial. By agreement I&M and TCC are partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident at any nuclear plant in the U.S. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, results of operations, cash flows and financial condition would be adversely affected.Nuclear InciJent Liabilit, The Price-Anderson Act establishes insurance protection for public liability arising from a nuclear incident at $10.6 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance provides $300 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $101 million on each licensed reactor in the U.S. payable in annual installments of $10 million. As a result, I&M could be assessed $202 million per nuclear incident payable in annual installments of $20 million. TCC could be assessed $50 million per nuclear incident payable in annual installments of $5 million as its share of a STPNOC assessment. The number of incidents for which payments could be required is not limited. Under an industry-wide program insuring workers at nuclear facilities, l&M and TCC are also obligated for assessments of up to $6 million and $2 million, respectively, for potential claims. These obligations will remain in effect until December 31, 2007.Insurance coverage for property damage, decommissioning and decontamination at the Cook Plant and STP is carried by I&M and STPNOC in the amount of $1.8 billion each. I&M and STPNOC jointly purchase $1 billion of excess coverage for property damage, decommissioning and decontamination. Additional insurance provides coverage for extra costs resulting from a prolonged accidental outage. I&M and STPNOC utilize an industry mutual insurer for the placement of this insurance coverage. Participation in this mutual insurer requires a contingent financial obligation of up to $43 million for I&M and $2 million for TCC which is assessable if the insurer's financial resources would be inadequate to pay for losses.The current Price-Anderson Act expired in August 2002. Its contingent financial obligations still apply to reactors licensed by the NRC as of its expiration date. It is anticipated that the Price-Anderson Act wvill be renewed in 2004 with increases in required third party financial protection for nuclear incidents. SNFDisposal Federal law provides for government responsibility for permanent SNF disposal and assesses nuclear plant owners fees for SNF disposal. A fee of one mill per KWH for fuel consumed after April 6, 1983 at Cook Plant and ST? is being collected from customers and remitted to the U.S. Treasury. Fees and related interest of $226 million for fuel consumed prior to April 7, 1983 at Cook Plant have been recorded as long-term debt. I&M has not paid the government the Cook Plant related pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. At December 31, 2003, funds collected from customers towards payment of the pre-April 1983 fee and related earnings thereon are in external funds and exceed the liability amount. TCC is not liable for any assessments for nuclear fuel consumed prior to April 7, 1983 since the STP units began operation in 1988 and 1989.A-89 Decomnmissioniing and Low Level WasteAccumulationi Disposal Decommissioning costs are accrued over the service lives of the Cook Plant and STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014 and 2017. In November 2003, 1&M filed to extend the operating licenses of the two Cook Plant units for up to an additional 20 years. The review of the license extension application is expected to take at least two years. After expiration of the licenses, Cook Plant is expected to be decommissioned using the prompt decontamination and dismantlement (DECON) method. The estimated cost of decommissioning and low level radioactive waste accumulation disposal costs for Cook Plant ranges from $821 million to $1,080 million in 2003 nondiscounted dollars. The wide range is caused by variables in assumptions including the estimated length of time SNF may need to be stored at the plant site subsequent to ceasing operations. This, in turn, depends on future developments in the federal government's SNF disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is recovering estimated Cook Plant decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding. The amount recovered in rates for decommissioning the Cook Plant and deposited in the external fund was $27 million in 2003, 2002 and 2001.The licenses to operate the two nuclear units at STP expire in 2027 and 2028. Afier expiration of the licenses, STP is expected to be decommissioned using the DECON method. TCC estimates its portion of the costs of decommissioning STP to be $289 million in 1999 nondiscounted dollars. TCC is accruing and recovering these decommissioning costs through rates based on the service life of STP at a rate of $8 million per year.Decommissioning costs recovered from customers are deposited in external trusts. In 2003, 2002 and 2001, I&M deposited in its decommissioning trust an additional $12 million each year related to special regulatory commission approved funding for decommissioning of the Cook Plant. Trust fund earnings increase the fund assets and decrease the amount needed to be recovered from ratepayers. Decommissioning costs including interest, unrealized gains and losses and expenses of the trust funds are recorded in Other Operation expense for Cook Plant. For STP, nuclear decommissioning costs are recorded in Other. Operation expense, interest income of the trusts are recorded in Nonoperating Income and interest expense of the trust funds are included in Interest Charges.TCC's nuclear decommissioning trust asset and liability are included in held for sale amounts on the Consolidated Balance Sheets.OPERATIONAL Construction and Connditmenits The AEP System has substantial construction commitments to support its operations. Aggregate construction expenditures for 2004-2006 for consolidated domestic and foreign operations are estimated to be $5.8 billion including amounts for proposed environmental rules.Our subsidiaries have entered into long-term contracts to acquire fuel for electric generation. The longest contract extends to the year 2014. The contracts provide for periodic price adjustments and contain various clauses that would release the subsidiaries from their obligations under certain conditions. The AEP System has unit contingent contracts to supply approximately 250 MW of capacity to unaffiliated entities through December 31, 2009. The commitment is pursuant to a unit power agreement requiring the delivery of energy only if the unit capacity is available. Potential UnitnsuredLosses Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to damage to the Cook Plant or STP and costs of replacement power in the event of a nuclear incident at the Cook Plant or STP. Future losses or liabilities which are not completely insured, unless recovered from customers, could have a material adverse effect on results of operations, cash flows and financial condition. A-90 Power Generation Facility We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop, construct, and finance a non-regulated merchant power generation facility (Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to us.Juniper will own the Facility and lease it to AEP after construction is completed and we will sublease the Facility to The Dow Chemical Company (Dow).Dow will use a portion of the energy produced by the Facility and sell the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow. OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in excess of market.Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as non-conforming. On September 5, 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. We allege that TEM has breached the PPA, and we are seeking a determination of our rights under the PPA. TEM alleges that the PPA never became enforceable or alternatively, that the PPA has already been terminated as the result of AEP breaches. If the PPA is deemed terminated or found to be unenforceable by the court, we could be adversely affected to the extent we are unable to find other purchasers of the power with similar contractual terms to the extent we do not fully recover claimed termination value damages from TEM. The corporate parent of TEM has provided a limited guaranty.On November 18, 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols relating to the dispatching, operation, and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM basically argued that in the absence of mutually agreed upon protocols there was no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the "creation of protocols" was not subject to arbitration, but did not rule upon the merits of TEM's claim that the PPA is not enforceable. If commercial operation is not achieved for purposes of the PPA by April 30, 2004, TEM may claim that it can terminate the PPA and is owed liquidating damages of approximately $17.5 million. TEM may also claim that we are not entitled to receive any termination value for the PPA.See further discussion in Notes 10 and 16.Merger Litigation In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC failed to prove that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit its conclusion that the merger met PUHCA requirements that utilities be "physically interconnected" and confined to a "single area or region." In its June 2000 approval of the merger, the SEC agreed with AEP that the companies' systems are integrated because they have transmission access rights to a single high-voltage line through Missouri and also met the PUCHA's single region requirement because it is now technically possible to centrally control the output of power plants across many states. In its ruling, the appeals court said that the SEC failed to support and explain its conclusions that the integration and single region requirements are satisfied. Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably. A-91 Enront Bankruptcy On October 15, 2002, certain subsidiaries of AEP filed claims against Enron and its subsidiaries in the bankruptcy proceeding filed by the Enron entities which are pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron's bankruptcy, certain subsidiaries of AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased Houston Pipe Line Company (HPL) from Enron. Various HPL related contingencies and indemnities from Enron remained unsettled at the date of Enron's bankruptcy. The timing of the resolution of the claims by the Bankruptcy Court is not certain.In connection with the 2001 acquisition of HPL, we acquired exclusive rights to use and operate the underground Bammel gas storage facility pursuant to an agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron. This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years and includes the use of the Bammel storage facility and the appurtenant pipelines. WVe have engaged in discussions with Enron concerning the possible purchase of the Bammel storage facility and related assets, the possible resolution of outstanding issues between AEP and Enron relating to our acquisition of HPL and the possible resolution of outstanding energy trading issues. We have considered the possible outcomes of these issues in our impairment analysis of HPL; however, actual results could differ from those estimates. We are unable to predict whether these discussions will lead to an agreement on these subjects. In January 2004, AEP and its subsidiaries filed an amended lawsuit against Enron and its subsidiaries in the U.S. Bankruptcy Court claiming that Enron does not have the right to reject the Bammel storage facility agreement or the cushion gas use agreement, described below. In February 2004 Enron filed Notices of Rejection regarding the cushion gas use agreement and other incidental agreements. We have objected to Enron's attempted rejection of these agreements. Management is unable to predict the outcome of these proceedings or the impact on results of operations, cash flows or financial condition. We also entered into an agreement with BAM Lease Company which grants HPL the exclusive right to use approximately 65 billion cubic feet of cushion gas required for the normal operation of the Bammel gas storage facility. The Bammel Gas Trust (owned by Enron and Bank of America (BOA)) purports to have a lien on 55 billion cubic feet of this cushion gas. These banks claim to have certain rights to the cushion gas in certain events of default.In connection with our acquisition of HPL, the banks and Enron entered into an agreement granting HPL's exclusive use of 65 billion cubic feet of cushion gas. Enron and the banks released HPL from all prior and future liabilities and obligations in connection with the financing arrangement. After the Enron bankruptcy, HPL was informed by the banks of a purported default by Enron under the terms of the financing arrangement. In July 2002, the banks filed a lawsuit against HPL in the state court of Texas seeking a declaratory judgment that they have a valid and enforceable security interest in gas purportedly in the Bammel storage facility which would permit them to cause the withdrawal of up to 55 billion cubic feet of gas from the storage facility. In September 2002, HPL filed a general denial and certain counterclaims against the banks including that Enron was a necessary and indispensable party to the Texas state court proceeding initiated by BOA. HPL also filed a motion to dismiss, which was denied. In December 2003, the Texas state court granted partial summary judgment in favor of the banks. HPL appealed this decision. We have considered the possible outcomes of these issues in our impairment analysis of HPL; however, actual results could differ from those estimates. Management is unable to predict the outcome of this lawsuit or its impact on results of operations, cash flows and financial condition. In October 2003, AEP Energy Services Gas Holding Company filed a lawsuit against BOA in the United States District Court for the Southern District of Texas. On January 8, 2004, this lawsuit was amended and seeks damages for BOA's breach of contract, negligent misrepresentation and fraud in connection with transactions surrounding our acquisition of HPL from Enron including entering into the Bammel storage facility lease arrangement with Enron and the cushion gas arrangements with BOA and Enron. BOA led a lending syndicate involving the 1997 gas monetization that Enron and its subsidiaries undertook and the leasing of the Bammel underground gas storage reservoir to HPL. The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPL, that BOA directly benefited from the sale of HPL and that AEP undertook the stock purchase and entered into the Bammel storage facility lease arrangement with Enron and the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron's financial condition that BOA knew or should have known were false including that the 1997 gas monetization did not contravene or constitute a default of any federal, state, or local statute, rule, regulation, code or any law.A-92 In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP's offsetting of receivables and payables and related collateral across various Enron entities and seeking payment of approximately $125 million plus interest in connection with gas related trading transactions. \Ve will assert our right to offset trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. Management is unable to predict the outcome of this lawsuit or its impact on our results of operations, cash flows or financial condition. In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron's claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. Management is unable to predict the outcome of this lawsuit or its impact on our results of operations, cash flows or financial condition. During 2002 and 2001, we expensed a total of $53 million ($34 million net of tax) for our estimated loss from the Enron bankruptcy. The amount expensed wvas based on an analysis of contracts where AEP and Enron entities are counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities and management's analysis of the HPL related purchase contingencies and indemnifications. As noted above, Enron has challenged our offsetting of receivables and payables and the Bammel storage facility lease agreement and cushion gas agreement. Management is unable to predict the final resolution of these disputes, however the impact on results of operations, cash flows and financial condition could be material.Shareholdler Lawsuits In the fourth quarter of 2002 and the first quarter of 2003, lawsuits alleging securities law violations and seeking class action certification wvere filed in federal District Court, Columbus, Ohio against AEP, certain AEP executives, and in some of the lawsuits, members of the AEP Board of Directors and certain investment banking firms. The lawsuits claim that we failed to disclose that alleged "round trip" trades resulted in an overstatement of revenues, that wve failed to disclose that our traders falsely reported energy prices to trade publications that published gas price indices and that we failed to disclose that we did not have in place sufficient management controls to prevent "round trip" trades or false reporting of energy prices. The plaintiffs seek recovery of an unstated amount of compensatory damages, attorney fees and costs. The Court has appointed a lead plaintiff who has filed a Consolidated Amended Complaint. We have filed a Motion to Dismiss the Consolidated Amended Complaint. The Motion has been briefed by the parties. Also, in the first quarter of 2003, a lawsuit making essentially the same allegations and demands was filed in state Common Pleas Court, Columbus, Ohio against AEP, certain executives, members of the Board of Directors and our independent auditor. We removed this case to federal District Court in Columbus and the Court has denied plaintiff's motion to remand the case to state court. We have moved to consolidate this case with the other pending cases. We intend to continue to vigorously defend against these actions.In the fourth quarter of 2002, tvo shareholder derivative actions were filed in state court in Columbus, Ohio against AEP and its Board of Directors alleging a breach of fiduciary duty for failure to establish and maintain adequate internal controls over our gas trading operations. These cases have been stayed pending the outcome of our Motion to Dismiss the Consolidated Amended Complaint in the federal securities lawsuits. If these cases do proceed, wve intend to vigorously defend against them. Also, in the fourth quarter of 2002 and the first quarter of 2003, three putative class action lawsuits were filed against AEP, certain executives and AEP's Employee Retirement Income Security Act (ERISA) Plan Administrator alleging violations of ERISA in the selection of AEP stock as an investment alternative and in the allocation of assets to AEP stock. The ERISA actions are pending in federal District Court, Columbus, Ohio. In these actions, the plaintiffs seek recovery of an unstated amount of compensatory damages, attorney fees and costs. We have filed a Motion to Dismiss these actions. The parties have fully briefed this Motion. We intend to continue to vigorously defend against these claims.California Lawsuits In November 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County, California Superior Court against forty energy companies, including AEP, and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the A-93 market price of natural gas and electricity. This case is in the initial pleading stage and all defendants have filed motions to dismiss. AEP has been dismissed from the case. The plaintiff had stated an intention to amend the complaint to add an AEP subsidiary as a defendant. The plaintiff amended the complaint but did not name any AEP company as a defendant. In November 2003, Texas-Ohio Energy, Inc. filed a la vsuit in the United States District Court for the Eastern District of California alleging that AEP and a large number of other energy companies conspired to manipulate natural gas prices in California in violation of federal and state antitrust and unfair competition laws.Certain of the other defendants in this case have filed a Notice of Potential Tag-Along Action with the Judicial Panel on Multi-District Litigation seeking to have this case transferred to the United States District Court for the District of Nevada where there are a number of other cases now pending that assert claims regarding the alleged manipulation of energy markets in California. None of the AEP companies is a party to these other pending cases. Once venue for the Texas-Ohio Energy, Inc. case is determined, we plan to move to dismiss the complaint and othervise vigorously defend against these claims. In February 2004, two individuals on behalf of themselves and two businesses they own and another individual filed an action in state court in San Diego County, California against a large number of energy companies including AEPES. This action alleges violations of state antitrust and unfair competition laws based on alleged manipulation of gas price indices. This case is in the initial pleading states. We plan to vigorously defend against these claims.Cornerstone Lawsuit In the third quarter of 2003, Cornerstone Propane Partners filed an action in the United States District Court for the Southern District of New York against forty companies, including AEP and AEPES seeking class certification and alleging unspecified damages from claimed price manipulation of natural gas futures and options on the NYMEX from January 2000 through December 2002. Thereafter, two similar actions were filed in the same court against a number of companies including AEP and AEPES making essentially the same claims as Cornerstone Propane Partners and also seeking class certification. On December 5, 2003, the Court issued its initial Pretrial Order consolidating all related cases, appointing co-lead counsel and providing for the filing of an amended consolidated complaint. In January 2004, plaintiffs filed an amended consolidated complaint. We plan to move to dismiss the complaint and otherwise vigorously defend against these claims.Texas Commercial Energy, LLP Lawsuit Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit in federal District Court in Corpus Christi, Texas, in July 2003, against us and four AEP subsidiaries, certain unaffiliated energy companies and ERCOT. The action alleges violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against the AEP companies, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy wvhen it was unable to raise prices to its customers due to fixed price contracts. The suit alleges over $500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs. Two additional parties, Utility Choice, LLC and Cirro Energy Corporation, have sought leave to intervene as plaintiffs asserting similar claims. We filed a Motion to Dismiss in September 2003. In February 2004, TCE filed an amended complaint. We intend to file a motion to dismiss the amended complaint and otherwise vigorously defend against the claims.Batik of Montreal Claint In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals and claimed that we owed approximately $34 million. In April 2003, eve filed a lawsuit in federal District Court in Columbus, Ohio against BOM claiming BOM had acted contrary to the appropriate trading contract and industry practice in terminating the contract and calculating termination and liquidation amounts and that BOM had acknowledged just prior to the termination and liquidation that it owed us approximately $68 million. We are claiming that BOM owes us at least$45 million. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition. A-94 Arbitration of Wiliants Claim In October 2002, we filed a demand for arbitration with the American Arbitration Association to initiate formal arbitration proceedings in a dispute with the Williams Companies (Williams). The proceeding resulted from Williams' repudiation of its obligations to provide physical power deliveries to AEP and Williams' failure to provide the monetary security required for natural gas deliveries by AEP. Consequently, both parties claimed default and terminated all outstanding natural gas and electric power trading deals among the various Williams and AEP affiliates. Williams claimed that we owed approximately $130 million in connection with the termination and liquidation of all trading deals. Williams and AEP settled the dispute and we paid $90 million to Williams in June 2003. The settlement amount approximated the amount payable that, in the ordinary course of business, we recorded as part of our trading activity using MTM accounting. As a result, the resolution of this matter did not have a material impact on results of operations or financial condition. Arbitration of PG&E Energy Trading, LLC Clainm In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately $22 million was owed by AEP in connection with the termination and liquidation of all trading deals. In February 2003, PGET initiated arbitration proceedings. In July 2003, AEP and PGET agreed to a settlement and we paid approximately $11 million to PGET.The settlement amount approximated the amount payable that, in the ordinary course of business, wev recorded as part of our trading activity using MTM accounting. As a result, the settlement payment did not have a material impact on results of operations, cash flows or financial condition. Energy AMarket Investigation AEP and other energy market participants received data requests, subpoenas and requests for information from the FERC, the SEC, the PUCT, the U.S. Commodity Futures Trading Commission (CFTC), the U.S. Department of Justice and the California attorney general during 2002. Management responded to the inquiries and provided the requested information and has continued to respond to supplemental data requests in 2003 and 2004.In March 2003, we received a subpoena from the SEC as part of the SEC's ongoing investigation of energy trading activities. In August 2002, we had received an informal data request from the SEC asking that we voluntarily provide information. The subpoena sought additional information and is part of the SEC's formal investigation. We responded to the subpoena and will continue to cooperate with the SEC.On September 30, 2003, the CFTC filed a complaint against AEP and AEPES in federal district court in Columbus, Ohio. The CFTC alleges that AEP and AEPES provided false or misleading information about market conditions and prices of natural gas in an attempt to manipulate the price of natural gas in violation of the Commodity Exchange Act.The CFTC seeks civil penalties, restitution and disgorgement of benefits. The case is in the initial pleading stage with our response to the complaint currently due on May 18, 2004. Although management is unable to predict the outcome of this case, it is not expected to have a material effect on results of operations due to a provision recorded in December 2003.In January 2004, the CFTC issued a request for documents and other information in connection with a CFTC investigation of activities affecting the price of natural gas in the fall of 2003. \Ve are responding to that request.Management cannot predict what, if any further action, any of these governmental agencies may take with respect to these matters.FERCProposed Standard Aarket Design In July 2002, the FERC issued its Standard Market Design (SMD) notice of proposed rulemaking, which sought to standardize the structure and operation of wholesale electricity markets across the country. Key elements of FERC's proposal included standard rules and processes for all users of the electricity transmission grid, new transmission rules and policies, and the creation of certain markets to be operated by independent administrators of the grid in all regions. The FERC issued a "white paper" on the proposal in April 2003, in response to the numerous comments that A-95 the FERC received on its proposal. Management does not know if or when the FERC will finalize a rule for SMD.Until any potential rule is finalized, management cannot predict its effect on cash flows and results of operations. FERC AMarket Power AMitigation A FERC order issued in November 2001 on AEP's triennial market based wholesale power rate authorization update required certain mitigation actions that AEP would need to take for sales/purchases within its control area and required AEP to post information on its website regarding its power system's status. As a result of a request for rehearing filed by AEP and other mark-et participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. Management is unable to predict the timing of any further action by the FERC or its affect of future results of operations and cash flows.8. GUARANTEES There are no liabilities recorded for guarantees entered into prior to December 31, 2002 in accordance with FIN 45.There are certain immaterial liabilities recorded for guarantees entered into subsequent to December 31, 2002. There is no collateral held in relation to any guarantees and there is no recourse to third parties in the event any guarantees are drawn unless specified below.LETTERS OF CREDIT We have entered into standby letters of credit (LOC) with third parties. These LOCs cover gas and electricity risk management contracts, construction contracts, insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. All of these LOCs were issued by us in the ordinary course of business. At December 31, 2003, the maximum future payments for all the LOCs are approximately $227 million with maturities ranging from January 2004 to January 2011. Included in these amounts is TCC's LOC of approximately $43 million with a maturity date of November 3, 2005. As the parent of all these subsidiaries, we hold all assets of the subsidiaries as collateral. There is no recourse to third parties in the event these letters of credit are drawn.We have guaranteed 50% of the principal and interest payments as well as 100% of a Power Purchase Agreement (PPA) of Fort Lupton, an IPP of which we are a 50% owner. In the event Fort Lupton does not make the required debt payments, we have a maximum future payment exposure of approximately $7 million, which expires May 2008.In the event Fort Lupton is unable to perform under its PPA agreement, we have a maximum future payment exposure of approximately $15 million, which expires June 2019.We have guaranteed 50% of a security deposit for gas transmission as well as 50% of a Power Purchase Agreement (PPA) of Orange Cogeneration (Orange), an IPP of which we are a 50% owner. In the event Orange fails to make payments in accordance with agreements for gas transmission, we have a maximum future payment exposure of approximately $1 million, which expires June 2023. In the event Orange is unable to perform under its PPA agreement, we have a maximum future payment exposure of approximately $1 million, which expires June 2016.GUARANTEES OF THIRD-PARTY OBLIGATIONS CSWYEnergy and CSlVInternational CSW Energy and CSW International have guaranteed 50% of the required debt service reserve of Sweeny Cogeneration (Sweeny), an IPP of which CSW Energy is a 50% owner. The guarantee was provided in lieu of Sweeny funding the debt reserve as a part of a financing. In the event that Sweeny does not make the required debt payments, CSW Energy and CSW International have a maximum future payment exposure of approximately $4 million, which expires June 2020.A-96 AEP Utilities AEP Utilities guaranteed 50% of the required debt service reserve for Polk Power Partners, an IPP of which CSW Energy owns 50%. In the event that Polk Power does not make the required debt payments, AEP Utilities has a maximum future payment exposure of approximately $5 million, which expires July 2010.SIFEPCo In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain conditions, to assume the capital lease obligations and term loan payments of the mining contractor, Sabine Mining Company (Sabine). In the event Sabine defaults under any of these agreements, SWEPCo's total future maximum payment exposure is approximately $58 million with maturity dates ranging from June 2005 to February 2012.As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo has agreed to provide guarantees of mine reclamation in the amount of approximately $85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by a third party miner. At December 31, 2003, the cost to reclaim the mine in 2035 is estimated to be approximately $36 million. This guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to complete reclamation. On July 1, 2003, SWEPCo consolidated Sabine due to the application of FIN 46 (see Note 2). Upon consolidation, SWEPCo recorded the assets and liabilities of Sabine ($78 million). Also, after consolidation, SWEPCo currently records all expenses (depreciation, interest and other operation expense) of Sabine and eliminates Sabine's revenues against SWEPCo's fuel expenses. There is no cumulative effect of an accounting change recorded as a result of the requirement to consolidate, and there is no change in net income due to the consolidation of Sabine.INDEMNIFICATIONS AND OTHER GUARANTEES We entered into several types of contracts, which would require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the sale price. We cannot estimate the maximum potential exposure for any of these indemnifications entered into prior to December 3 1, 2002 due to the uncertainty of future events. In 2003 we entered into several sale agreements discussed in Note 10.These sale agreements include indemnifications with a maximum exposure of approximately $57 million. There are no material liabilities recorded for any indemnifications entered into during 2003. There are no liabilities recorded for any indemnifications entered prior to December 31, 2002.We lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we have committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At December 31, 2003, the maximum potential loss for these lease agreements was approximately $28 million assuming the fair market value of the equipment is zero at the end of the lease term.See Note 16 "Leases" for disclosure of lease residual value guarantees.

9. SUSTAINED EARNINGS IMPROVEMENT INITIATIVE In response to difficult conditions in our business, a Sustained Earnings Improvement (SEI) initiative was undertaken company-wide in the fourth quarter of 2002, as a cost-saving and revenue-building effort to build long-term earnings growth.A-97 Termination benefits expense relating to 1,120 terminated employees totaling $75.4 million pre-tax was recorded in the fourth quarter of 2002. Of this amount, we paid $9.5 million to these terminated employees in the fourth quarter of 2002. No additional termination benefits expense related to the SEI initiative was recorded in 2003, and the remaining SEI related payments were made in 2003. The termination benefits expense is classified as Maintenance and Other Operation expense on our Consolidated Statements of Operations.

We determined that the termination of the employees under our SEI initiative did not constitute a plan curtailment of any of our retirement benefit plans.10. ACQIRSITIONS, DISPOSITMONS, DISCONTINUED OPERATIONS, WIPAIRMENTS, ASSETS HELD FOR SALE AND ASSETS HELD AND USED ACQUISITIONS 2002 Acquisitiont of Aordic Tra(intg (Investments -UK Operations segment)In January 2002 we acquired the trading operations, including key staff, of Enron's Norway and Sweden-based energy trading businesses (Nordic Trading). Results of operations are included in our Consolidated Statements of Operations from the date of acquisition. Subsequently in the fourth quarter of 2002, a decision was made to exit this non-core European trading business. The sale of Nordic Trading in the second quarter of 2003 is discussed in the"Dispositions" section of this note.Acquisitiont of USTI (IMvestmnents -Other segmento In January 2002, we acquired 100% of the stock of United Sciences Testing, Inc. (USTI) for $12.5 million. USTI provides equipment and services related to automated emission monitoring of combustion gases to both our affiliates and external customers. Results of operations are included in our Consolidated Statements of Operations from the date of acquisition. 2001 Houston Pipe Line Conpany (Investments -Gas Operationls segmelnt)On June 1, 2001, through a wholly-owned subsidiary, we purchased Houston Pipe Line Company and Lodisco LLC for $727 million from Enron. The acquired assets include 4,200 miles of gas pipeline, a 30-year prepaid lease of a gas storage facility and certain gas marketing contracts. The purchase method of accounting was used to record the acquisition. During 2003 we recorded impairment and other losses for HPL and related gas operations of $315 million ($228 million net of tax).U.K. Generation Plants (In vestments -UK Operations segnmelt)In December 2001, we acquired 4,000 megawatts of coal-fired generation from Fiddler's Ferry, a four-unit, 2,000 MW station on the River Mersey in northwest England, and Ferrybridge, a four-unit, 2,000 MW station on the River Aire in northeast England and related coal stocks. These assets were acquired for a cash payment of $942.3 million and the assumption of certain liabilities. During 2003 these assets became held-for-sale and we reported the operations as discontinued. See U.K. Generation Plants in the "Discontinued Operations" section of this note for further information. Other Acquisitions (Various segments)We also purchased the following assets or acquired the following businesses from July 2001 through December 2001:* Dolet Hills mining operations were purchased by SWEPCo, an AEP subsidiary, and SWEPCo also assumed the existing mine reclamation liabilities at itsjointly owned lignite reserves in Louisiana.

Quaker Coal Company as part of a bankruptcy proceeding settlement was acquired, including certain liabilities.

A-98 The acquisition includes property, coal reserves, mining operations and royalty interests in Colorado, Kentucky, Ohio, Pennsylvania and XVest Virginia. We continue to operate the mines and facilities. See AEP Coal in the"Assets Held for Sale" section of this note for further information on our decision to dispose of this investment.

MEMCO Barge Line was acquired adding 1,200 hopper barges and 30 towboats to AEP's existing barging fleet.MEMCO added major barging operations on the Mississippi and Ohio rivers to AEP's barging operations on the Ohio and Kanawha rivers.* A 20% equity interest in Caiua, a Brazilian electric operating company which is a subsidiary of Vale was acquired by converting a total of $66 million on an existing loan and accrued interest on that loan into Caiua equity. See Grupo Rede Investment in the "Dispositions" section of this note for further information.
Indian Mesa Wind Project (referred to as "Desert Sky") consisting of 160 MW of wind generation located near Fort Stockton, Texas was purchased.
Enron's London-based international coal trading group was acquired by purchasing existing contracts and hiring key staff.Management recorded the assets acquired and liabilities assumed at their estimated fair values based on currently available information and on current assumptions as to future operations.

DISPOSITIONS 2003 C3 Comnunuications (In vestmnents -Othier segment)In February 2003, C3 Communications sold the majority of its assets for a sales price of $7.25 million. WVe provided for an $82 million pre-tax ($53 million afler-tax) asset impairment in December 2002 and the effect of the sale on 2003 results of operations was not significant. The impairment is classified in Asset Impairments and Other Related Changes in our Consolidated Statements of Operations. See "Assets Held for Sale" section of this note for information on assets and liabilities held for sale at December 31, 2002 related to our "telecommunications" businesses. Mfutiual Energy Companies (Utility Operations segment)On December 23, 2002 we sold the general partner interests and the limited partner interests in Mutual Energy CPL L.P. and Mutual Energy WTU L.P. for a base purchase price paid in cash at closing and certain additional payments, including a net working capital payment. The buyer paid a base purchase price of $145.5 million which was based on a fair market value per customer established by an independent appraiser and an agreed customer count. We recorded a net gain totaling $83.7 million after-tax ($129 million pre-tax) in Other Income during 2002. We provided the buyer with a power supply contract for the two REPs and back-office services related to these customers for a tvo-year period. In addition, we retained the right to share in earnings from the two REPs above a threshold amount through 2006 in the event the Texas retail market develops increased earnings opportunities. No revenue was recorded in 2003 related to these sharing agreements. Under the Texas Legislation, REPs are subject to a clawback liability if customer change does not attain thresholds required by the legislation. We are responsible for a portion of such liability, if any, for the period we operated the REPs in the Texas competitive retail market (January 1, 2002 through December 23, 2002). In addition, we retained responsibility for regulatory obligations arising out of operations before closing. Our wholly-owned subsidiary Mutual Energy Service Company LLC (MESC) received an up-front payment of approximately $30 million from the buyer associated with the back-office service agreement, and MESC deferred its right to receive payment of an additional amount of approximately $9 million to secure certain contingent obligations. These prepaid service revenues were deferred on the books of MESC as of December 31, 2002 and are being amortized over the two-year term of the back office service agreement. In February 2003, we completed the sale of MESC for $30.4 million dollars and realized a pre-tax gain of approximately $39 million, which included the recognition of the remaining balance of the original $30 million prepayment ($27 million), as no further service obligations existed for MESC.A-99 I Water Healer Assets (Utility Operations segment)We sold our wvater heater rental program for $38 million and recorded a pre-tax loss of $3.9 million in the first quarter of 2003 based upon final terms of the sale agreement. We had provided for a $7.1 million pre-tax charge in the fourth quarter 2002 based on an estimated sales price ($3.2 million asset impairment charge and $3.9 million lease prepayment penalty). The impairment loss is included in Investment Value Losses in our Consolidated Statements of Operations. We operated a program to lease electric water heaters to residential and commercial customers until a decision was reached in the fourth quarter of 2002 to discontinue the program and offer the assets for sale. See the"Assets Held for Sale" section of this Note for assets and liabilities held for sale as of December 31, 2002.AEP Gas Power Systems (lmvestinenits -Other segment)In 2001, we acquired a 75% interest in a startup company, seeking to develop low-cost peaking generator sets powered by surplus jet turbine engines. In January 2003, AEP Gas Power Systems, LLC sold its assets. We recognized a goodwill impairment loss of $12.3 million pre-tax in the first quarter of 2002 due to technological and operational problems (also see Note 3). The impairment loss was recorded in Investment Value Losses on our Consolidated Statements of Operations. The fair values of the remaining assets and liabilities as of December 31, 2002 were excluded from held for sale on our Consolidated Balance Sheets as the impact was not significant. The effect of the asset sale on the first quarter 2003 results of operations was not significant. Ne)vgu YFacility (Investments -Other segment)In 1995, we purchased an 85 MW gas-fired peaking electrical generation facility located near Newgulf, Texas (Newgulf). In October 2002, we began negotiations with a likely buyer of the facility. We estimated a pre-tax loss on sale of $11.8 million based on the indicative bid. This loss was recorded as Asset Impairments and Other Related Charges on our Consolidated Statements of Operations during the fourth quarter 2002. Newgulf's Property, Plant and Equipment, net of accumulated depreciation, was classified on our Consolidated Balance Sheets as held for sale at December 31, 2002. During the second quarter of 2003 we completed the sale of Newgulf and the impact on earnings in 2003 was not significant. Nordic Tradfing (Investmentts -UK Operations segment)In October 2002 wve announced that our ongoing energy trading operations would be centered around our generation assets. As a result, we took steps to exit our coal, gas and electricity trading activities in Europe, except for those activities predominantly related to our U.K. generation operations. The Nordic Trading business acquired earlier in 2002 was made available for sale to potential buyers later in 2002. The estimated pre-tax loss on disposal recorded in 2002 of $5.3 million, consisted of impairment of goodwill of $4.0 million and impairment of assets of $1.3 million.The estimated loss of $5.3 million is included in Asset Impairments and Other Related Charges on our Consolidated Statements of Operations. Management's determination of a zero fair value was based on discussions with a potential buyer. The assets and liabilities of Nordic Trading have been classified on our Consolidated Balance Sheets as held for sale at December 31, 2002. The transfer of the Nordic Trading business, including the trading portfolio, to new owners was completed during the second quarter of 2003 and the impact on earnings during the second quarter of 2003 was not significant. Eastex (Investmentts -Other segment)In 1998, wve began construction of a natural gas-fired cogeneration facility (Eastex) located near Longview, Texas and commercial operations commenced in December 2001. In June 2002, we requested that the FERC allow us to modify the FERC Merger Order and substitute Eastex as a required divestiture under the order, due to the fact that the agreed upon market-power related divestiture of a plant in Oklahoma was no longer feasible. The FERC approved the request at the end of September 2002. Subsequently, in the fourth quarter of 2002, we solicited bids for the sale of Eastex and several interested buyers were identified by December 2002. The estimated pre-tax loss on sale of $218.7 million pre-tax ($142 million after-tax), which was based on the estimated fair value of the facility and indicative bids by interested buyers, wvas recorded in Discontinued Operations in our Consolidated Statements of Operations during the fourth quarter 2002.A-100 We completed the sale of Eastex during the third quarter of 2003 and the effect of the sale on third quarter 2003 results of operations was not significant. The results of operations of Eastex have been reclassified as Discontinued Operations in accordance with SFAS 144 for all years presented. The assets and liabilities of Eastex were reclassified on the Consolidated Balance Sheets from Assets Held for Sale and Liabilities Held for Sale to Discontinued Operations at December 31, 2002. See "Discontinued Operations" section of this note for additional information. Griipo Rede Investment (In vestments -Other segment)In December 2002, we recorded an other than temporary impairment totaling $141.0 million ($217.0 million net of federal income tax benefit of $76.0 million) of our 44% equity investment in Vale and our 20% equity interest in Caiua, both Brazilian electric operating companies (referred to as Grupo Rede). This amount is included in Investment Value Losses on our Consolidated Statements of Operations. In December 2003 we transferred our share and investment in Vale to Grupo Rede for $1 million. The effect of the transfer on fourth quarter results of operations was not significant. Excess Equipment (Imestmentts -Otlher segment)In November 2002, as a result of a cancelled development project, we obtained title to a surplus gas turbine generator. We had been unsuccessful in finding potential buyers of the unit due to an over-supply of generation equipment available for sale during 2002. An estimated pre-tax loss on disposal of $23.9 million was recorded in December 2002, based on market prices of similar equipment. The loss is included in Asset Impairments and Other Related Charges on our Consolidated Statements of Operations. The Other asset of $12 million in 2002 was classified on our Consolidated Balance Sheets as held for sale at December 31, 2002.We completed the sale of the surplus gas turbine generator in November 2003. The proceeds from the sale were $8.7 million. A pre-tax loss of $1.8 million wvas recorded in the fourth quarter of 2003.Ft. Davis ritid Farm (IMvestnentts -Other segment)In the 1990's, we developed a 6 MW facility wind energy project located on a lease site near Ft. Davis, Texas. In the fourth quarter of 2002 our engineering staff determined that operation of the facility was no longer technically feasible and the lease of the underlying site should not be renewed. Dismantling of the facility is expected to be completed during 2004. An estimated pre-tax loss on abandonment of $4.7 million was recorded in December 2002.The loss was recorded in Asset Impairments and Other Related Charges on our Consolidated Statements of Operations. 2002 SEEB OARD (Investments -Other segment)On June 18, 2002, through a wholly-owned subsidiary, we entered into an agreement, subject to European Union (EU) approval, to sell our consolidated subsidiary SEEBOARD, a U.K. electricity supply and distribution company.EU approval wvas received July 25, 2002 and the sale was completed on July 29, 2002. We received approximately $941 million in net cash from the sale, subject to a working capital true up, and the buyer assumed SEEBOARD debt of approximately $1.12 billion, resulting in a net loss of $345 million at June 30, 2002. The results of operations of SEEBOARD have been classified as Discontinued Operations for all years presented. A net loss of $22 million pre-tax ($14 million after-tax) was classified as Discontinued Operations in the second quarter of 2002. The remaining$323 million of the net loss has been classified as a transitional goodwill impairment loss from the adoption of SFAS 142 (see Notes 2 and 3) and has been reported as a Cumulative Effect of Accounting Change retroactive to January 1, 2002. A $59 million pre-tax ($38 million after-tax) reduction of the net loss was recognized in the second half of 2002 to reflect changes in exchange rates to closing, settlement of working capital true-up and selling expenses. The net total loss recognized on the disposal of SEEBOARD was $286 million. Proceeds from the sale of SEEBOARD were used to pay down bank facilities and short-term debt. See "Discontinued Operations" section for the total revenues and pretax profit (loss) of the discontinued operations of SEEBOARD.A-1 01 CitPower (Investments -Other segment), On July 19, 2002, through a wholly owned subsidiary, we entered into an agreement to sell CitiPower, a retail electricity and gas supply and distribution subsidiary in Australia. We completed the sale on August 30, 2002 and received net cash of approximately $175 million and the buyer assumed CitiPower debt of approximately $674 million. We recorded a pre-tax charge totaling $192 million ($125 million after-tax) as of June 30, 2002. The charge included a pre-tax impairment loss of $151 million ($98 million after-tax) on the remaining carrying value of an intangible asset related to a distribution license for CitiPower. The remaining $41 million pre-tax ($27 million after-tax) of net loss was classified as a transitional goodwill impairment loss from the adoption of SFAS 142 (see Notes 2 and 3) and was recorded as a Cumulative Effect of Accounting Change retroactive to January 1, 2002.The loss on the sale of CitiPower increased $37 million pre-tax ($24 million after-tax) to $229 million pre-tax ($149 million after-tax; $122 million plus $27 million of cumulative effect) in the second half of 2002 based on actual closing amounts and exchange rates. See the "Discontinued Operations" section of this note for the total revenues and pretax profit (loss) of the discontinued operations of CitiPower. 2001 In March 2001, CSWE, a subsidiary company, completed the sale of Frontera, a generating plant that the FERC required to be divested in connection with the merger of AEP and CSW. The sale proceeds were $265 million and resulted in an after-tax gain of $46 million ($73 million pre-tax).In July 2001, through a wholly-ovned subsidiary, we sold our 50% interest in a 120-megawatt generating plant located in Mexico. The sale resulted in an after tax gain of approximately $11 million.In July 2001, we sold coal mines in Ohio and West Virginia and agreed to purchase approximately 34 million tons of coal from the purchaser of the mines through 2008. The sale had a nominal impact on our results of operations and cash flows.In December 2001, we completed the sale of our ownership interests in the Virginia and West Virginia PCS (Personal Communications Services) Alliances for stock, resulting in an after tax gain of approximately $7 million.Subsequently during 2002, due to decreasing market value of the shares received from the sale, we reduced the value of them to zero.DISCONTINUED OPERATIONS Management periodically assesses the overall AEP 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 the operations of those businesses or operations as discontinued operations. The assets and liabilities of these discontinued operations are classified as Assets and Liabilities Held for Sale until the time that they are sold. At the time they are sold they are reclassified to Assets and Liabilities of Discontinued Operations on the Consolidated Balance Sheets for all periods presented. Assets and liabilities that are held for sale, but do not qualify as a discontinued operations are reflected as Assets and Liabilities Held for Sale both while they are held for sale and after they have been sold, for all periods presented. A-102 Certain of our operations were determined to be discontinued operations and have been classified as such in 2003, 2002 and 2001. Results of operations of these businesses have been reclassified as shown in the following table: Pushan U.K.SEE- Power Generation BOARD CitiPower Eastex Plant LIG Plants Total 2003 Revenue $- $- $58 $60 $653 $125 $896 2003 Pretax Profit (Loss) -(20) (23) 4 (122) (713) (874)2003 Earnings (Loss)AfterTax 16 (13) (14) 4 (91) (507) (605)2002 Revenue 694 204 73 57 507 251 1,786 2002 Pretax Profit (Loss) 180 (190) (239) (13) 14 (579) (827)2002 Earnings (Loss)After Tax 96 (123) (156) (7) 8 (472) (654)2001 Revenue 1,451 350 -57 525 26 2,409 2001 Pretax Profit (Loss) 104 (4) 1 8 (6) (48) 55 2001 Earnings (Loss)After Tax 88 (6) -4 (4) (41) 41 Assets and liabilities of discontinued operations have been reclassified as follows: Eastex (in millions)As of December 31. 2002 Current Assets $15 Total Assets of Discontinued Operations $1 Current Liabilities $8 Deferred Credits and Other 4 Total Liabilities of Discontinued Operations $n-Pushan Power Plant (Investments -Other segment)In the fourth quarter of 2002, we began active negotiations to sell our interest in the Pushan Power Plant (Pushan) in Nanyang, China to our minority interest partner and a purchase and sale agreement was signed in the fourth quarter of 2003. We expect to close on this transaction by mid 2004. An estimated pre-tax loss on disposal of $20 million pre-tax ($13 million after-tax) was recorded in December 2002, based on an indicative price expression. The estimated pre-tax loss on disposal is classified in Discontinued Operations in our Consolidated Statements of Operations. Results of operations of Pushan have been reclassified as Discontinued Operations. The assets and liabilities of Pushan have been classified on our Consolidated Balance Sheets as held for sale. We have classified the assets and liabilities as held for sale for longer than 12 months, which is longer than originally expected, due to several unusual circumstances including the SARS outbreak and governmental delays.LouisianaIntrastate Gas (LIG) (Investments -Gas Operations segment)After announcing during 2003 that we would be divesting our non-core assets we began actively marketing LIG with the help of an investment advisor. After receiving and analyzing initial bids during the fourth quarter 2003 wve recorded a $133.9 million pre-tax ($99 million after-tax) impairment loss; of this loss, $128.9 million pre-tax relates to the impairment of goodwill and $5 million pre-tax relates to other charges. In February 2004, we signed a definitive agreement to sell the pipeline portion of LIG. We anticipate the sale will be completed during the second quarter of 2004 and that the impact on results of operations in 2004 will not be significant. The assets and liabilities of LIG are classified as held for sale on our Consolidated Balance Sheets and the results of operations (including the above-mentioned impairments and other related charges) are classified in Discontinued Operations in our Consolidated Statements of Operations. A-103 UK Generationt Plants (Investmnents -UK Operations segment)In December 2001, we acquired two coal-fired generation plants (U.K. Generation) in the U.K. for a cash payment of$942.3 million and assumption of certain liabilities. Subsequently and continuing through 2002, wholesale U.K.electric power prices declined sharply as a result of domestic over-capacity and static demand. External industry forecasts and our own projections made during the fourth quarter of 2002 indicated that this situation may extend many years into the future. As a result, the U.K. Generation fixed asset carrying value at year-end 2002 was substantially impaired. A December 2002 probability-veighted discounted cash flow analysis of the fair value of our U.K. Generation indicated a 2002 pre-tax impairment loss of $548.7 million ($414 million after-tax). This impairment loss is included in 2002 Discontinued Operations on our Consolidated Statements of Operations. Management has retained an investment advisor to assist in determining the best methodology to exit the U.K.business. An information memorandum was distributed for the sale of our U.K. Generation and based on current information we recorded a $577 million pre-tax charge ($375 after-tax), including asset impairments of $420.7 million during the fourth quarter of 2003 to write down the value of the assets to their estimated realizable value.Additional charges of $156.7 million pre-tax were also recorded in December 2003 including $122.2 million related to the net loss on certain cash flow hedges previously recorded in Accumulated Other Comprehensive Income that has been reclassified into earnings as a result of management's determination that the hedged event is no longer probable of occurring and $34.5 million related to a first quarter 2004 sale of certain power contracts. The assets and liabilities of U.K. Generation have been classified as held for sale on our Consolidated Balance Sheets and the results of operations are included in Discontinued Operations on our Consolidated Statements of Operations. We anticipate the sale of the U.K. Generation plants during 2004.ASSET IMPAIRMENTS, INVESTMENT VALUE LOSSES AND OTHER RELATED CHARGES In 2003, AEP recorded pre-tax impairments of assets (including goodwill) and investments totaling $1A billion[consisting of approximately $650 million related to Asset Impairments ($610 million) and Other Related Charges ($40 million), $70 million related to Investment Value Losses, $711 million related to Discontinued Operations ($550 million of impairments and $161 million of other charges) and $6 million related to charges recorded for Excess Real Estate in Maintenance and Other Operation in the Consolidated Statements of Operations] that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, our decision to exit non-core businesses and other factors.In 2002, AEP recorded pre-tax impairments of assets (including goodwill) and investments totaling $1.7 billion (consisting of approximately $318 million related to Asset Impairments, $321 million related to Investment Value Losses, $938 million related to Discontinued Operations and $88 million related to charges recorded in other lines-vithin the Consolidated Statements of Operations) that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, and other factors. These impairments exclude the transitional goodwill impairment loss from adoption of SFAS 142 (see Notes 2 and 3).A-104 The categories of impairments include: 2003 2002 2001 (in millions)Asset Impairments and Other Related Charges (Pre-tax)AEP Coal $67 $60 HPL and Other 315 -Posver Generation Facility 258 Blackhawvk Coal Company 10 Ft. Davis Wind Farm -5 Texas Plants -38 Newvgulf Facility -12 Excess Equipment -24 Nordic Trading 5 Excess Real Estate -16 Telecommunications -AEPC/C3 -158 Total $651 $318-Investment Value Losses (Pre-tax)Independent Power Producers $70 $-Water Heater Assets -3 South Coast Power Investment -63 Telecommunications -AFN -14 AEP Gas Power Systems -12 Grupo Rede Investment -Vale -217 Technology Investments -12 Total b3"Impairments and Other Related Charges" and "Operations" Included in Discontinued Operations (After-tax) Impairments and Other Related Charges: U.K. Generation Plants $(375) $(414)Louisiana Intrastate Gas (99)CitiPower -(122)Eastex -(142)SEEBOARD -24 Pushan -(13)Total* (474) (667)Operations: U.K. Generation Plants (132) (58) (41)Louisiana Intrastate Gas 8 8 (4)CitiPower (13) (1) (6)Eastex (14) (14)SEEBOARD 16 72 88 Pushan 4 6 4 Total Jf3l) 13 41 Total Discontinued Operations $(605)$ AL* See the "Dispositions" and "Discontinued Operations" sections of this note for the pre-tax impairment figures.A-105 ASSETS HELD FOR SALE Telecomnnunications (In restinents -Other segment)We developed businesses to provide telecommunication services to businesses and other telecommunication companies through broadband fiber optic networks. The businesses included AEP Communications, LLC (AEPC), C3 Communications, Inc. (C3), and a 50% share of AFN, LLC (AFN), a joint venture. Due to the difficult economic conditions in these businesses and the overall telecommunications industry, the AEP Board approved in December 2002 a plan to cease operations of these businesses. We took steps to market the assets of the businesses to potential interested buyers in the fourth quarter of 2002.We completed the sale of substantially all the assets of C3 in the first quarter of 2003 as discussed in the"Dispositions" section of this note. AFN closed on the sale of substantially all of its assets in January 2004 with no significant additional effect on results of operations in 2004. The sale of remaining telecommunication assets is proceeding. An estimated pre-tax impairment loss of $158.5 million ($76.3 million related to AEPC and $82.2 million related to C3) was recorded in December 2002 and is classified in Asset Impairments and Other Related Charges in our Consolidated Statements of Operations. An estimated pre-tax loss in value of the investment in AFN of $13.8 million was recorded in December 2002 and is classified in Investment Value Losses in our Consolidated Statements of Operations. The estimated losses were based on indicative bids by potential buyers. Property, Plant and Equipment, net of accumulated depreciation, of the telecommunication businesses have been classified on our Consolidated Balance Sheets as held for sale in 2002.AEP Coal (Investments -Other segment,)In October 2001, we acquired out of bankruptcy certain assets and assumed certain liabilities of nineteen coal mine companies formerly known as "Quaker Coal" and renamed "AEP Coal." During 2002 the coal operations suffered from a decline in prices and adverse mining factors resulting in significantly reduced mine productivity and revenue.Based on an extensive review of economically accessible reserves and other factors, future mine productivity and production is expected to continue below historical levels. In December 2002, a probability-weighted discounted cash flow analysis of fair value of the mines was performed which indicated a 2002 pre-tax impairment loss of $59.9 million including a goodwill impairment of $3.6 million as discussed in Note 3. This impairment loss is included in Asset Impairments and Other Related Charges on our Consolidated Statements of Operations. In 2003, as a result of management's decision to exit our non-core businesses, we retained an advisor to facilitate the sale of AEP Coal. In the fourth quarter of 2003, after considering the current bids and all other options, we recorded a$66.6 million pre-tax ($43.6 million after-tax) charge comprised of a $29.4 million asset impairment, a $25.2 million charge related to accelerated remediation cost accruals and $12 million charge (accrued at December 31, 2003) related to a royalty agreement. These impairment losses were included in Asset Impairments and Other Related Charges on our Consolidated Statements of Operations. The assets and liabilities of AEP Coal that are held for sale have been included in Assets and Liabilities Held for Sale in our Consolidated Balance Sheets at December 31, 2003 and 2002.Texas Plants (Utility Operations segment)In September 2002, AEP indicated to ERCOT its intent to deactivate 16 gas-fired power plants (8 TCC plants and 8 TNC plants). ERCOT subsequently conducted reliability studies, which determined that seven plants (4 TCC plants and 3 TNC plants) would be required to ensure reliability of the electricity grid. As a result of those studies, ERCOT and AEP mutually agreed to enter into reliability must run (RMR) agreements, which expired in December 2002, and were subsequently renewed through December 2003. However, certain contractual provisions provided ERCOT with a 90-day termination clause, if the contracted facility was no longer needed to ensure reliability of the electricity grid.With ERCOT's approval, AEP proceeded with its planned deactivation of the remaining nine plants. In August 2003, pursuant to contractual terms, ERCOT provided notification to AEP of its intent to cancel a RMR agreement at one of the TNC plants. Upon termination of the agreement, AEP proceeded with its planned deactivation of the plant. In December 2003, AEP and ERCOT mutually agreed to new RMR contracts at six plants (4 TCC plants and 2 TNC A-106 plants) through December 2004, subject to ERCOT's 90 day termination clause and the divestiture of the TCC facilities. As a result of the decision to deactivate TNC plants, a wvrite-dowvn of utility assets of approximately $34.2 million (pre-tax) wvas recorded in Asset Impairments and Other Related Charges expense during the third quarter 2002 on our Consolidated Statements of Operations. The decision to deactivate the TCC plants resulted in a write-down of utility assets of approximately $95.6 million (pre-tax), which was deferred and recorded in Regulatory Assets during the third quarter 2002 in our Consolidated Balance Sheets.During the fourth quarter of 2002, evaluations continued as to whether assets remaining at the deactivated plants, including materials, supplies and fuel oil inventories, could be utilized elsewhere within the AEP System. As a result of such evaluations, TNC recorded an additional asset impairment charge to Asset Impairments and Other Related Charges expense of $3.9 million (pre-tax) in the fourth quarter of 2002. In addition, TNC recorded related fuel inventory and materials and supplies wvrite-downs of $2.6 million ($1.2 million in Fuel for Electric Generation and$1.4 million in Maintenance and Other Operation). Similarly, TCC recorded an additional asset impairment write-down of $6.7 million (pre-tax), which was deferred and recorded in Regulatory Assets in the fourth quarter of 2002.TCC also recorded related inventory write-downs of $14.9 million which wvas deferred and recorded in Regulatory Assets in the fourth quarter 2002.The total Texas plant asset impairment of $38.1 million pre-tax in 2002 (all related to TNC) is included in Asset Impairments and Other Related Charges in our Consolidated Statements of Operations. In December 2002, TCC filed a plan of divestiture with the PUCT proposing to sell all of its power generation assets, including the eight gas-fired generating plants that were either deactivated or designated as RMR status. During the fourth quarter of 2003, after receiving bids from interested buyers, we recorded a $938 million impairment loss and changed the classification of the plant assets from plant in service to Assets Held for Sale. In accordance with Texas legislation, the $938 million impairment was offset by the establishment of a regulatory asset, which is expected to be recovered through a wvires charge, subject to the final outcome of the 2004 Texas true-up proceeding. See Texas Restructuring section of Note 6, "Customer Choice and Industry Restructuring," for further discussion of the divestiture plan, anticipated timeline and true-up proceeding. The assets and liabilities of the entities held for sale at December 31, 2003 and 2002 are as follows: Pushan U.X Power Generation AEP Texas Plant -Plants Coal Plants I11G Total December31, 2003 (in millions)Assets: Current Assets S24 $1,245 $6 $57 S50 $1,382 Property, Plant andEquipment,Net 142 99 13 797 171 1,222 Regulatory Assets ---49 -49 Spent Nuclear Fuel and Decommissioning Trusts ---125 -125 Goodwill --15 15 Long-term Risk Management Assets -274 ---274 Other _ 6 -9 15 Total Assets Ileld for Sale -SI R8 S12. J $liabilities: Current Liabilities S26 $98S $- $- $61 $1,075 Long-term Debt 20 ----20 Long-term Risk Management Liabilities -435 ---435 Regulatory Liabilities and Deferred Investment Tax Credits ---9 -9 Asset Retirement Obligations and Nuclear Decommissioning Trusts 219 -248 Employee Benefits and Pension Obligations --12 Deferred Credits and Other 57 6 77 Total labilities Ield for Sale a -$1A6 ,. $228 A-107 Pushan Power Plant ILK.Generation Plants Tele-AEP Texas Commun-Coal Plants LIC ications (in millions)Nordic Newguir Excess Tradin Faciliht Equipment Vater Heater Progra Total December31, 2002 Assets: Current Assets Property, Plant and Equipment, Net Spent Nuclear Fuel and Decommissioning Trusts Goodwill Long-term Risk Management Assets Other Total Assets Aleld ror Sale$19 $571 S4 S70 S62 S. $35 S. S- Si S762 132 445 38 1,647 169 6 6 38 2,481 98 I I 144 98 155 61-22 5 66 39.l L .SLU 14 By 31.814 _S3a5 $6 $45- S6 -- J39 _, Liabilities: Current Liabilities Long-term Debt Deferred Income Taxes Long-term Risk Management Liabilities Dferred Credits and Other Total Liabilities field for Sale S28 $992 25 -S $53 $- S48 5- S- S- $1,121------25 39 7 -3 49 26 15 9 10 ASSETS HELD AND USED In 2003 and 2002, we recorded the following impairments related to assets (including Goodwill) held and used to Asset Impairments and Other Related Charges on our Consolidated Statements of Operations as discussed below: Excess Real Estate (In vestments -Other segment)In the fourth quarter of 2002, we began to market an under-utilized office building in Dallas, TX obtained through our merger with CSW. Sale of the facility was projected by the second quarter 2003 and an estimated pre-tax loss on disposal of $15.7 million was recorded in 2002, based on the option sale price. The estimated loss is included in Asset Impairments and Other Related Charges on our Consolidated Statements of Operations. The Property asset of$18 million in 2002 and $36 million in 2001 'was previously classified on our Consolidated Balance Sheets as held for sale.The sale of this office building was not completed by the end of 2003 and as a result the building no longer qualifies for held for sale status. In accordance with SFAS 144 the building will be moved to held and used status for all periods presented as of December 31, 2003. In December 2003 ve recorded an additional pre-tax impairment of $6 million based on bids received to date. The impairment is recorded in Maintenance and Other Operation on our Consolidated Statements of Operations. The building will continue to be actively marketed.HPL and Other (Investments -Gas Operations segment)HPL owns, or leases, and operates natural gas gathering, transportation and storage operations in Texas. In 2003, management announced that we were in the process of divesting our non-core assets, which includes the assets within our Investments-Gas Operations segment. During the fourth quarter of 2003, based on a probability-weighted after-tax cash flow analysis of the fair value of HPL, we recorded an impairment of $300 million pre-tax ($218 million after-tax), with $150 million pre-tax related to goodwill, reflecting management's decision not to operate HPL as a A-108 major trading hub and market indicators supported by the LIG bid process. The cash flow analysis used management's estimate of the alternative likely outcomes of the uncertainties surrounding the continued use of the Bammel facility and other matters (see Note 7) and an after-tax risk free discount rate of 3.3% over the remaining life of the assets.We also recorded a $15 million pre-tax charge ($10 million after-tax) in the fourth quarter 2003 included in Asset Impairments and Other Related Charges on our Consolidated Statements of Operations. This charge related to the effect of the write-off of certain HPL and LIG assets and the impairment of goodwill related to our former optimization strategy of LIG assets by AEP Energy Services.Blackhawk Coal Company (Utility Operations segment)Blackhawk Coal Company (Blackhawk) is a wholly-ovned subsidiary of I&M and was formerly engaged in coal mining operations until they ceased due to gas explosions in the mine. During the fourth quarter of 2003, it was determined that the carrying value of the investment was impaired based on an updated valuation reflecting management's decision not to pursue development of potential gas reserves. As a result, a $10.4 million pre-tax charge was recorded to reduce the value of the coal and gas reserves to their estimated realizable value. This charge ,was recorded in Asset Impairments and Other Related Charges in our Consolidated Statements of Operations. Po wer Generation Facility (Investments -Other segment)We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop, construct, and finance a non-regulated merchant power generation facility (Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to us.Juniper will own the Facility and lease it to AEP after construction is completed and we will sublease the Facility to The Dow Chemical Company (Dow).At December 31, 2002, we would have reported the Facility and related obligations as an operating lease upon achieving commercial operation. In the fourth quarter of 2003, we chose to not seek funding from Juniper for budgeted and approved pipeline construction costs related to the Facility. In order to continue reporting the Facility as an off-balance sheet financing, we 'were required to seek funding of our construction costs from Juniper. As a result, we recorded $496 million of construction work in progress (CWIP) and the related financing liability for the debt and equity as of December 31, 2003. At December 31, 2003, the lease of the Facility is reported as an owned asset under a lease financing transaction. Since the debt obligations of the Facility are recorded on our financial statements, the obligations under the lease agreement are excluded from the above table of future minimum lease payments.The current litigation between TEM and ourselves, combined with a substantial oversupply of generation capacity in the markets where we would otherwise sell the power freed up by TEM contract termination, triggered us to review the project for possible impairment of its reported values. We determined that the value of the Facility was impaired and recorded a $258 million pre-tax impairment ($168 million after-tax) in December 2003 on the CWIP.See further discussion in Notes 7 and 16.INVESTMENT VALUE AND OTHER LOSSES In 2003 and 2002, we recorded the following declines in fair value on investments: Indlependent Power Producers (Investments -Other segment)During the third quarter of 2003, we initiated an effort to sell four domestic Independent Power Producer (IPP)investments accounted for under the equity method. Based on indicative bids, it was determined that an other than temporary impairment existed on two of the equity investments. The impairment wvas the result of the measurement of fair value that was triggered by our recent decision to sell the assets. A $70.0 million pre-tax ($45.5 million net of tax) loss was recorded in September 2003 as a result of an other than temporary impairment of the equity interest.This loss of investment value is included in Investment Value Losses on our Consolidated Statements of Operations. We have received bids on the IPP investments and anticipate a final sale during the first half of 2004.A-109 Soulth Coast Power Investment (Investments -Other segment)South Coast Power is a 50% owned joint venture that was formed in 1996 to build and operate a merchant closed-cycle gas turbine generator at Shoreham, U.K. South Coast Power is subject to the same adverse wholesale electric power rates described for U.K. Generation Plants above in "Discontinued Operations." A December 2002 projected cash flow estimate of the fair value of the investment indicated a 2002 pre-tax other than temporary impairment of the equity interest (which included the fair value of supply contracts held by South Coast Power and accounted for in accordance with SFAS 133) in the amount of $63.2 million. This loss of investment value is included in Investment Value Losses on our Consolidated Statements of Operations in 2002.Technolog limwestments (Investments -Other segment)We previously made investments totaling $11.7 million in four early-stage or startup technologies involving pollution control and procurement. An analysis in December 2002 of the viability of the underlying technologies and the projected performance of the investee companies indicated that the investments were unlikely to be recovered, and an other than temporary impairment of the entire amount of the equity interest under APB 18 was recorded. The loss of investment value is included in Investment Value Losses on our Consolidated Statements of Operations.

11. BENEFITPLANS In the U.S. we sponsor two qualified pension plans and two nonqualified pension plans. A substantial majority of our employees in the U.S. are covered by either one qualified plan or both a qualified and a nonqualified pension plan.Other postretirement benefit plans are sponsored by us to provide medical and death benefits for retired employees in the U.S.We also have a foreign pension plan for employees of AEP Energy Services U.K. Generation Limited (Genco) in the U.K. The Genco pension plan had $7 million of accumulated benefit obligations in excess of plan assets at December 31, 2002. The plan was in an overfunded position at December 31, 2003.The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two-year period ending at the plan's measurement date of December 31, 2003, and a statement of the funded status as of December 31 for both years: U.S.U.S. Other Post Retirement Pension Plans Benefit Plans 2003 2002 2003 2002 Change in Benefit Obligation: (in millions)Obligation at January 1 $3,583 $3,292 $1,877 $1,645 Service Cost 80 72 42 34 Interest Cost 233 241 130 114 Participant Contributions

--14 13 Plan Amendments -(2) --Actuarial (Gain) Loss 91 258 192 152 Benefit Payments (299) (278) (92) (81)Obligation at December31 $3 $2,1 Change in Fair Value of Plan Assets: Fair Value of Plan Assets at January 1 $2,795 $3,438 $723 $711 Actual Return on Plan Assets 619 (371) 122 (57)Company Contributions (a) 65 6 183 137 Participant Contributions --14 13 Benefit Payments (a) (299) (278) (92) (81)Fair Value of Plan Assets at December, 31 $ $2325- $9_A-110 Funded Status: Funded Status at December31 $(508) $(788) $(1,213) $(1,154)Unrecognized Net Transition (Asset) Obligation 2 (7) 206 233 Unrecognized Prior Service Cost (12) (13) 6 6 Unrecognized Actuarial (Gain) Loss 797 1.020 977 896 Net Asset (Liability) Recognized ._$212( L24.)(a) Our contributions and benefit payments include only those amounts contributed directly to or paid directly from plan assets.Accumulated Benefit Obligation: 2003 2002 U.S. Qualified Pension Plans U.S. Nonqualified Pension Plans (in millions)$3,549 $3,456 76 71 U.S.Pension Plans 2003 200;Prepaid Benefit Costs Accrued Benefit Liability Additional Minimum Liability Unrecognized Prior Service Costs Accumulated Other Comprehensive Income Net Asset (Liability) Recognized $325 (46)(723)39 684$-27-9$25'(44 (944 4'90($21;U.S.Other Post Retirement Benefit Plans 2 2003 2002 (in millions)1) (24) (19)4) N/A N/A 5 N/A N/A 0 N/A N/A=LLS) L9 Increase (Decrease) in Minimum Liability Included in Other Comprehensive Income (Pre-tax)N/A = Not Applicable The asset allocations for our U.S. pension plans at the end of 2003 and 2002, and the target allocation for 2004, by asset category, are as follows: Target Allocation 2004 Asset Cateaorv Equity Fixed Income Cash and Cash Equivalents Total 70 28 2 ik Percentage of Plan Assets at Yearend 2003 2002 (in percentage) 71 67 27 32 2 1 The asset allocations for our U.S. other postretirement benefit plans at the end of 2003 and 2002, and target allocation for 2004, by asset category, are as follows: Target Allocation 2004 Asset Cateaorv Equity Fixed Income Cash and Cash Equivalents Total 70 28 2 1QQ Percentage of Plan Assets at Yearend 2003 2002 (in percentage) 61 41 36 38 3 21 m IQQ A-111 Our investment strategy for our employee benefit trust funds is to use a diversified mixture of equity and fixed income securities to preserve the capital of the funds and to maximize the investment earnings in excess of inflation within acceptable levels of risk.The value of our qualified plans' assets increased from $2.795 billion at December 31, 2002 to $3.180 billion at December 31, 2003. The qualified plans paid $292 million in benefits to plan participants during 2003 (nonqualified plans paid $7 million in benefits). The status of our plans remains in an underfunded position (plan assets are less than projected benefit obligations) of $508 million at December 31, 2003. Due to the pension plans currently being underfunded, we recorded income in Other Comprehensive Income (OCI) of $154 million, and a reduction in the Deferred Income Tax Asset of $76 million, offset by a reduction to Minimum Pension Liability of $234 million and a reduction in adjustments for unrecognized costs of $4 million. The charge to OCI does not affect earnings or cash flow. Also, due to the current underfunded status of our qualified plans, we expect to make cash contributions to our U.S. pension plans of approximately $41 million in 2004.At December 31, 2003 and 2002, the projected benefit obligation, accumulated benefit obligation, and fair value of U.S. plan assets of the U.S. pension plans with an accumulated benefit obligation in excess of plan assets, were as follows: U.S. Plans End of Year 2003 2002 (in millions)Projected Benefit Obligation $3,688 $3,583 Accumulated Benefit Obligation 3,625 3,527 Fair Value of Plan Assets 3,180 2,795 Accumulated Benefit Obligation Exceeds the Fair Value of Plan Assets 445 732 We base our determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.The weighted-average assumptions as of December 31, used in the measurement of our benefit obligations are shown in the following tables: U.S. U.S.Pension Plans Other Postretirement Benefit Plans 2003 2002 2003 2002 (in percentages) Discount Rate 6.25 6.75 6.25 6.75 Rate of Compensation Increase 3.7 3.7 N/A N/A In determining the discount rate in the calculation of future pension obligations we review the interest rates of long-term bonds that receive one of the hvo highest ratings given by a recognized rating agency. As a result of a decrease in this benchmark rate during 2003, we determined that a decrease in our discount rate from 6.75% at December 31, 2002 to 6.25% at December 31, 2003 wvas appropriate. The rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 8.5%per year, with an average increase of 3.7%.A-112 Information about the expected cash flows for the U.S. pension (qualified and non-qualified) and other postretirement benefit plans is as follows: U.S.Other Postretirement U.S. Pension Plans Benefit Plans (in millions)Emplover Contributions 2003 2004 (expected) $65 41$183 180 The table below reflects the total benefits expected to be paid from the plan or from our assets, including both our share of the benefit cost and the participants' share of the cost, which is funded by participant contributions to the plan. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates, and variances in actuarial results. The estimated payments for pension benefits and other postretirement benefits are as follows: U.S.2004 2005 2006 2007 2008 Years 2009 to 2013, in Total U.S.Pension Benefits (in million$293 300 310 325 335 1,840 Other Postretirement Benefit Plans is)$106 114 123 132 140 836 The contribution to the pension fund is based on the minimum amount required by the U.S. Department of Labor or the amount of the pension expense for accounting purposes, whichever is greater. The contribution to the other postretirement benefit plans' trusts is generally based on the amount of the other postretirement benefit plans' expense for accounting purposes and is provided for in agreements with state regulatory authorities. The following table provides the components of our net periodic benefit cost (credit) for the plans for fiscal years 2003, 2002 and 2001: U.S.Pension Plans 2003 2002 U.S.Other Postretirement Benefit Plans 2001 2003 2002 2001 (in millions)$69 $42 $34 $30 232 130 114 114 (338) (64) (62) (61)Service Cost Interest Cost Expected Return on Plan Assets Amortization of Transition (Asset) Obligation Amortization of Prior-service Cost Amortization of Net Actuarial (Gain) Loss Net Periodic Benefit Cost (Credit)Curtailment Loss Net Periodic Benefit Cost (Credit) After Curtailments $80 233 (318)$72 241 (337)(8) (9) (8)28 29 30 (1) (1)11 (3)(1A0 (44)(24!(69)52 188 27 142 18 131 1 A-1 13 The weighted-average assumptions as of January 1, used in the measurement of our benefit costs are shown in the following tables: U.S. U.S.Pension Plans Other Postretirement Benefit Plans 2003 2002 2001 2003 2002 2001 (in percentage) Discount Rate 6.75 7.25 7.50 6.75 7.25 7.50 Expected Return on Plan Assets 9.00 9.00 9.00 8.75 8.75 8.75 Rate of Compensation Increase 3.7 3.7 3.2 N/A N/A N/A The expected return on plan assets for 2003 was determined by evaluating historical returns, the current investment climate, rate of inflation, and current prospects for economic growth. After evaluating the current yield on fixed income securities as well as other recent investment market indicators, the expected return on plan assets was reduced to 8.75% for 2004. The expected return on other postretirement benefit plan assets (a portion of which is subject to capital gains taxes as well as Unrelated Business Income Taxes) was reduced to 8.35%.The assumptions used for other postretirement benefit plan measurement purposes are shown below: Health Care Trend Rates: 2003 2002 (in percentage) Initial 10.0 10.0 Ultimate 5.0 5.0 Year Ultimate Reached 2008 2008 Assumed health care cost trend rates have a significant effect on the amounts reported for the other postretirement benefit health care plans. A 1% change in assumed health care cost trend rates would have the following effects: 1% Increase 1% Decrease (in millions)Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost $26 $(21)Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation 315 (257)We have not yet determined the impact of the Medicare Prescription Drug Improvement and Modernization Act of 2003 on our other postretirement benefit plans' accumulated benefit obligation and periodic benefit cost. See FASB Staff Position No. 106-1 in Note 2 for additional information on the potential impact on our results of operations, cash flows and financial condition. AEP Savings Plans We sponsor various defined contribution retirement savings plans eligible to substantially all non-United Mine Workers of America (UMWA) U.S. employees. These plans include features under Section 401(k) of the Internal Revenue Code and provide for company matching contributions. On January 1, 2003, the two major AEP Savings Plans merged into a single plan. Beginning in 2001, and continuing underthe single merged plan, our contributions to the plans increased from 50% to 75% of the first 6% of eligible employee compensation. The cost for contributions to these plans totaled $57.0 million in 2003, $60.1 million in 2002 and $55.6 million in 2001.Other UMWVA Benefits We provide UMWA pension, health and welfare benefits for certain unionized mining employees, retirees, and their survivors who meet eligibility requirements. UMWA trustees make final interpretive determinations with regard to all benefits. The pension benefits are administered by UMWA trustees and contributions are made to their trust funds.A-1 14 The health and welfare benefits are administered by us and benefits are paid from our general assets. Contributions are expensed as paid as part of the cost of active mining operations and were not material in 2003,2002 and 2001.12. STOCK-BASED COMPENSATION The American Electric Power System 2000 Long-Term Incentive Plan (the Plan) authorizes the use of 15,700,000 shares of AEP common stock for various types of stock-based compensation awards, including stock option awards, to key employees. The Plan was adopted in 2000 by the Board of Directors and shareholders. Stock-based compensation awards granted by AEP include restricted stock units, restricted shares, performance share units and stock options. Restricted stock units vest, subject to the participant's continued employment, in approximately equal 1/3 increments on January 1V for three years following the grant date. Amounts equivalent to cash dividends on the units accrue as additional units. AEP awarded 105,910 restricted stock units, including dividends, in 2003, with a weighted-average grant-date fair value of $22.17 per unit. Compensation cost is recorded over the vesting period, based on the market value on the grant date. Expense associated with units that are forfeited is reversed in the period of forfeiture. AEP awarded 300,000 restricted shares in January 2004, which vest over periods ranging from I to 8 years.Compensation cost will be recorded over the vesting period based on the market value of $30.76 per unit on the grant date.Performance share units are equal in value to shares of AEP common stock but are subject to an attached performance factor ranging from 0% to 200%. The performance factor is determined at the end of the performance period based on performance measure(s) established for each grant at the beginning of the performance period by the Human Resources Committee of the Board of Directors. Performance share units are typically paid in cash at the end of a three-year vesting period, unless they are needed to satisfy a participant's stock ownership requirement, in which case they are mandatorily deferred as phantom stock units until the end of the participants AEP career. Phantom stock units have a value equivalent to AEP common stock and are typically paid in cash upon the participanit's termination of employment. The compensation cost for performance share units is recorded over the vesting period and both the performance share and phantom stock unit liability is adjusted for changes in fair market value. Amounts equivalent to cash dividends on both performance share and phantom stock units accrue as additional units.Under the Plan, the exercise price of all stock option grants must equal or exceed the market price of AEP's common stock on the date of grant, and in accordance with its policy, AEP does not record compensation expense. AEP generally grants options that have a ten-year life and vest, subject to the participant's continued employment, in approximately equal 1/3 increments on January 1 following the first, second and third anniversary of the grant date.CSW maintained a stock option plan prior to the merger with AEP in 2000. Effective with the merger, all CSW stock options outstanding wvere converted into AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP stock option. The exercise price for each CSW stock option was adjusted for the exchange ratio. Outstanding CSW stock options will continue in effect until all options are exercised, cancelled or expired. Under the CSW stock option plan, the option price was equal to the fair market value of the stock on the grant date. All CSW options fully vested upon the completion of the merger and expire 10 years after their original grant date.A-15 A summary of AEP stock option transactions in fiscal periods 2003, 2002 and 2001 is as follows: 2003 2002 Outstanding at beginning of year Granted Exercised Forfeited Outstanding at end of year Options (in thousands) 8,787 927 (23)(597:-902 Weighted Average Exercise Price$34$28$27$33 Options (in thousands) 6,822 2,923 (600)(358)Weighted Average Exercise Price$37$27$36$41 2001 XWeighted Average Options Exercise (in thousands) Price 6,610 645 (216)(217)$36$45$38$37$33$34$37 Options exercisable at end of year 3,092$36 MAS$36$43 Weighted average exercise price of options:-Granted above Market Price-Granted at Market Price N/A$28$27$27 N/A$45 The following table summarizes information about AEP stock options outstanding at December 31, 2003: Ontions Outstanding Range of Exercise Prices Number Outstanding (in thousands) $25.73 -$27.95 3,530$34.58 -$41.50 5,054$43.79 -$49.00 510 9.9 Weighted Average Remainine Lire (in years)9.1 6.6 7.5 7.6 Weighted Average Exercise Price$27.28$35.74$45.98$33.03 Options Exercisable Ranae of Exercise Prices$25.73 -$27.95$34.58 -$41.50$43.79 -$49.00 Number Outstanding (in thousands) 52 3,610 247 Weighted Average Exercise Price$27.06$35.78$46.57 320 $36.35 The proceeds received from exercised stock options are included in common stock and paid-in capital.The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model ,vith the following weighted average assumptions used to estimate the fair value of AEP options granted: 2003 2002 2001 Risk Free Interest Rate 3.92% 3.53% 4.87%Expected Life 7 years 7 years 7 years Expected Volatility 27.57% 29.78% 28.40%Expected Dividend Yield 4.86% 6.15% 6.05%Weighted average fair value of options:-Granted above Market Price-Granted at Market Price N/A$5.26 A-1 16$4.58$4.37 N/A$8.01

13. BUSINESS SEGMENTS Our segments and their related business activities are as follows: Utility Operations

Domestic generation of electricity for sale to retail and wholesale customers* Domestic electricity transmission and distribution Im'estntents

-Gas Operations*

Gas pipeline and storage services Investments

-UK Operations**

International generation of electricity for sale to wholesale customers* Coal procurement and transportation to AEP plants and third parties Investmnents

-Other* Coal mining, bulk commodity barging operations and other energy supply businesses

Operations of Louisiana Intrastate Gas were classified as discontinued during 2003.** UK Operations were classified as discontinued during 2003.The tables below present segment information for the twelve months ended December 31, 2003, 2002 and 2001.These amounts include certain estimates and allocations where necessary.

Prior year amounts have been reclassified to conform to the current year's presentation. I Utility Gas Operations Operations Investments UK Onerations Other (in millions)All Reconciling Other* Adiustments 2003 Revenues from: External Customers Other Operating Segments Discontinued Operations, Net of Tax Cumulative Effect of Accounting Changes, Net of Tax Net Income (Loss)Depreciation, Depletion and Amortization Expense Total Assets Assets Held for Sale Investments in Equity Method Subsidiaries Gross Property Additions Consolidated $14,545$10,871$3,097 192 S 577 96$-$-(299)(91)237 1,455 1,241 30,816 1,033 1,323 (23)(404)18 2,405 240 36 25 (507)(21)(528)1,705 1,624 (7)(605)(284) (129)193 110 1,299 36,744 3,082 39 1,697 185 1 14,925 (14,804)38 87-10 161 1,358* All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service company subsidiary, which provides services at cost to the other operating segments.A-1 17 Investments Utility Gas Operations Operations UK Operations Other (in millions)All Reconciling Othcr* Adiustments Consolidated 2002 Revenues from: External Customers Other Operating Segments Discontinued Operations, Net of Tax Cumulative Effect of Accounting Changes, Net of Tax Net Income (Loss)Depreciation, Depletion and Amortization Expense Total Assets Assets Held for Sale Investments in Equity Method Subsidiaries Gross Property Additions$10,446$2,071 222$791 147 10 (379)$13,308 8 (472) (190)(654)1,154 1,268 29,431 1,866 1,517 (91)13 3,912 375 (350)(472) (1,062)(48)(350)(519)1,215 1,150 67 1,947 210 18,388 96 (19,003)1,348 35,890 3,601 35 47 137 25 172 1,685* All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service company subsidiary, which provides services at cost to the other operating segments.Investments Utility Gas UK Operations Operations Operations Other (in millions)All Reconciling Other* Adjustments 2001 Revenues from: External Customers Other Operating Segments Discontinued Operations, Net of Tax Extraordinary Items, Net of Tax Cumulative Effect, Net of Tax Net Income (Loss)Depreciation, Depletion and Amortization Expense Gross Property Additions Consolidated $12,753$10,546$1,797$- $410-86 5-(91)(4) (41)86 41 (48)911 1,193 1,397 (48)87 15 14 (41)18 86 (72)18 971 25 137 98 1,233 1,646* All Other includes interest, litigation and other miscellaneous parent company expenses, as well as the operations of a service company subsidiary, which provides services at cost to the other operating segments.14. DERIVATIVES, HEDGING AND FINANCIAL INSTRUMENTS DERIVATIVES AND HEDGING In the first quarter of 2001, we adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. We recorded a favorable transition adjustment to Accumulated Other Comprehensive Income (Loss) of$27 million at January 1, 2001 in connection with the adoption of SFAS 133. Derivatives included in the transition adjustment are interest rate swaps, foreign currency swaps and commodity swaps, options and futures. Most of the derivatives identified in the transition adjustment were designated as cash flow hedges and relate to foreign operations. A-1 18 SFAS 133 requires recognition of all derivative instruments as either assets or liabilities in the statement of financial position at fair value. Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies, and has been designated, as part of a hedging relationship and further, on the type of hedging relationship. We designate the hedging instrument, based on the exposure being hedged, as a fair value hedge, a cash flow hedge or a hedge of a net investment in a foreign operation. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in SFAS 133. These contracts are not reported at fair value, as otherwise required by SFAS 133.For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof that is attributable to a particular risk), we recognize the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item associated with the hedged risk in Revenues in the Consolidated Statement of Operations during the period of change. For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Other Accumulated Comprehensive Income and subsequently reclassify it to Revenues in the Consolidated Statement of Operations when the forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any, is recognized currently in Revenues during the period of change.For a hedge of a net investment in a foreign currency, we include the effective portion of the gain or loss in Other Accumulated Comprehensive Income as part of the cumulative translation adjustment. We recognize any ineffective portion of the gain or loss in Revenues immediately during the period of change.NVe recognize all derivative instruments at fair value in our Consolidated Balance Sheets as either "Risk Management Assets" or "Risk Management Liabilities." We do not consider contracts that have been elected normal purchase or normal sale under SFAS 133 to be derivatives. Unrealized and realized gains and losses on all derivative instruments are ultimately included in Revenues in the Consolidated Statement of Operations on a net basis, with the exception of physically settled Resale Gas Contracts for the purchase of natural gas. The unrealized and realized gains and losses on these Resale Gas Contracts are presented as Purchased Gas for Resale in the Consolidated Statement of Operations. Fair Value Hedging Strategies We enter into natural gas forward and swap transactions to hedge natural gas inventory. The purpose of the hedging activity is to protect the natural gas inventory against changes in fair value due to changes in the spot gas prices.During the year ended December 31, 2003, we recognized a pre-tax loss of approximately $3.4 million within revenues related to hedge ineffectiveness and changes in time value excluded from the assessment of hedge ineffectiveness. We enter into interest rate forward and swap transactions for interest rate risk exposure management purposes. The interest rate forward and swap transactions effectively modifies our exposure to interest risk by converting a portion of our fixed-rate debt to a floating rate. WMe do not hedge all interest rate exposure.Cashi Flow Hedlging Strategies We enter into forward contracts to protect against the reduction in value of forecasted cash flows resulting from transactions denominated in foreign currencies. When the dollar strengthens significantly against the foreign currencies, the decline in value of future foreign currency revenue is offset by gains in the value of the forward contracts designated as cash flow hedges. Conversely, when the dollar weakens, the increase in the value of future foreign currency cash flows is offset by losses in the value of forward contracts. We do not hedge all foreign currency exposure.We enter into interest rate forward and swap transactions in order to manage interest rate risk exposure. These transactions effectively modify our exposure to interest risk by converting a portion of our floating-rate debt to a fixed rate. We do not hedge all interest rate exposure.We enter into forward and swap transactions for the purchase and sale of electricity and natural gas to manage the variable price risk related to the forecasted purchase and sale of electricity. We closely monitor the potential impacts A-1 19 of commodity price changes and, where appropriate, enter into contracts to protect margins for a portion of future sales and generation revenues. We do not hedge all variable price risk exposure related to the forecasted purchase and sale of electricity. Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Consolidated Balance Sheets at December 31, 2003 are: Portion Expected to Accumulated Be Reclassified to Hedging Hedging Other Comprehensive Earnings during Assets Liabilities Income (Loss) After Tax the Next 12 Months (in millions)Power and Gas $21 $(121) $(65) $(58)Interest Rate -(7) (9)* (8)Foreign Currency -(30) (20) (20)_$(04* Includes $6 million loss recorded in an equity investment. The net losses from cash flowv hedges in Accumulated Other Comprehensive Income (Loss) at December 31, 2003 are expected to be reclassified to net income in the next twelve months as the items being hedged settle. The actual amounts reclassified from AOCI to Net Income can differ as a result of market price changes. The maximum term for ,vhich the exposure to the variability of future cash flows is being hedged is five years.The following table represents the activity in Accumulated Other Comprehensive Income (Loss) for derivative contracts that qualify as cash flow hedges at December 31, 2003: (in millions)Beginning Balance, January I, 2003 $(16)Changes in fair value (79)Reclasses from AOCI to net gain Ending Balance, December 31, 2003 Hedge of0Aet Investment in Foreign Operations In 2001 and 2002, we used foreign denominated fixed-rate debt to protect the value of our investments in foreign subsidiaries in the U.K. Realized gains and losses from these hedges are not included in the income statement, but are shown in the cumulative translation adjustment account included in Other Accumulated Comprehensive Income.During 2002, we recognized $64 million of net losses, included in the cumulative translation adjustment, related to the foreign denominated fixed-rate debt.FINANCIAL INSTRUMENTS The fair values of Long-term Debt and preferred stock subject to mandatory redemption are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments with similar maturities. These instruments are not marked-to-market. The estimates presented are not necessarily-indicative of the amounts that we could realize in a current market exchange.A-120 The book values and fair values of significant financial instruments at December 31, 2003 and 2002 are summarized in the following tables.2003 2002 Book Value Fair Value Book Value Fair Value (in millions) (in millions)Long-term Debt $14,101 $14,621 $10,190 $10,535 Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption* 76 76 84 77 Trust Preferred Securities --321 324* See Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries for the effect of SFAS 150 in 2003.Other Financial Instruments -Nuclear Trust Funds Recorded at a arket Value The trust investments which are classified as available for sale for decommissioning and SNF disposal, reported in"Spent Nuclear Fuel and Decommissioning Trusts" and "Assets Held for Sale" on our Consolidated Balance Sheets, are recorded at market value in accordance with SFAS 115 "Accounting for Certain Investments in Debt and Equity Securities." At December 31, 2003 and 2002, the fair values of the trust investments wvere $1,107 million and $969 million, respectively, and had a cost basis of $995 million and $909 million, respectively. The change in market value in 2003, 2002, and 2001 was a net unrealized holding gain of $53 million and a net unrealized holding loss of $33 million and $11 million, respectively.

15. INCOME TAXES The details of our consolidated income taxes before discontinued operations, extraordinary items, and cumulative effect as reported are as follows: Year Ended December 31, 2003 2002 2001 (in millions)Federal: Current $297 $307 $411 Deferred 34 (60) 54 Total 331 247 465 State and Local: Current 19 32 61 Deferred 1 28 34 Total 20 60 95 International:

Current 7 8 (7)Deferred --Total 7 8 (7)Total Income Tax as Reported Before Discontinued Operations, Extraordinary Items and Cumulative Effect $ $315 $553 A-121 The following is a reconciliation of our consolidated difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory tax rate and the amount of income taxes reported.Year Ended December 31, 2003 2002 2001 (in millions)Net Income (Loss) $110 Discontinued Operations (net of income tax of $312 million,$174 million and $14 million in 2003, 2002 and 2001, respectively) 605 Extraordinary Items (net of income tax of $20 million in 2001) -Cumulative Effect of Accounting Change (net of income tax of $138 million in 2003) (193)Preferred Stock Dividends 9 Income Before Preferred Stock Dividends of Subsidiaries 531 Income Taxes Before Discontinued Operations, Extraordinary Items and Cumulative Effect 358 Pre-Tax Income $889 Income Taxes on Pre-Tax Income at Statutory Rate (35y) $311 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 40 Asset Impairments and Investment Value Losses 23 Investment Tax Credits (net) (33)Tax Effects of International Operations 8 Energy Production Credits (15)State Income Taxes 13 Other 11 Total Income Taxes as Reported Before Discontinued Operations, Extraordinary Items and Cumulative Effect -$358 Effective Income Tax Rate 40.3%$(519) $971 654 (41)48 350 11 496 315-$8l$284 32 4 (35)27 (14)39 (22)(18)10 970 553$1521$533 48 (37)(22)62 (31).r3n15 38.8%36.3%The following table shows our elements of the net deferred tax liability and the significant temporary differences. Deferred Tax Assets Deferred Tax Liabilities Net Deferred Tax Liabilities Property Related Temporary Differences Amounts Due From Customers For Future Federal Income Taxes Deferred State Income Taxes Transition Regulatory Assets Regulatory Assets Designated for Securitization Deferred Income Taxes on Other Comprehensive Loss All Other (net)Net Deferred Tax Liabilities As of December 31, 2003 2002 (in millions)$3,354 $2,604 (7.311) (6,520)$(2 $(9$(2,836)(389)(416)(254)(281)306 (87)$(3,195)(360)(422)(234)(310)326 279$(R96 A-122 We have settled with the IRS all issues from the audits of our consolidated federal income tax returns for the years prior to 1991. We have received Revenue Agent's Reports from the IRS for the years 1991 through 1996, and have filed protests contesting certain proposed adjustments. Returns for the years 1997 through 2000 are presently being audited by the IRS. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations. We join in the filing of a consolidated federal income tax return with our affiliated companies in the AEP System.The allocation of the AEP System's current consolidated federal income tax to the System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determining their current tax expense. The tax loss of the System parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group.16. LEASES Leases of property, plant and equipment are for periods up to 99 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.Lease rentals for both operating and capital leases are generally charged to operating expenses in accordance with rate-making treatment for regulated operations. Capital leases for non-regulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Year Ended December 31, 2003 2002 2001 (in millions)Lease Payments on Operating Leases $330 $346 $292 Amortization of Capital Leases 64 65 82 Interest on Capital Leases 9 14 22 Total Lease Rental Costs 0 $2W5 $396 Property, plant and equipment under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows: December 31, 2003 2002 (in millions)Property, Plant and Equipment Under Capital Leases Production $37 $40 Distribution 15 15 Other 470 687 Total Property, Plant and Equipment 522 742 Accumulated Amortization 218 299 Net Property, Plant and Equipment Under Capital Leases MA0 $441 Obligations Under Capital Leases: Noncurrent Liability $131 $170 Liability Due Within One Year 51 58 Total Obligations under Capital Leases $S12 $22&A-123 Future minimum lease payments consisted of the following at December 31, 2003: Noncancelable Capital Leases Operatina Leases (in millions)2004 $63 $291 2005 43 255 2006 34 237 2007 31 227 2008 18 214 Later Years 31 2.331 Total Future Minimum Lease Payments 220 $3.Less Estimated Interest Element 38 Estimated Present Value of Future Minimum Lease Payments 3182 Pows'er Genzeratiott Facility We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop, construct, and finance a non-regulated merchant power generation facility (Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to us.The Facility is a "qualifying cogeneration facility" for purposes of PURPA. Construction of the Facility was begun by Katco Funding, Limited Partnership (Katco), an unrelated unconsolidated special purpose entity. Katco assigned its interest in the Facility to Juniper in June 2003.Juniper is an unaffiliated limited partnership, formed to construct or otherwise acquire real and personal property for lease to third parties, to manage financial assets and to undertake other activities related to asset financing. Juniper arranged to finance the Facility with debt financing up to $494 million and equity up to $31 million from investors with no relationship to AEP or any of AEP's subsidiaries. Juniper will own the Facility and lease it to AEP after construction is completed. At December 31, 2002, we would have reported the Facility and related obligations as an operating lease upon achieving commercial operation (COD). In the fourth quarter of 2003, we chose to not seek funding from Juniper for budgeted and approved pipeline construction costs related to the Facility. In order to continue reporting the Facility as an off-balance sheet financing, we were required to seek funding of our construction costs from Juniper. As a result, we recorded $496 million of construction work in progress (CWVIP) and the related financing liability for the debt and equity as of December 31, 2003. At December 31, 2003, the lease of the Facility is reported as an owned asset under a lease financing transaction. Since the debt obligations of the Facility are recorded on our financial statements, the obligations under the lease agreement are excluded from the above table of future minimum lease payments.We are the construction agent for Juniper. We expect to achieve COD in the spring of 2004, at which time the obligation to make payments under the lease agreement will begin to accrue and we will sublease the Facility to The Dow Chemical Company (Dow). If COD does not occur on or before March 14, 2004, Juniper has the right to terminate the project. In the event the project is terminated before COD, we have the option to either purchase the Facility for 100% of Juniper's acquisition cost (in general, the outstanding debt and equity associated with the Facility) or terminate the project and make a payment to Juniper for 89.9% of project costs (in general, the acquisition cost less certain financing costs).The initial term of the lease agreement between Juniper and AEP commences on COD and continues for five years.The lease contains extension options, and if all extension options are exercised, the total term of the lease will be 30 years. AEP's lease payments to Juniper during the initial term and each extended term are sufficient for Juniper to make required debt payments under Juniper's debt financing associated with the Facility and provide a return on equity to the investors in Juniper. We have the right to purchase the Facility for the acquisition cost during the last month of the initial term or on any monthly rent payment date during any extended term. In addition, we may A-124 purchase the Facility from Juniper for the acquisition cost at any time during the initial term if we have arranged a sale of the Facility to an unaffiliated third party. A purchase of the Facility from Juniper by AEP should not alter Dow's rights to lease the Facility or our contract to purchase energy from Dow. If the lease were renewed for up to a 30-year lease term, we may further renew the lease at fair market value subject to Juniper's approval, purchase the Facility at its acquisition cost, or sell the Facility, on behalf of Juniper, to an independent third party. If the Facility is sold and the proceeds from the sale are insufficient to pay all of Juniper's acquisition costs, wve may be required to make a payment (not to exceed $396 million) to Juniper of the excess of Juniper's acquisition costs over the proceeds from the sale, provided that we would not be required to make any payment if we have made the additional rental prepayment described below. We have guaranteed the performance of our subsidiaries to Juniper during the lease term. Because we now report the debt related to the Facility on our balance sheet, the fair value of the liability for our guarantee (the $396 million payment discussed above) is not separately reported.At December 31, 2003, Juniper's acquisition costs for the Facility totaled $496 million, and total costs for the completed Facility are currently expected to be approximately $525 million. For the 30-year extended lease term, the base lease rental is a variable rate obligation indexed to three-month LIBOR. Consequently, as market interest rates increase, the base rental payments under the lease will also increase. Annual payments of approximately $18 million represent future minimum payments for interest on Juniper's financing structure during the initial term calculated using the indexed LIBOR rate (1.15% at December 31, 2003). An additional rental prepayment (up to $396 million)may be due on June 30, 2004 unless Juniper has refinanced its present debt financing on a long-term basis. Juniper is currently planning to refinance by June 30, 2004. The Facility is collateral for the debt obligation of Juniper. At December 31, 2003, we reflected $396 million of the $496 million recorded obligation as long-term debt due within one year. Our maximum required cash payment as a result of our financing transaction with Juniper is $396 million as well as interest payments during the lease term. Due to the treatment of the Facility as a financing of an owned asset, the recorded liability of $496 million is greater than our maximum possible cash payment obligation to Juniper.Dow will use a portion of the energy produced by the Facility and sell the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow. OPCo has also agreed to sell up to approximately 800 MWV of energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in excess of market.Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as non-conforming. See further discussion in Notes 7 and 10.Gavin Lease OPCo has entered into an agreement with JMG, an unrelated special purpose entity. JMG has a capital structure of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from commercial paper, pollution control bonds and other bonds. JMG was formed to design, construct and lease the Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber and leases it to OPCo. Prior to July 1, 2003, the lease was accounted for as an operating lease. Payments under the lease agreement are based on JMG's cost of financing (both debt and equity) and include an amortization component plus the cost of administration. OPCo and AEP do not have an ownership interest in JMG and do not guarantee JMG's debt.At any time during the lease, OPCo has the option to purchase the Gavin Scrubber for the greater of its fair market value or adjusted acquisition cost (equal to the unamortized debt and equity of JMG) or sell the Gavin Scrubber on behalf of JMG. The initial 15-year lease term is non-cancelable. At the end of the initial term, OPCo can renew the lease, purchase the Gavin Scrubber (terms previously mentioned), or sell the Gavin Scrubber on behalf of JMG. In case of a sale at less than the adjusted acquisition cost, OPCo must pay the difference to JMG.On March 31, 2003, OPCo made a prepayment of $90 million under this lease structure. AEP recognizes lease expense on a straight-line basis over the remaining lease term, in accordance with SFAS 13 "Accounting for Leases." The asset will be amortized over the remaining lease term, which ends in the first quarter of 2010.On July 1, 2003, OPCo consolidated JMG due to the application of FIN 46. Upon consolidation, OPCo recorded the assets and liabilities of JMG ($469.6 million). OPCo now records the depreciation, interest and other operating A-125 expenses of JMG and eliminates JMG's revenues against OPCo's operating lease expenses. There was no cumulative effect of an accounting change recorded as a result of our requirement to consolidate JMG, and there was no change in net income due to the consolidation of JMG. Since the debt obligations of JMG are now consolidated, the JMG lease is no longer accounted for on a consolidated basis as an operating lease and has been excluded from the above table of future minimum lease payments.RocAport Lease AEGCo and I&M entered into a sale and leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee) an unrelated unconsolidated trustee for Rockport Plant Unit 2 (the plant). Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The future minimum lease payments for each respective company are $1.4 billion.The FASB and other accounting constituencies continue to interpret the application of FIN 46R. As a result, we are continuing to review the application of this new interpretation as it relates to the Rockport Plant Unit 2 transaction. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the plant and leases it to AEGCo and l&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and l&M have the option to renew the lease or the Owner Trustee can sell the plant. Neither AEGCo, I&M nor AEP has an owvnership interest in the Owvner Trustee and do not guarantee its debt.Railcar Lease In June 2003, we entered into an agreement with an unrelated, unconsolidated leasing company to lease 875 coal-transporting aluminum railcars. The lease has an initial term of five years and may be renewed for up to three additional five-year terms, for a maximum of twenty years. We intend to renew the lease for the full twenty years.At the end of each lease term, we may (a) renew for another five-year term, not to exceed a total of twenty years, (b)purchase the railcars for the purchase price amount specified in the lease, projected at the lease inception to be the then fair market value, or (c) return the railcars and arrange a third party sale (return-and-sale option). The lease is accounted for as an operating lease with the future payment included in the future minimum lease payments schedule earlier in this note. This operating lease agreement allows us to avoid a large initial capital expenditure, and to spread our railcar costs evenly over the expected twenty-year usage.Under the lease agreement, the lessor is guaranteed that the sale proceeds under the return-and-sale option discussed above will equal at least a lessee obligation amount specified in the lease, which declines over the term from approximately 86% to 77% of the projected fair market value of the equipment. At December 31, 2003, the maximum potential loss was approximately $31.5 million ($20.5 million net of tax) assuming the fair market value of the equipment is zero at the end of the current lease term. The railcars are subleased for one year to an unaffiliated company under an operating lease. The sublessee may renew the lease for up to four additional one-year terms. AEP has other rail car lease arrangements that do not utilize this type of structure.

17. FINANCING ACTIVITIES Trust Prefrerred Securities PSO, SWEPCo and TCC have wholly-owned business trusts that have issued trust preferred securities.

The trusts which hold mandatorily redeemable trust preferred securities were deconsolidated effective July 1, 2003 due to the implementation of FIN 46. Therefore, $321 million ($75 million PSO, $110 million SWEPCo and $136 million TCC), previously reported at December 31, 2002 as Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such Subsidiaries, is now reported as two components on the Balance Sheet. The $10 million investment in the trust is now reported as Other within Other Non-Current Assets while the $331 million of subordinated debentures are now reported as Notes Payable to Trust within Long-term Debt.A-126 The Junior Subordinated Debentures of PSO and TCC mature on April 30, 2037. In October 2003, SWEPCo refinanced its Junior Subordinated Debentures which are now due October 1, 2043. The following Trust Preferred Securities issued by the wholly-owned statutory business trusts of PSO, SWEPCo and TCC were outstanding at December 31, 2003 and 2002: Amount Units Amount in Reported Description of -Issued/ Amount in Notes Payable Prior to Underlying Outstanding Other to Trust FIN 46 Debentures of Business Trust Security at 12/31103 at 12/31/03 (a) at 12/31/03 (b) at 12/31/02 (c) Registrant (in millions) (in millions) (in millions)CPL Capital I 8.00/o, Series A 5,450,000 $5 $141 S136 TCC, $141 million, 8.000% Series A PSO Capital 1 8.00%, Series A 3,000,000 2 77 75 PSO, $77 million, 8.00%, Series A SWVEPCo Capital 1 7.8750% Series A ---110 SWEPCo, $113 million, 7.875%/c, Series A SWVEPCo Capital I 5.2 5%, Series B 110000 113 SWVEPCo, $113 million, 5.25% five year fixed rate period, Series B Total $10 $31 $321 (a) Amounts are in Other %vithin Other Non-Current Assets.(b) Amounts are in Notes Payable to Trust within Long-term Debt.(c) Amounts reported on Balance Sheet prior to FIN 46.Each of the business trusts is treated as a non-consolidated subsidiary of its parent company. The only assets of the business trusts are the subordinated debentures issued by their parent company as specified above. In addition to the obligations under their subordinated debentures, each of the parent companies has also agreed to a security obligation which represents a full and unconditional guarantee of its capital trust obligation. AMinority Interest in Finance Subsidiary We formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis Partners, LLC (Caddis) in August 2001. SubOne is a wholly-owned consolidated subsidiary that was capitalized with the assets of Houston Pipe Line Company and Louisiana Intrastate Gas Company and $321.4 million of AEP Energy Services Gas Holding Company (AEP Gas Holding is a subsidiary of AEP and the parent of SubOne) preferred stock, that was convertible into AEP common stock at market price on a dollar-for-dollar basis. Caddis was capitalized with $2 million cash and a subscription agreement that represents an unconditional obligation to fund $83 million from SubOne for a managing member interest and $750 million from Steelhead Investors LLC (Steelhead) for a non-controlling preferred member interest. As managing member, SubOne consolidated Caddis. Steelhead is an unconsolidated special purpose entity and had an original capital structure of $750 million (currently approximately $525 million) of which 3% is equity from investors with no relationship to us or any of our subsidiaries and 97% is debt from a syndicate of banks. The$525 million invested in Caddis by Steelhead was loaned to SubOne. The loan to SubOne is due August 2006. Net proceeds from the proposed sale of LIG will be used to reduce the outstanding balance of the loan from Caddis (see Note 10 for additional information on LIG and HPL).On July 1, 2003, due to the application of FIN 46, we deconsolidated Caddis, which included amounts previously reported as Minority Interest in Finance Subsidiary ($759 million at December 31, 2002 and $533 million at June 30, 2003). As a result, a note payable to Caddis is reported as a component of Long-term Debt ($527 million at December 31, 2003). Due to the prospective application of FIN 46, we did not change the presentation of Minority Interest in Finance Subsidiary in periods prior to July 1, 2003.A-127 On May 9, 2003, SubOne borrowed $225 million from us and used the proceeds to reduce the outstanding balance of the loan from Caddis, which Caddis used to reduce the preferred interest held by Steelhead. This payment eliminated the convertible preferred stock of AEP Gas Holding which under certain conditions had been convertible to AEP common stock.The credit agreement between Caddis and SubOne contains covenants that restrict certain incremental liens and indebtedness, asset sales, investments, acquisitions, and distributions. The credit agreement also contains covenants that impose minimum financial ratios. Non-performance of these covenants may result in an event of default under the credit agreement. Through December 31, 2003, SubOne has complied with the covenants contained in the credit agreement. In addition, the acceleration of outstanding debt in excess of $50 million would be an event of default under the credit agreement. SubOne has deposited $422 million in a cash reserve fund in order to comply with certain covenants in the credit agreement. Pursuant to the terms of the credit agreement, SubOne subsequently loaned these funds to affiliates, and ve guaranteed the repayment obligations of these affiliates. These loans must be repaid in the event our credit ratings fall below investment grade.Steelhead has certain rights as a preferred member in Caddis. Upon the occurrence of certain events, including a default in the payment of the preferred return, Steelhead's rights include forcing a liquidation of Caddis and acting as the liquidator. Liquidation of Caddis could negatively impact our liquidity. Caddis and SubOne are each a limited liability company, with a separate existence and identity from its members, and the assets of each are separate and legally distinct from us.Equity, Units In June 2002, AEP issued 6.9 million equity units at $50 per unit and received proceeds of $345 million. Each equity unit consists of a forward purchase contract and a senior note.The forward purchase contracts obligate the holders to purchase shares of AEP common stock on August 16, 2005.The purchase price per equity unit is $50. The number of shares to be purchased under the forward purchase contract will be determined under a formula based upon the average closing price of AEP common stock near the stock purchase date. Holders may satisfy their obligation to purchase AEP common stock under the forward purchase contracts by allowing the senior notes to be remarketed or by continuing to hold the senior notes and using other resources as consideration for the purchase of stock. If the holders elect to allow the notes to be remarketed, the proceeds from the remarketing will be used to purchase a portfolio of U.S. treasury securities that the holders will pledge to AEP in order to meet their obligations under the forward purchase contracts. The senior notes have a principal amount of $50 each and mature on August 16, 2007. The senior notes are the collateral that secures the holders' requirement to purchase common stock under the forward purchase contracts. AEP is making quarterly interest payments on the senior notes at an initial annual rate of 5.75%. The interest rate can be reset through a remarketing, which is initially scheduled for May 2005. AEP makes contract adjustment payments to the purchaser at the annual rate of 3.50% on the forward purchase contracts. The present value of the contract adjustment payments was recorded as a $31 million liability in Equity Unit Senior Notes offset by a charge to Paid-in Capital in June 2002. Interest payments on the senior notes are reported as interest expense. Accretion of the contract adjustment payment liability is reported as interest expense.AEP applies the treasury stock method to the equity units to calculate diluted earnings per share. This method of calculation theoretically assumes that the proceeds received as a result of the forward purchase contract are used to repurchase outstanding shares.A-128 Lines of Credit-AEPSystem We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries. The corporate borrowing program includes a utility money pool, which funds the utility subsidiaries, and a non-utility money pool, which funds the majority of the non-utility subsidiaries. In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in the non-utility money pool for regulatory or operational reasons. As of December 31, 2003, we had credit facilities totaling $2.9 billion to support our commercial paper program. At December 31, 2003, AEP had $326 million outstanding in short-term borrowings of which $282 million was commercial paper supported by the revolving credit facilities. In addition, JMG has commercial paper outstanding in the amount of $26 million. This commercial paper is specifically associated with the Gavin scrubber lease identified in Note 16 "Leases". This commercial paper does not reduce available liquidity to AEP. The maximum amount of commercial paper outstanding during the year, which had a weighted average interest rate during 2003 of 1.98%, was $1.5 billion during January 2003. On December 11, 2002, Moody's Investor Services placed AEP's Prime-2 short-term rating for commercial paper under review for possible downgrade. On January 24, 2003, Standard & Poor's Rating Services placed AEP's A-2 short-term rating for commercial paper under review for possible downgrade. On February 10, 2003, Moody's Investor Services downgraded AEP's short-term rating for commercial paper to Prime-3 from Prime-2. On March 7, 2003, Standard & Poor's Rating Services reaffirmed AEP's A-2 short-term rating for commercial paper.Outstanding Short-term Debt consisted of: December 31, 2003 2002 (in millions)Balance Outstanding: Notes Payable $18 $1,322 Commercial Paper -AEP 282 1,417 Commercial Paper -JMG 26 -Total $326. $273 Sale of Receivables -AEP Credit AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140, allowing the receivables to be taken off of AEP Credit's balance sheet and allowing AEP Credit to repay any debt obligations. AEP has no ownership interest in the commercial paper conduits and does not consolidate these entities in accordance with GAAP. We continue to service the receivables. We entered into this off-balance sheet transaction to allow AEP Credit to repay its outstanding debt obligations, continue to purchase the AEP operating companies' receivables, and accelerate its cash collections. AEP Credit extended its sale of receivables agreement to July 25, 2003 from its May 28, 2003 expiration date. The agreement was then renewed for an additional 364 days and now expires on July 23, 2004. This new agreement provides commitments of $600 million to purchase receivables from AEP Credit. At December 31, 2003, $385 million was outstanding. As collections from receivables sold occur and are remitted, the outstanding balance for sold receivables is reduced and as new receivables are sold, the outstanding balance of sold receivables increases. All of the receivables sold represented affiliate receivables. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of the receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivable less an allowance for anticipated uncollectible accounts.AEP Credit purchases accounts receivable through purchase agreements with certain registrant subsidiaries and, until the first quarter of 2002, with non-affiliated companies. These subsidiaries include CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in all of its regulatory jurisdictions, only a portion of APCo's accounts receivable are sold to AEP Credit. As a result of the restructuring of electric utilities in the State of Texas, the purchase agreement between AEP Credit and Reliant A-129 Energy, Incorporated was terminated as of January 25, 2002 and the purchase agreement between AEP Credit and Texas-New Mexico Power Company, the last remaining non-affiliated company, was terminated on February 7, 2002.In addition, the purchase agreements between AEP Credit and its Texas affiliates, AEP Texas Central Company (formerly Central Powver and Light Company) and AEP Texas North Company (formerly WVest Texas Utilities Company), were terminated effective March 20, 2002.Comparative accounts receivable information for AEP Credit: Year Ended December 31, 2003 2002 (in millions)Proceeds from Sale of Accounts Receivable $5,221 $5,513 Accounts Receivable Retained Interest Less Uncollectible Accounts and Amounts Pledged as Collateral 124 76 Deferred Revenue from Servicing Accounts Receivable I I Loss on Sale of Accounts Receivable 7 4 Average Variable Discount Rate 1.33% 1.92%Retained Interest if 10% Adverse Change in Uncollectible Accounts 122 74 Retained Interest if 20% Adverse Change in Uncollectible Accounts 121 72 Historical loss and delinquency amount for the AEP System's customer accounts receivable managed portfolio: Face Value Year Ended December 31, 2003 2002 (in millions)Customer Accounts Receivable Retained $1,155 $1,553 Accrued Unbilled Revenues Retained 596 551 Miscellaneous Accounts Receivable Retained 83 93 Allowvance for Uncollectible Accounts Retained (124) (108)Total Net Balance Sheet Accounts Receivable 1,710 2,089 Customer Accounts Receivable Securitized (Affiliate) 385 454 Total Accounts Receivable Managed $2i2.2 $2,.Net Uncollectible Accounts Written Off 1 ,9$48 Customer accounts receivable retained and securitized for the domestic electric operating companies are managed by AEP Credit. Miscellaneous accounts receivable have been fully retained and not securitized. At December 31, 2003, delinquent customer accounts receivable for the electric utility affiliates that AEP Credit currently factors was $30 million.A-130

18. UNAUDITED QUARTERLY FINANCIAL INFORMATION Our unaudited quarterly financial information is as follows: 2003 Ouarterlv Periods Ended March 31 June30 September 30 December 31 (In Millions -Except Per Share Amounts)Revenues $3,834 $3,451 $3,940 $3,320 Operating Income (Loss) 630 393 735 (126)Income (Loss) Before Discontinued Operations, Extraordinary Items and Cumulative Effect 294 185 298 (255)Net Income (Loss) 440 175 257 (762)Earnings (Loss) per Share Before Discontinued Operations, Extraordinary Items and Cumulative Effect* 0.83 0.47 0.75 (0.65)Earnings (Loss) per Share** 1.24 0.44 0.65 (1.93)2002 Ouarterlv Periods Ended March 31 June30 September 30 December 31 (In Millions -Except Per Share Amounts)Revenues $2,802 $3,395 $3,639 $3,472 Operating Income 420 433 781 170 Income (Loss) Before Discontinued Operations, Extraordinary Items and Cumulative Effect 134 167 385 (201)Net Income (Loss) (169) 62 425 (837)Earnings (Loss) per Share Before Discontinued Operations, Extraordinary Items and Cumulative Effect***

0.42 0.51 1.14 (0.59)Earnings (Loss) per Share**** (0.53) 0.19 1.25 (2.47)* Amounts for 2003 do not add to $1.35 earnings per share before Discontinued Operations, Extraordinary Loss and Cumulative Effect due to rounding and the dilutive effect of shares issued in 2003.** Amounts for 2003 do not add to $0.29 earnings per share due to rounding and the dilutive effect of shares issued in 2003.***Amounts for 2002 do not add to $1.46 earnings per share before Discontinued Operations, Extraordinary Loss and Cumulative Effect due to rounding.****Amounts for 2002 do not add to $(1.57) earnings per share due to rounding.Income (Loss) Before Discontinued Operations, Extraordinary Items and Cumulative Effect for the fourth quarter 2003 ($255 million loss) and 2002 ($201 million loss) were significantly lower than the previous three quarters due to asset impairments, investment value losses and other related charges. These pre-tax writedowns ($650 million in the fourth quarter 2003 and $593 million in the fourth quarter 2002) were made to reflect impairments and discontinued operations as discussed in Note 10.19. SUBSEQUENT EVENTS (UNAUDITED) After December 31, 2003, we entered into separate agreements to dispose of the following investments: Investment Sales Price Date of Apreement (in millions)Oklaunion Power Station $42.8 January 30, 2004 LIG Pipeline and its subsidiaries $76.2 February 13, 2004 STP $332.6 February 27, 2004 A-131 We anticipate these sales to be completed during 2004 and that the impact on results of operations will not be significant. The Nanyang General Light (Pushan) investment was sold for $60.7 million on March 2, 2004. This sale had no significant impact on our results of operations. On March 10, 2004, wve entered into an agreement to sell four domestic Independent Power Producer (IPP)investments for a sales price of $156 million. We anticipate this sale to be completed during 2004 and to result in a pre-tax gain of approximately $100 million.A-132 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of American Electric Power Company, Inc.: We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and subsidiary companies as of December 31, 2003 and 2002, and the related consolidated statements of operations, cash flows and common shareholders' equity and comprehensive income, for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and subsidiary companies as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.As discussed in Note 2 to the consolidated financial statements, the Company adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002.As discussed in Note 2 to the consolidated financial statements, the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations" and EITF 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" effective January 1, 2003.As discussed in Note 2 to the consolidated financial statements, the Company adopted FIN 46, "Consolidation of Variable Interest Entities" effective July 1, 2003.Isl Deloitte & Touche LLP Columbus, Ohio March 5, 2004 A-133 MANAGEMENT'S RESPONSIBILITY The management of American Electric Power Company, Inc. (the Company) has prepared the financial statements and schedules herein and is responsible for the integrity and objectivity of the information and representations in this annual report, including the consolidated financial statements. These statements have been prepared in conformity with accounting principles generally accepted in the United States of America, using informed estimates where appropriate, to reflect the Company's financial condition and results of operations. The information in other sections of the annual report is consistent with these statements. The Company's Board of Directors has oversight responsibilities for determining that management has fulfilled its obligation in the preparation of the financial statements and in the ongoing examination of the Company's established internal control structure over financial reporting. The Audit Committee, which consists solely of outside directors and which reports directly to the Board of Directors, meets regularly with management, Deloitte & Touche LLP -independent auditors and the Company's internal audit staff to discuss accounting, auditing and reporting matters. To ensure auditor independence, both Deloitte & Touche LLP and the internal audit staff have unrestricted access to the Audit Committee. The financial statements have been audited by Deloitte & Touche LLP, whose report appears on the previous page.A-134 AEP GENERATING COMPANY AEP GENERATING COMPANY SELECTED FINANCIAL DATA 2003 2002 2001 (in thousands) 2000 1999 INCOME STATEMENTS DATA Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Net Income$233,165 225.991 7,174 3,340 2,550$213,281 207.152 6,129 3,681 2.258_-$1.5$227,548 220.571 6,977 3,484 2,586_$7.8-75-$228,516 220.092 8,424 3,429 3.869$217,189 211.849 5,340 3,659 2.804 BALANCE SHEETS DATA Electric Utility Plant Accumulated Depreciation Net Electric Utility Plant$674,055 351,062$322.9$652,213 330.187$322,02$648,254 310.804$642,302 290.858$351.444$640,093 271,941$3M68152 TOTAL ASSETS$380,045 $37.1M3768 $9,1 4L6 Common Stock and Paid-in Capital Retained Earnings Total Common Shareholder's Equity$24,434 21.441$24,434 18,163_$42,59$24,434 13,761_$382$24,434 9.722_$34.5$30,235 3.673 Long-term Debt (a)_$4811 $44 2 $44,79 $44,Q $-44.80 Obligations Under Capital Leases (a)TOTAL CAPITALIZATION AND LIABILITIES --=$269- _$50J $311 $591 $$380,045 $377,716 $387,68 $3992.31 $42I7I (a) Including portion due within one year.B-1 AEP GENERATING COMPANY MANAGEMIENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS AEGCo, co-owner of the Rockport Plant, is engaged in the generation and wholesale sale of electric power to two affiliates, I&M and KPCo, under long-term agreements. I&M is the operator and the other co-owner of the Rockport Plant.Operating revenues are derived from the sale of Rockport Plant energy and capacity to I&M and KPCo pursuant to FERC approved long-term unit power agreements. Under the terms of its unit power agreement, l&M agreed to purchase all of AEGCo's Rockport energy and capacity unless it is sold to other utilities or affiliates. I&M assigned 30% of its rights to energy and capacity to KPCo. This assignment expires December 31, 2004.The unit powver agreements provide for a FERC approved rate of return on common equity, a return on other capital (net of temporary cash investments) and recovery of costs including operation and maintenance, fuel and taxes. Under the terms of the unit power agreements, AEGCo accumulates all expenses monthly and prepares bills for its affiliates. In the month the expenses are incurred, AEGCo recognizes the billing revenues and establishes a receivable from the affiliated companies. Results of Operations 2003 Compared to 2002 Net Income increased $412 thousand for the year 2003 compared with the year 2002. The fluctuations in Net Income are a result of terms in the unit power agreements which allow for the return on total capital of the Rockport Plant calculated and adjusted monthly.Operating Income Operating Income increased $1 million for the year 2003 compared with the year 2002 primarily due to:* A $20 million increase in Operating Revenue as a result of increased recoverable expenses, primarily Fuel for Electric Generation, in accordance with the unit power agreements along with increased return on total capital.* A $2 million decrease in Maintenance and Other Operation expense. This decrease is due primarily to the impact of cost reduction efforts instituted in the fourth quarter of 2002 and related employment termination benefits allocated to AEGCo in 2002.The increase in Operating Income was partially offset by:* A $20 million increase in Fuel for Electric Generation expense. This increase is primarily due to an increase in the average cost of coal and an 8% increase in MWH generation. Off-Balance Sheet Arrangements We enter into off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties. The following identifies significant off-balance sheet arrangements: RocAport Plant Unit 2 AEGCo and I&M entered into a sale and leaseback transaction in 1989 with Wilmington Trust Company (Oxvner Trustee), an unrelated unconsolidated trustee for Rockport Plant Unit 2 (the plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and certain institutional investors. The future minimum lease payments for each respective company are $1.4 billion.B-2 The FASB and other accounting constituencies continue to interpret the application of FIN 46 (revised December 2003)(FIN 46R). As a result, we are continuing to review the application of this new interpretation as it relates to the Rockport Plant Unit 2 transaction. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the plant and leases it to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the lease footnote. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and l&M have the option to renew the lease or the Owner Trustee can sell the plant.Neither AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and none of these entities guarantee its debt.Summary Obli2ation Information Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2003: Payments Due by Period (in millions)Contractual Cash Obligations Less Than 1 year 2-3 years 4-5 years After 5 years Total Long-term Debt $- $- $- $45 $45 Advances from Affiliates 37 ---37 Unconditional Purchase Obligations (a) 82 75 75 161 393 Noncancellable Operating Leases 74 148 148 1J033 1,403 Total $193 $223 $223 $L23-2 _18 (a) Represents contractual obligations to purchase coal as fuel for electric generation along with related transportation of the fuel.Some of the transactions, described under "Off-Balance Sheet Arrangements" above, have been employed for a contractual cash obligation reported in the above table. The lease of Rockport Unit 2 is reported in Noncancellable Operating Leases.Significant Factors See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-l for additional discussion of factors relevant to us.B-3 AEP GENERATING COMPANY STATEMENTS OF INCOME For the Years Ended December 31,2003,2002 and 2001 2003 2002 (in thousands) 2001 OPERATING REVENUES$233,165 OPERATING EXPENSES Fuel for Electric Generation Rent -Rockport Plant Unit 2 Other Operation Maintenance Depreciation Taxes Other Than Income Taxes Income Taxes TOTAL 109,238 68,283 10,399 10,346 22,686 3,396 1.643 225.991$213.281 89,105 68,283 12,924 9,418 22,560 3,281 1.581 207,152$227.548 102,828 68,283 11,025 8,853 22,423 4,257 2.902 220,571 OPERATING INCOME 7,174 6,129 6,977 Nonoperating Income Nonoperating Expenses Nonoperating Income Tax Credits Interest Charges NET INCOME 151 361 3,550 2.550$7.964 344 199 3,536 2,258$7.552 30 16 3,470 2,586 STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31,2003,2002 and 2001 2003 2002 (in thousands) 2001 BALANCE AT BEGINNING OF PERIOD Net Income$18,163$13,761$9,722 7,964 7,552 7,875 Cash Dividends Declared 4.686 3.150 3.836 BALANCE AT END OF PERIOD $2 The common stock ofAEGCo is whollyowned byAEP.See Notes to Respective Financial Statements beginning on page L-l.B-4 AEP GENERATING COMPANY BALANCE SHEETS ASSETS December 31,2003 and 2002 2003 2002 (in thousands) ELECTRIC UTILITY PLANT Production General Construction Work in Progress TOTAL Accumulated Depreciation TOTAL -NET$645,251 4,063 246741 674,055 351.062 322.993$637,095 4,728 10.390 652,213 330.187 322.026 OTHER PROPERTY AND INVESTMENTS -Non-Utility Property, Net 119 119 CURRENT ASSETS Accounts Receivable -Affiliated Companies Fuel Materials and Supplies TOTAL DEFERRED DEBITS AND OTHER ASSETS Regulatory Assets: Unamortized Loss on Reacquired Debt Asset Retirement Obligations Deferred Charges TOTAL 24,748 20,139 5,419 50.306 18,454 20,260 4.913 43.627 4,970 6,974 11.944 4,733 928 966 6.627 TOTAL ASSETS See Notes to Respective Financial Statements beginning on page L-1.M3.0.Q0i B-5 AEP GENERATING COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31, 2003 and 2002 2003 2002 (in thousands) CAPITALIZATION Common Shareholder's Equity: Common Stock -Par Value $1,000 per share: Authorized and Outstanding -1,000 Shares Paid-in Capital Retained Earnings Total Common Shareholder's Equity Long-term Debt TOTAL$1,000 23,434 21.441 45,875 44,811 90,686$1,000 23,434 18.163 42,597 44,802 87.399 CURRENT LIABILITIES Advances from Affiliates Accounts Payable: General Affiliated Companies Taxes Accrued Interest Accrued Obligations Under Capital Leases Rent Accrued -Rockport Plant Unit 2 TOTAL 36,892 498 15,911 6,070 911 87 4.963 65,332 28,034 26 15,907 2,327 911 200 4,963 52.368 DEFERRED CREDITS AND OTHER LIABILITIES Deferred Income Taxes Regulatory Liabilities: Asset Removal Costs Deferred Investment Tax Credits SFAS 109 Regulatory Liability, Net Deferred Gain on Sale and Leaseback -Rockport Plant Unit 2 Obligations Under Capital Leases Asset Retirement Obligations Other TOTAL 24,329 27,822 49,589 15,505 105,475 182 1,125 29,002 52,943 16,670 111,046 301 27.987 237.949 Commitments and Contingencies (Note 7)TOTAL CAPITALIZATION AND LIABILITIES $377,71 See ANotes to Respective Financial Statements beginning on page L-J.B-6 AEP GENERATING COMPANY STATEMENTS OF CASH FLOWS For the Years Ended December 31,2003,2002 and 2001 2003 OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities: Depreciation Deferred Income Taxes Deferred Investment Tax Credits Amortization of Deferred Gain on Sale and Leaseback -Rockport Plant Unit 2 Changes in Certain Assets and Liabilities: Accounts Receivable Fuel, Materials and Supplies Accounts Payable Taxes Accrued Deferred Property Taxes Change in Other Assets Change in Other Liabilities Net Cash Flows From Operating Activities $7,964 22,686 (5,838)(3,354)(5,571)(6,294)(385)476 3,743 (45)3,531 1,007 17.920 2002 (in thousands) $7,552 22,560 (5,028)(3,361)(5,571)4,037 (5,450)6,697 (2,450)190 (5,401)(2,295)11,480 2001$7,875 22,423 (6,224)(3,414)(5,571)1,224 (4,738)(4,597)(216)(49)(520)(1,244 4,949 INVESTING ACTIVITIES Construction Expenditures Proceeds From Sale of Assets Net Cash Flows Used For Investing Activities (22,197)105 (22,092 (5,298)(5,298)(6,868)(6.868 FINANCING ACTIVITIES Change in Advances from Affiliates Dividends Paid Net Cash Flows From (Used For) Financing Activities 8,858 (4.686)4,172 (4,015)(3,150)(7,165)3,981 (3,836 145 Net Decrease in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period (983)983 (1,774)2,757 SUPPLEMENTAL DISCLOSURE: Cash paid for interest net of capitalized amounts was $2,283,000, $2,019,000 and $1,509,000 and for income taxes was $6,483,000, $7,884,000 and $8,597,000 in 2003, 2002 and 2001, respectively. See Notes to Respective Financial Statements beginning on page L-1.B-7 AEP GENERATING COMPANY STATEMENTS OF CAPITALIZATION December 31, 2003 and 2002 2003 2002 (in thousands) COMMON SHAREHOLDER'S EQUITY $45.875 $42,597 LONG-TERM DEBT: Installment Purchase Contracts -City of Rockport (a)Series Due Date 1995 A 2025(b) 22,500 22,500 1995 B 2025(b) 22,500 22,500 Unamortized Discount (189. (198)TOTAL LONG-TERM DEBT 44,811 44.802 TOTAL CAPITALIZATION MlQa $87.399 (a) Installment purchase contracts were entered into in connection with the issuance of pollution control revenue bonds by the City of Rockport, Indiana. The terms of the installment purchase contracts require AEGCo to pay amounts sufficient to enable the payment of interest and principal on the related pollution control revenue bonds issued to refinance the construction costs of pollution control facilities at the Rockport Plant.(b) These series have an adjustable interest rate that can be a daily, weekly, commercial paper or term rate as designated by AEGCo. Prior to July 13, 2001, AEGCo had selected a daily rate which ranged from 0.9% to 5.6% during 2001 and averaged 2.8% in 2001. Effective July 13, 2001, AEGCo selected a term rate of 4.05% for five years ending July 12, 2006.See ANotes to Respective Financial Statements beginning on page L-l.B-8 AEP GENERATING COMPANY INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to AEGCo's financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to AEGCo. The footnotes begin on page L-1.Footnote Reference Organization and Summary of Significant Accounting Policies Note I New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes Note 2 Effects of Regulation Note 5 Commitments and Contingencies Note 7 Guarantees Note 8 Sustained Earnings Improvement Initiative Note 9 Benefit Plans Note 11 Business Segments Note 12 Derivatives, Hedging and Financial Instruments Note 13 Income Taxes Note 14 Leases Note 15 Financing Activities Note 16 Related Party Transactions Note 17 Unaudited Quarterly Financial Information Note 19 B-9 INDEPENDENT AUDITORS' REPORT To the Shareholder and Board of Directors of AEP Generating Company: NVe have audited the accompanying balance sheets and statements of capitalization of AEP Generating Company as of December 31, 2003 and 2002, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that wve plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Generating Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America./s/ Deloitte & Touche LLP Columbus, Ohio March 5, 2004 B-10 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY SELECTED CONSOLIDATED FINANCIAL DATA 2003 2002 2001 (in thousands) INCOME STATEMENTS DATA Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Income Before Cumulative Effect of Accounting Change Cumulative Effect of Accounting Change (Net of Tax)Net Income Preferred Stock Dividend Requirements Gain (Loss) on Reacquired Preferred Stock Earnings Applicable To Common Stock$1,747,511 1,425.971 321,540 29,819 133.812 217,547 122 217,669 241_$217.42&$1,690,493 _1,296,760 393,733 8,079 125.871 275,941 275,941 241 4$22.7Q1$1,738,837 1,443,106 295,731 2,815 116.268 182,278 182,278 242$182,03 2000$1,770,402 1,463.304 307,098 7,235 124.766 189,567 189,567 241 WLM3n2 1999$1,482,475 1.188.490 293,985 2,596 114.380 182,201 182,201 6,931 (2.763)$-12.507 BALANCE SHEETS DATA Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant$2,425,038 $2,334,794 $2,231,287 616.526$1,614,6$2,097,497 570.522 L$526.7$1,996,374 598.275_I123Q22 695,359$IX1.72 662.345 116122 TOTAL ASSETS$555f521i Common Stock and Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total Common Shareholder's Equity$187,898 1,083,023 (61.872)$L20.4$187,898 $573,903 986,396 826,197$573,904 $573,904 792,219 758,894 (73.160)~$1,91013-$IA~QQ$L332M72&Cumulative Preferred Stock Not Subject to Mandatory Redemption Trust Preferred Securities (a)J$AI8.Q Long-term Debt (b)$2.291.625 IAi.5 Obligations Under Capital Leases (b)TOTAL CAPITALIZATION AND LIABILITIES B2fl3QL (a) See Note 16 of the Notes to Respective Financial Statements.(b) Including portion due wvithin one year.C-l AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS AEP Texas Central Company (TCC), formerly know as Central Power and Light Company (CPL), is a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power. As a power pool member with AEP WVest companies, we share in the revenues and expenses of the power pool's sales to neighboring utilities and power marketers. TCC also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and retail electric providers (REPs) in Texas.Power pool members are compensated for energy delivered to other members based upon the delivering members'incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives. The revenue and costs for sales to neighboring utilities and power marketers made by AEPSC on behalf of the AEP West companies are shared among the members based upon the relative magnitude of the energy each member provides to make such sales.Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other AEP registrant subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas. The electricity and gas contracts include physical transactions, over-the-counter options and swaps and exchange traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts. Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and WVest companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and XVest companies' allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and WVest companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and West companies, respectively, for the remainder of 2003.Results of Operations 2003 Compared to 2002 Net Income decreased $58 million for 2003. The decrease is mainly due to an increased provision for refunds of $85 million ($55 million after tax) and a decrease in the recognition of non-cash earnings related to legislatively mandated capacity auctions and regulatory assets established in Texas of $29 million net of tax. Additionally, income from transactions with ERCOT increased significantly due mainly to Texas Restructuring Legislation. Since REPs are the electricity suppliers to retail customers in the ERCOT area, we sell our generation to the REPs and other market participants and provide transmission and distribution services to retail customers of the REPs in our service territory. As a result of the provision of retail electric service by REPs, effective January 1, 2002, we no longer supply electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a shift in our sales as further described below.In December 2002, AEP sold Mutual Energy CPL to an unrelated third party, who assumed the obligations of the affiliated REP including the provision of price-to-beat rates under the Texas Restructuring Legislation. Prior to the sale, during 2002, sales to Mutual Energy CPL were classified as Sales to AEP Affiliates. Subsequent to the sale, energy transactions and delivery charges with Mutual Energy CPL are classified as Electric Generation, Transmission and Distribution. C-2 Operating Income Operating Income decreased $72 million primarily due to:* Increased provisions for rate refunds of $85 million due mainly to 2003 Texas fuel issues (see "TCC Fuel Reconciliation" in Note 4).* Decreased revenues associated with establishing regulatory assets in Texas of $44 million or 17% in 2003 (see "Texas Restructuring" in Note 6). These revenues will not continue after 2003.* Decreased system sales, including those to REPs, of $7 million due mainly to a decrease in the overall average price per KWH and higher KWH sales of 2%.* Decreased revenues from ERCOT for various services, including balancing energy, of $7 million or 7%.* The 2002 ICR adjustments which accounted for approximately $59 million of the decrease in revenue with an offsetting $51 million decrease in purchased power.* Decreased retail revenues of $24 million driven by a 9% decrease in cooling degree-days offset by a slight increase in heating degree-days. Average price per KWH decreased 2%.* Increases in fuel and purchased electricity on a net basis of $197 million to replace portions of the energy from the non-RMR mothballed plants and the unscheduled forced outage at the STP nuclear unit (See"Significant Factors" below). KWH purchased increased 47% while the cost increased 54%. Although the KWH generated decreased, fuel costs increased 16% due to higher per unit costs attributable mostly to natural gas.* Increased Maintenance expense of $8 million due mainly to the STP Unit 2 forced outage in the first quarter of 2003 and the STP Unit I scheduled refueling outage and forced outage in the second and third quarters of 2003.The decrease in Operating Income was partially offset by:* Increased Reliability Must Run (RMR) revenues from ERCOT of $214 million which include both fuel recovery and a fixed cost component of $35 million (see "Texas Plants" in Note 10 for discussion of RMR facilities).

Increased margins of $31 million resulting from risk management activities.
Increased other operating revenue of $25 million comprised primarily of miscellaneous service revenue and fees as a result of the Texas Restructuring Legislation.
Decreased Other Operation expense of $6 million due primarily to lower distribution and customer related expenses in 2003, offset in part by $16 million of accretion expense associated with the implementation of SFAS 143, as well as increased cost of $6 million related to 2003 ERCOT transmission charges.* Decreased Depreciation and Amortization expense of $25 million due mainly to decreases resulting from ARO of $16 million (see Note 2) and reduced depreciable plant by $6 million due to the mothballing of certain generating units in 2002.* Decreased Taxes Other Than Income Taxes of $3 million due mainly to reduce gross receipt taxes as a result of the sale of the Texas REPs, partially offset by higher property taxes.* Decreased Income Taxes of $41 million due to decreased pre-tax operating income.Other Impacts on Earnings Nonoperating Income increased

$1 million. While 2003 gains from risk management activities increased $33 million, they are almost totally offset by lower 2003 revenues of $33 million from third party non-utility energy related construction projects.Nonoperating Expense decreased $25 million primarily due to lower non-utility expenses associated with energy related construction projects for third parties.Nonoperating Income Tax Expense (Credit) increased $4 million due to increased pre-tax nonoperating income partially offset by changes related to consolidated tax savings.Interest Charges increased $8 million primarily due to the replacement of lower cost short-term floating rate debt with longer-term higher cost fixed rate debt.C-3 2002 Compared to 2001 In 2002, Net Income increased $94 million primarily due to $262 million of revenue associated with recognition of stranded costs in Texas offset in part by losses associated with the commencement of customer choice in Texas, which resulted in the loss of customers and reduced prices (see Note 6).Operating Income Operating Income increased $98 million primarily due to:* Increased revenue associated with establishing regulatory assets in Texas of $262 million in 2002 (see "Texas Restructuring" in Note 6).* Increased system sales, including those to REPs, of $84 million due mainly to the newly created affiliated REP, offset by retail fuel revenue, as a result of Texas Restructuring Legislation.

Increase revenues of $73 million from ERCOT for various services, including balancing energy, as a result of Texas Restructuring Legislation.
The 2002 ICR adjustments which accounted for approximately

$59 million of the increase in revenue with an offsetting $51 million increase in purchased power (See "ICR Explanation" in Note 4 for discussion of the ICR adjustments).

Decreased provisions for rate refunds of $3 million due mainly to a 2001 FERC transmission tariff refund.* Increased RMR revenues from ERCOT of $28 million which include both fuel recovery and a fixed cost component (see "Texas Plants" in Note 10 for discussion of RMR facilities).
Net decreases in fuel and purchased electricity on a combined basis of $198 million due to a decrease in both generation and the average cost of fuel, offset in part by increased KWI purchased.

More KWH were purchased in part due to our ability to purchase power below our cost to produce. KWIH purchased increased 5% while the total cost increased 26%. The KWH generated decreased by 27% and fuel costs decreased 50%.* Decreased Other Operation expense of $17 million due to the elimination of factoring of accounts receivable, as well as lower ERCOT transmission charges.* Decreased Maintenance expense of $8 million due mainly to two scheduled "18 months interval" refueling outages for STP during 2001 that increased maintenance expense above the 2002 level. Also contributing to the decrease in 2002 was an increase in maintenance expense for scheduled major overhauls of four power plants in 2001.The increase in Operating Income was partially offset by:* Decreased retail revenues due to the Texas Restructuring Legislation of $467 million in 2002 (see "Texas Restructuring" in Note 6).* Decreased revenues of $54 million resulting from risk management activities.

Increased Depreciation and Amortization expense of $46 million due mainly to the amortization of regulatory assets that were securitized in the first quarter of 2002 and being collected in revenue, offset by the elimination of excess earnings expense in 2002 under Texas Restructuring Legislation (See Note 6).* Increased Taxes Other Than Income Taxes of $5 million due to higher local franchise taxes, offset by one-time 2001 assessments and decreased gross receipts tax due to deregulation.

Other Impacts on Earnings Nonoperating Income increased $31 million primarily due to increased non-utility revenues associated with energy related construction projects for third parties offset in part by decreased interest income.Nonoperating Expense increased $20 million primarily due to increased non-utility expenses associated with energy related construction projects for third parties offset in part by the extraordinary loss on reacquired debt in 2001, that was reclassified to Nonoperating Expense with the implementation of SFAS 145 (See Note 1).Nonoperating Income Tax Expense (Credit) increased $5 million due to higher pre-tax nonoperating book income.Interest Charges increased $10 million primarily due to higher levels of outstanding debt.C4 Cunulative Effect ofAccowiting Change This amount represents the one-time after-tax effect of the application of EITE 02-3 (see Note 2).Financial Condition Credit Ratings The rating agencies currently have us on stable outlook. Our current ratings are as follows: Moody's S&P Fitch A A-First Mortgage Bonds Senior Unsecured Debt Baal Baa2 BBB BBB In February 2003, Moody's Investor Service (Moody's) completed their review of AEP and its rated subsidiaries. The.results of that review included a downgrade of TCC's rating for unsecured debt from Baal to Baa2 and secured debt from A3 to Baal. The completion of this review wvas a culmination of ratings action started during 2002. With the completion of the reviews, Moody's has placed AEP and its rated subsidiaries on stable outlook. In March 2003, S&P lowered AEP and our senior unsecured debt and first mortgage bonds ratings from BBB+ to BBB.Cash Flow Cash flows for the year ended December 31,2003, 2002 and 2001 were as follows: 2003 2002 (in thousands) $85.420 $10.909 Cash and cash equivalents at beginning of period Cash flow from (used for): Operating activities Investing activities Financing activities Net increase (decrease) in cash and cash equivalents Cash and cash equivalents at end of period 367,223 (134,316)(252,445)(19.538)_$65882 147,493 (151,502)78.520 74,511 2001$14.253 469,920 (194,086)(279.178)(3.344).$10909~Operating Activities Cash flow from operating activities were $367 million primarily due to net income as explained above, changes to Accounts Receivable, Accounts Payable and Accrued Taxes, as well as, non-cash Depreciation and Amortization partially offset by the non-cash Texas Wholesale Clawvback regulatory asset recorded in 2003.Investing Activities Investing expenditures in 2003 were $134 million due mostly to construction expenditures focused on improved service reliability projects for transmission and distribution systems.Financing Activities We obtained the additional funds needed for financing activities through new borrowings of $962 million in 2003.Current year debt proceeds replaced both short and long-term debt.C-5 Summary Oblization Information Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2003: Payments Due by Period (in thousands) Contractual Cash Obligations Less Than 1 year 2-3 years 4-5 years After 5 years Total Long-term Debt Unconditional Purchase Obligations (a)Capital Lease Obligations Noncancellable Operating Leases Total$237,651 $524,838 $121,417 53,749 450 6.112$29i96 82,203 571 11,104$618.71 60,648 110 8.347$190.522$1,407,719 $2,291,625 133,608 330,208-1,131 11,272 36,835$L2.99 $2,652 (a) Represents contractual obligations to purchase coal and natural gas as fuel for electric generation along with related transportation costs.In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business. These commitments include standby letters of credit and other commitments. Our commitments outstanding at December 31, 2003 under these agreements are summarized in the table below: Amount of Commitment Expiration Per Period (in thousands) Other Commercial Commitments Less Than I year 2-3 years 4-5 years After 5 years Total Standby Letters of Credit Transmission Facilities for Third Parties (a)Total$- $43,000$- $43,000 22.811$-221 74.716 30.720-128247_$: $11.27 (a) As construction agent for third party owners of transmission facilities, wve have committed by contract terms to complete construction by dates specified in the contracts. Sienificant Factors See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-1 for additional discussion of factors relevant to us.Quantitative And Qualitative Disclosures About Risk Management Activities Market Risks Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effect.C-6 MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.MTM Risk Management Contract Net Assets Year Ended December 31,2003 (in thousands) Domestic Powver Beginning Balance December 31, 2002 $5,414 (Gain) Loss from Contracts Realized/Settled During the Period (a) (2,033)Fair Value of New Contracts When Entered Into During the Period (b)Net Option Premiums Paid/(Received) (c) (130)Change in Fair Value Due to Valuation Methodology Changes Effect of EITF 98-10 Rescission (d) 187 Changes in Fair Value of Risk Management Contracts (e) 8,504 Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges 11,942 Net Cash Flow Hedge Contracts (g) (2,812)Ending Balance December 31, 2003 (a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003.(b)The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location.(c)"Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003.(d)See Note 2 "New Accounting Pronouncements Extraordinary Items and Cumulative Effect of Accounting Changes." (e)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.(f)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.(g)"Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in Accumulated Other Comprehensive Income (Loss).Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.C-7 Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets Fair Value of Contracts as of December 31,2003 After 2004 2005 2006 2007 2008 2008 Total (c)(in thousands)

Prices Actively Quoted -Exchange Traded Contracts $238 $(99) $9 $61 $- $- $209 Prices Provided by Other External Sources -OTC Broker Quotes (a) 1,752 1,570 576 363 208 -4,469 Prices Based on Models and Other Valuation Methods (b) 4,346 511 114 237 497 1,559 7,264 Total $633 $L982 $699 $6L $ML 1$L $1LL2 (a)"Prices Provided by Other External Sources -OTC Broker Quotes" reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.(b)"Prices Based on Models and Other Valuation Methods" is in absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the Modeled category varies by market.(c)Amounts exclude Cash Flow Hedges.Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. (However, given that under SFAS 133 only cash flow hedges are recorded in AOCI, the table does not provide an all-encompassing picture of our hedging activity). The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll-off of hedges). In accordance with GAAP, all amounts are presented net of related income taxes.Total Accumulated Other Comprehensive Income (Loss) Activity Year Ended December 31,2003 Domestic Power (in thousands) Beginning Balance December 31,2002 $(36)Changes in Fair Value (a) (1,931)Reclassifications from AOCI to Net Income (b) 139 Ending Balance December 31,2003 .$CL828)(a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes.(b) "Reclassifications from AOCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above.The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a$1,413 thousand loss.C-8 Credit Risk Our counterparty credit quality and exposure is generally consistent with that of AEP.VaR Associated with Management Contracts The following table shows the end, high, average, and low market risk as measured by VaR for year-to-date: December 31, 2003 (in thousands) End High Average Low$189 $733 $307 $73 December 31, 2002 (in thousands) End High Average Low$115 $353 $126 $26 VaR Associated wiith Debt Outstanding The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $206 million and $65 million at December 31, 2003 and 2002, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.C-9 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31,2003,2002 and 2001 2003 OPERATING REVENUES Electric Generation, Transmission and Distribution Sales to AEP Affiliates TOTAL$1,593,943 153.568 1.747.511 2002 (in thousands) $682,049 1.008,444 1.690.493 2001$1,697,075 41,762 1.738.837 OPERATING EXPENSES Fuel for Electric Generation Fuel from Affiliates for Electric Generation Purchased Electricity for Resale Purchased Electricity from AEP Affiliates Other Operation Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Income Taxes TOTAL 89,389 195,527 373,388 19,097 297,878 71,361 189,130 92,109 98,092 1.425,971 88,488 157,346 211,358 23,406 304,094 63,392 214,162 95,500 139.014 1.296.760 492,057 127,816 58,641 321,227 71,212 168,341 90,916 112,896 1.443,106 OPERATING INCOME 321,540 393,733 295,731 Nonoperating Income Nonoperating Expenses Nonoperating Income Tax Expense (Credit)Interest Charges 54,172 17,273 7,080 133,812 53,141 41,910 3,152 125.871 22,552 21,486 (1,749)116,268 Income Before Cumulative Effect of Accounting Change Cumulative Effect of Accounting Change (Net of Tax)217,547 122 275,941 182,278 NET INCOME 217,669 275,941 182,278 Gain on Reacquired Preferred Stock Preferred Stock Dividend Requirements 241 4 241 242 EARNINGS APPLICABLE TO COMMON STOCK-$1B2.QM6 The conmon stock of TCC is owned by a ivholly-ownedsubsidiay ofAEP.See Notes to Respective Financial Statements beginning on page L-1.C-10 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME For the Years Ended December 31, 2003, 2002 and 2001 (in thousands) Common Paid-in Stock Capital Retained Earnines Accumulated Other Comprehensive Income (Loss)Total DECEMBER 31, 2000$168,888 $405,015$792,219$- $1,366,122 Common Stock Dividends Declared Preferred Stock Dividends Declared Other TOTAL COMPREHENSIVE INCOME NET INCOME TOTAL COMPREHENSIVE INCOME (148,057)(242)(1)182,278 (148,057)(242)(1!1.217.822 182.278 182.278 DECEMBER 31,2001 Redemption of Common Stock Common Stock Dividends Preferred Stock Dividends Gain on Reacquired Preferred Stock TOTAL$168,888 $405,015 (113,596) (272,409)$826,197 (115,505)(241)4$- $1,400,100 (386,005)(115,505)(241)4 COMPREHENSIVE INCOME Other Comprehensive Income, Net of Taxes: Unrealized Loss on Cash Flow Hedges Minimum Pension Liability NET INCOME TOTAL COMPREHENSIVE INCOME (36)(73,124)(36)(73,124)275.941 202,781 275,941 DECEBIER 31,2002$55,292 $132,606$986,396$(73,160) $1,101,134 Common Stock Dividends Preferred Stock Dividends TOTAL COMPREHENSIVE INCOME Other Comprehensive Income (Loss), Net of Taxes: Unrealized Loss on Cash Flow Hedges Minimum Pension Liability NET INCOME TOTAL COMPREHENSIVE INCOME (120,801)(241)217,669 (120,801)(241)980,092 (1,792)13,080 (1,792)13,080 217.669 228.957 DECEMBER 31,2003$13-2,60-6 LQL $(R61m) $L209049 See Notes to Respective Financial Statements beginning on page L-1.C-lI AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS ASSETS December 31,2003 and 2002 2003 2002 (in thousands) ELECTRIC UTILITY PLANT Production Transmission Distribution General Construction Work in Progress TOTAL Accumulated Depreciation and Amortization TOTAL -NET 767,970 1,376,761 221,354 58.953 2,425,038 695.359 1.729.679 682,780 1,296,731 202,418 152.865 2,334,794 662.345 1.672.449 OTHER PROPERTY AND INVESTMENTS Non-Utility Property, Net Other Investments TOTAL 1,302 4.639 5.941 2,385 354 2,739 CURRENT ASSETS Cash and Cash Equivalents Advances to Affiliates Accounts Receivable: Customers Affiliated Companies Accrued Unbilled Revenues Miscellaneous Allowance for Uncollectible Accounts Materials and Supplies Risk Management Assets Margin Deposits Prepayments and Other Current Assets TOTAL 65,882 60,699 146,630 78,484 23,077 (1,710)11,708 22,051 3,230 6,770 416.821 85,420 113,014 121,324 27,150 529 (346)14,376 22,493 121 2,012 386,093 9,950 262,000 8,661 330,960 13,324 170,101 734,591 4,392 43,890 1,577.869 1.814.810 DEFERRED DEBITS AND OTHER ASSETS Regulatory Assets: SFAS 109 Regulatory Asset, Net Wholesale Capacity Auction True-up Unamortized Loss on Reacquired Debt Designated for Securitization Deferred Debt -Restructuring Other Securitized Transition Assets Long-term Risk Management Assets Deferred Charges TOTAL 3,249 480,000 9,086 1,253,289 12,015 133,913 689,399 7,627 55,554 2,644.132 Assets Held for Sale -Texas Generation Plants 1.028,134 TOTAL ASSETS$i824A70L See Notes to Respective Financial Statements beginning on page L-J.C-12 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31,2003 and 2002 2003 2002 (in thousands) CAPITALIZATION Common Shareholder's Equity: Cormmon Stock -$25 Par Value: Authorized -12,000,000 Shares Outstanding -2,211,678 Shares Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total Common Shareholder's Equity Cumulative Preferred Stock Not Subject to Mandatory Redemption Total Shareholder's Equity CPL -Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of TCC Long-term Debt TOTAL$55,292 132,606 1,083,023 (61,872)1,209,049 5.940 1,214,989 2.053.974 3.268.963$55,292 132,606 986,396 (73,160)1,101,134 5,942 1,107,076 136,250 1.209,434 2.452.760 CURRENT LIABILITIES Short-term Debt -Affiliates Long-term Debt Due Within One Year Advances from Affiliates Accounts Payable: General Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued Risk Management Liabilities Obligation Under Capital Leases Other TOTAL 237,651 90,004 74,209 1,517 67,018 43,196 17,888 407 23.248 555,138 650,000 229,131 126,711 72,199 36,242 666 24,791 51,205 19,811 36,698 1.247.454 1,261,252 1,713 117,686 69,026 51,926 76,547 166.711 1.744.861 DEFERRED CREDITS AND OTHER LIABILITIES Deferred Income Taxes Long-term Risk Management Liabilities Regulatory Liabilities: Asset Removal Costs Deferred Investment Tax Credits Deferred Fuel Costs Retail Clawback Other Obligation Under Capital Leases Deferred Credits and Other TOTAL 1,244,912 2,660 95,415 112,479 69,026 45,527 56,984 636 144.833 1 772,472 Liabilities Held for Sale -Texas Generation Plants 228,134 8.885 Commitments and Contingencies (Note 7)TOTAL CAPITALIZATION AND LIABILITIES $5.453.960 See Notes to Respective Financial Statements beginning on page L-1.C-13 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CAShI FLOWS For the Years Ended 2003, 2002 and 2001 2003 OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities: Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax Credits Cumulative Effect of Accounting Change Mark-to-Market of Risk Management Contracts Wholesale Capacity Auction True-up Changes in Certain Assets and Liabilities: Accounts Receivable, Net Fuel, Materials and Supplies Interest Accrued Accounts Payable Taxes Accrued Fuel Recovery Change in Other Assets Change in Other Liabilities Net Cash Floivs From Operating Activities $217,669 189,130 19,393 (5,207)(122)(6,341)(218,000)15,190 15,850 (8,009)55,772 42,227 30,341 19.330 367,223 2002 (in thousands) $275,941 214,162 113,655 (5,206)(1,558)(262,000)(217,149)(4,899)27,490 (6,167)(58,721)16,455 (534)56,024 147,493 2001$182,278 168,341 (72,568)(5,208)(12,048)52,862 (18,215)(2,502)(55,311)27,986 179,866 13,276 11,163 469.920 INVESTING ACTIVITIES Construction Expenditures Other Net Cash Flows Used For Investing Activities (141,771)7.455 (134.316)(151,645)143 (151.502)(193,732)(354)(194,086)FINANCING ACTIVITIES Change in Short-term Debt -Affiliates Issuance of Long-term Debt Retirement of Long-term Debt Change in Advances to/from Affiliates, Net Retirement of Common Stock Retirement of Preferred Stock Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net Cash Flows From (Used For) Financing Activities Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period (650,000)953,136 (247,127)(187,410)(2)(120,801)(241)(252.445)(19,538)85.420$6588_650,000 797,335 (639,492)(227,566)(386,005)(6)(115,505)(241)78.520 74,511 10.909$85.420 260,162 (475,606)84,565 (148,057)(242)(279.178)(3,344)14.253$10,902 SUPPLEMENTAL DISCLOSURE: Cash paid for interest net of capitalized amounts was $129,491,000, $93,120,000 and $109,835,000 and for income taxes wvas $49,630,000, $95,600,000 and $161,529,000 in 2003, 2002 and 2001, respectively. See Notes to Respective Financial Statements beginning on page L-J.C-14 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31, 2003 and 2002 2003 2002 (in thousands) TOTAL COMMON SHAREHOLDER'S EQUITY (a)PREFERRED STOCK -3,035,000 authorized shares, $100 par value Not Subject to Mandatory Redemption: $1.209,049 $1,101,134 Call Price Series December 31, 2003 Number of Shares Redeemed Year Ended December 31, 2003 2002 2001 Shares Outstanding December31, 2003 4.00% $105.75 4.20% 103.75 Total Preferred Stock 11 100 41,927 17,476 4,192 1.748 5.940 4,194 1.748 5.942 TRUST PREFERRED SECURITIES: TCC-Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of TCC, 8.00%, due April 30,2037 (b)-136,250 LONG-TERM (See Schedule of Long-term Debt): First Mortgage Bonds Securitization Bonds (a)Note Payable to Trust (b)Installment Purchase Contracts Senior Unsecured Notes Less Portion Due Within One year 117,939 745,680 140,889 489,585 797,532 (237.651)152,353 796,635 489,577 (229.131)1,209A34 Long-term Debt Excluding Portion Due Within One Year 2.053.974 TOTAL CAPITALIZATION $S1268.96 (a) In February 2002, TCC issued securitization bonds. $386 million of the proceeds was used to retire 4,543,857 shares of common stock.(b) See Note 16 for discussion of Notes Payable to Trust.See Notes to Respective Financial Statements beginning on page L-J.C-15 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY SCHEDULE OF LONG-TERM DEBT December 31,2003 and 2002 First Mortgage Bonds outstanding were as follows:% Rate 6.875 7.25 7-1/8 7.50 6-5/8 Total Due 2003 -February I 2004 -October 1 2008-February 1 2023-April 1 2005-July I 2003 2002 (in thousands) $- $16,418 27,400 27,400 18,581 18,581-17,996 71,958 71.958$117,939 a523--First Mortgage Bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Interest payments are made semi-annually.Securitization Bonds outstanding were as follows: Final Payment%i/Rate Date 3.54 1/15/2005 5.01 1/15/2008 5.56 1/15/2010 5.96 7/15/2013 6.25 1/15/2016 Unamortized Discount Total Maturity Date 1/15/2007 1/15/2010 1/15/2012 7/15/2015 1/15/2017 2003 2002 (in thousands) $77,937 $128,950 154,507 154,507 107,094 107,094 214,927 214,927 191,857 191,857 (642) (700)$74,68 $7296 In February 2002, CPL Transition Funding LLC, a special purpose subsidiary of TCC, issued $797 million of Securitization Bonds, Series 2002-1. The Securitization Bonds mature at different times through 2017 and have a weighted average interest rate of 5.4 percent.Senior Unsecured Notes outstanding were as follows: I% Rate Due 5.50 2013-February 15 6.65 2033 -February 15 3.00 2005-February 15 (a) 2005 -February 15 Unamortized Discount Total 2003 2002 (in thousands) $275,000 $-275,000 -150,000 100,000 (2.468) __$72L,52_ L (a) A floating interest rate is determined quarterly. The rate on December 31, 2003 was 2.43%.C-16 Installment Purchase Contracts have been entered into in connection

ith the issuance of pollution control revenue bonds by governmental authorities as follows:% Rate Due Matagorda County Navigation District, Texas: 6.00 2028 -July I 6-1/8 2030-May I 3.75 2003 -November 1 2.15 2030-May I (a)4.00 2030-May I 4.55 2029-November I (b)2.35 2030-May I (a)Guadalupe-Blanco River Authority District, Texas: 2015 -November I (c)Red River Authority of Texas: 6.00 2020-June I Unamortized Discount Total 2003 2002 (in thousands)

$120,265 60,000 111,700 100,635 50,000 40,890 6,330 (235)$SAM85$120,265 60,000 111,700 50,000 100,635 40,890 6,330 (243)$277 (a) Installment Purchase Contract provides for bonds to be tendered in 2004 for 2.15% and 2.35% series. Therefore, these installment purchase contracts have been classified for payment in 2004.(b) Installment Purchase Contract provides for bonds to be tendered in 2006 for 4.55% series. Therefore, this installment purchase contract has been classified for payment in 2006.(c) A floating interest rate is determined daily. The rate on December 31, 2003 was 1.30%.Under the terms of the installment purchase contracts, TCC is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Interest payments range from monthly to semi-annually. Notes Payable to Trust was outstanding as follows: 2003 2002% Rate Due (in thousands) 8.00 2037-April 30 $140,889 $-See Note 16 for discussion of Notes Payable to Trust.At December 31,2003, future annual long-term debt payments are as follows: 2004 2005 2006 2007 2008 Later Years Total Principal Amount Unamortized Discount Total Amount (in thousands) $237,651 371,938 152,900 52,729 68,688 1.411,064 2,294,970 (3.345)$2.29L625 C-17 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to TCC's consolidated financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to TCC. The footnotes begin on page L-1.Footnote Reference Organization and Summary of Significant Accounting Policies Note I New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes Note 2 Rate Matters Note 4 Effects of Regulation Note 5 Customer Choice and Industry Restructuring Note 6 Commitments and Contingencies Note 7 Guarantees Note 8 Sustained Earnings Improvement Initiative Note 9 Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used Note 10 Benefit Plans Note II Business Segments Note 12 Derivatives, Hedging and Financial Instruments Note 13 Income Taxes Note 14 Leases Note 15 Financing Activities Note 16 Related Party Transactions Note 17 Jointly Owned Electric Utility Plant Note 18 Unaudited Quarterly Financial Information Note 19 Subsequent Events (Unaudited) Note 20 C-18 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of AEP Texas Central Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of AEP Texas Central Company and subsidiary as of December 31, 2003 and 2002, and the related consolidated statements of income, changes in common shareholder's equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.WVe conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of AEP Texas Central Company and subsidiary as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.As discussed in Note 2 to the consolidated financial statements, the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003.As discussed in Note 2 to the consolidated financial statements, the Company adopted FIN 46, "Consolidation of Variable Interest Entities," effective July 1, 2003./s/ Deloitte & Touche LLP Columbus, Ohio March 5,2004 C-19 AEP TEXAS NORTH COMPANY AEP TEXAS NORTH COMPANY SELECTED FINANCIAL DATA 2003 2002 2001 (in thousands) INCOME STATEMENTS DATA Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Income (Loss) Before Extraordinary Item and Cumulative Effect of Accounting Change Extraordinary Loss Cumulative Effect of Accounting Change Net Income (Loss)Gain on Reacquired Preferred Stock Preferred Stock Dividend Requirements Earnings (Loss) Applicable to Common Stock$465,946 397.919 68,027 9,685 22,049 55.663 (177)3.071 58,557 3$450,740 442,869 7,871 (703)20.845$556,458 523,068 33,390 2,195 23,275 2000$571,064 518.723 52,341 (1,675)23.216 1999$445,709 391,910 53,799 2,488 24.420 31.867 (5,461)26,406 104 (13.677) 12,310 27450 (13,677)12,310 27,450 104 104 104 104.AI2.2A$21,346 BALANCE SHEETS DATA Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant$1,233,427 $1,201,747 $1,260,872 $1,229,339 $1,182,544 460.513 446,818_$ 54.A 475.036 J78,83 447.802_$78,53 446.282-$73-6,6 TOTAL ASSETS$1,154,743 2$9.10,M Common Stock and Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total Common Shareholder's Equity$139,565 125,428 (26,718!3231&22$139,565 71,942$139,565 105,970$139,565 122,588$139,565 113,242 (30.763)_$1M0.744 5262J5I Cumulative Preferred Stock Not Subject to Mandatory Redemption Long-term Debt (a)$_23,51$_2,M$13.50_$2.3M1$2,367_M$5S,-$2X62i Obligations Under Capital Leases (a) $473 TOTAL CAPITALIZATION AND LIABILITIES $1009 ma$910.770 (a) Including portion due within one year.D-1 AEP TEXAS NORTH COMPANY MANAGENIENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS AEP Texas North Company (TNC), formerly known as XVest Texas Utilities Company (WTTU), is a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power in west and central Texas. As a power pool member with AEP WVest companies, we share in the revenues and expenses of the power pool's sales to neighboring utilities and power marketers. TNC also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and retail electric providers (REPs) in Texas.Power pool members are compensated for energy delivered to other members based upon the delivering members'incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives. The revenue and costs for sales to neighboring utilities and power marketers made by AEPSC on behalf of the AEP West companies are shared among the members based upon the relative magnitude of the energy each member provides to make such sales.Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other AEP registrant subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forvard contracts at fixed and variable prices and to a lesser extent gas.The electricity and gas contracts include physical transactions, over-the-counter options and sw'aps and exchange traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts. Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and West companies' allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and West companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and \Vest companies, respectively, for the remainder of 2003.Results of Operations 2003 Compared to 2002 Net Income increased $72 million primarily due to a 2002 $43 million write-down ($28 million after tax) of gas power plants and increased risk management margins of $20 million in 2003. Transactions with ERCOT also significantly increased income in 2003.Since REPs are the electricity suppliers to retail customers in the ERCOT area, we sell our generation to the REPs and other market participants and provide transmission and distribution services to retail customers of the REPs in our service territory. As a result of the provision of retail electric service by REPs effective January 1, 2002, we no longer supply electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a significant shift in our sales as further described below.In December 2002, AEP sold Mutual Energy WTU to an unrelated third party, who assumed the obligations of the affiliated REP, including the provision of price-to-beat rates under the Texas Restructuring Legislation. Prior to the sale, during 2002, sales to Mutual Energy WTU were classified as Sales to AEP Affiliates. Subsequent to the sale, energy transactions and delivery charges with Mutual Energy WTU are classified as Electric Generation, Transmission and Distribution. D-2 Operating Income Operating Income increased by $60 million primarily due to:* The 2002 asset impairment of $43 million. See Note 10 "Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used."* Increased Reliability Must Run (RMR) revenues from ERCOT of $44 million which include both fuel recovery and a fixed cost component of $13 million (see "Texas Plants" in Note 10 for discussion of RMR facilities).

Increased revenues from risk management activities of $l 0 million.* Increased revenues from ERCOT of $22 million or 91% for various services, due mainly to prior years adjustments made by ERCOT.* Decreased fuel and purchased power on a net basis of $9 million. KNVH generation decreased 27%mainly due to mothballing of plants while the per unit cost of fuel increased 14% due primarily to higher natural gas prices. KWVH purchased declined 9%/O, but the average cost increased 2%.* Reduced Other Operation expenses of $20 million due to several factors including

$8 million of customer service, outside services, other administrative related expenses, ERCOT transmission charges of $4 million, distribution expenses of $2 million, and a $2 million wvrite-dowvn of material and supplies to market value related to the deactivation of several power plants in 2002.* Decreased Maintenance expense of $3 million due primarily to the deactivation of several power plants in 2002 (See Note 10).* Reduced Depreciation and Amortization of $7 million due to the 2002 impairment of several power plants resulting in approximately $4 million less depreciation expense. An additional decrease of $3 million relates to adjustments to prior years' excess earnings accruals under the Texas restructuring legislation due to a favorable Appeals Court ruling (See Note 6).* Decrease of Taxes Other Than Income Taxes of $2 million is due to reduced gross receipts tax as a result of the sale of the Texas REPs.The increase in Operating Income was partially offset by:* Decreased system sales, including those to REP's, of $7 million due mainly to both lower KWH sales of 17% and a decrease in the overall average price per KWVH.* The 2002 ICR adjustments decreased revenue by approximately $24 million in 2003. This decrease wvas partially offset by a reduction in purchased power, due to these adjustments of $5 million.* Decreased delivery revenues of $5 million, due partly to decreased cooling and heating degree-days.

Reduced wholesale revenues of $8 million due to the loss of several large wholesale customers whose contracts expired and were not renewed.* Increased provision for rate refunds of $20 million in 2003 due mainly to the final Texas fuel reconciliation (see "TNC Fuel Reconciliation" in Note 4).* Increased Federal Income Taxes of $39 million due to the increase in pre-tax operating income.Other Impacts on Earnings Nonoperating Income increased

$15 million primarily due to a $10 million increase in net revenue from risk management activities, while revenue from third party non-utility energy related construction projects increased $5 million.Extraordinary (Loss) -(Net of Tax)Extraordinary loss resulted from the cessation of SFAS 71 accounting for wholesale generation assets due to the FERC settlement case (see Note 2).D-3 Cinulative Effect ofAccountting CGiahiges The Cumulative Effect of Accounting Changes is due to a one-time after-tax impact of adopting SFAS 143 (see Note 2).Financial Condition Credit Ratings The rating agencies currently have us on stable outlook. Our current ratings are as follows: Moodv's S&P Fitch First Mortgage Bonds A3 BBB A Senior Unsecured Debt Baal BBB A-In February 2003, Moody's Investor Service (Moody's) completed their review of AEP and its rated subsidiaries. TNC had its secured debt downgraded from A2 to A3 and unsecured debt downgraded from A3 to Baal. The completion of this review was a culmination of ratings action started during 2002. In March 2003, S&P lowered AEP and our senior unsecured debt and mortgage bonds ratings from BBB+ to BBB.Summary Oblivation Information Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2003: Payments Due by Period (in thousands) Contractual Cash Obliigations Less Than 1 year 2-3 years 4-5 years After 5 years Total Long-term Debt $42,505 $37,609 $8,151 $268,489 $356,754 Unconditional Purchase Obligations (a) 51,172 82,478 57,456 201,096 392,202 Capital Lease Obligations 223 275 9 2 509 Noncancellable Operating Leases 1.964 3.791 2770 4981 13.506 Total $124,153 $0, $47568 $762.21 (a) Represents contractual obligations to purchase coal and natural gas as fuel for electric generation along with related transportation costs.In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business. These commitments include standby letters of credit and other commitments. Our commitments outstanding at December 31, 2003 under these agreements are summarized in the table below: Amount of Commitment Expiration Per Period (in thousands) Other Commercial Commitments Less Than 1 year 2-3 years 4-5 years After 5 years Total Transmission Facilities for Third Parties (a) $75,658 $15,621 $- $- $91,279 (a) As construction agent for third party owners of transmission facilities, we have committed by contract terms to complete construction by dates specified in the contracts. D-4 Significant Factors See the "Registrants' Combined Management's Discussion and Anailysis" section beginning on page M-I for additional discussion of factors relevant to us.Quantitative And Oualitativc Disclosures About Risk Management Activities Market Risks Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effects.MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.MTM Risk Management Contract Net Assets Year Ended December 31,2003 (in thousands) Domestic Power Beginning Balance December 31,2002 $2,043 (Gain) Loss from Contracts Realized/Settled During the Period (a) 104 Fair Value of New Contracts WThen Entered Into During the Period (b)Net Option Premiums Paid/(Received) (c) (110)Change in Fair Value Due to Valuation Methodology Changes Effect of EITF 98-10 Rescission (d) 20 Changes in Fair Value of Risk Management Contracts (e) 3,203 Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f) (640)Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges 4,620 Net Cash Flow Hedge Contracts (g) (926)Ending Balance December 31,2003 31691 (a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003.(b)The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location.(c)'Net Option Premiums Paid/(Receivedy' reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003.(d)See Note 2 "New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes." (e)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.(f)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.(g)"Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in Accumulated Other Comprehensive Income (Loss).D-5 Maturity and Source of Fair Value of MTM Risk Management Coniract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
The maturity, by year, of our net assetsAiabilities, giving an indication of when these MTM amounts will settle and generate cash.Maturity and Source of Fair Value of mTM Risk Management Contract Net Assets Fair Value of Contracts as of December 31, 2003 After 2004 2005 2006 2007 2008 2008 Total (c)(in thousands)

Prices Actually Quoted -Exchange Traded Contracts $96 $(40) $4 $24 $- $- $84 Prices Provided by Other External Sources -OTC Broker Quotes (a) 932 631 231 146 84 -2,024 Prices Based on Models and Other Valuation Methods (b) 1.323 223 45 95 199 627 2.512 Total S2.35L_ j1i _$2.. _$25 m2_8 3 $- 2 $4,G2Q (a) "Prices Provided by Other External Sources -OTC Broker Quotes" reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.(b) "Prices Based on Models and Other Valuation Methods" is in absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the Modeled category varies by market.(c) Amounts exclude Cash Flow Hedges.Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. (However, given that under SFAS 133 only cash flow hedges are recorded in AOCI, the table does not provide an all-encompassing picture of our hedging activity). The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll-off of hedges). In accordance with GAAP, all amounts are presented net of related income taxes.D-6 Total Accumulated Other Comprehensive Income (Loss) Activity Year Ended December 31,2003 Domestic Power (in thousands) Beginning Balance December 31,2002 $(15)Changes in Fair Value (a) (641)Reclassifications from AOCI to Net Income (b) 55 Ending Balance December 31, 2003 SOU (a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes.(b) "Reclassifications from AOCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above.The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a$435 thousand loss.Credit Risk Our counterparty credit quality and exposure is generally consistent with that of AEP.VaR Associated with Risk Management Contracts The following table shows the end, high, average, and low market risk as measured by VaR for year-to-date: December 31.2003 December 31, 2002 (in thousands) (in thousands) End Hiah Averaee Low End High Average Low 9U M 123- TM ! S5 11 VaR Associated with Debt Outstanding The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $33 million and $5 million at December 31, 2003 and 2002, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.D-7 AEP TEXAS NORTH COMPANY STATEMENTS OF OPERATIONS For the Years Ended December 31,2003,2002 and 2001 2003 OPERATING REVENUES Electric Generation, Transmission and Distribution Sales to AEP Affiliates TOTAL$410,793 55,153 465.946 2002 (in thousands) $210,315 240,425 450.740 2001$537,777 18,681 556.458 OPERATING EXPENSES Fuel for Electric Generation Fuel from Affiliates for Electric Generation Purchased Electricity for Resale Purchased Electricity from AEP Affiliates Other Operation Asset Impairments Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Income Tax Expense (Credit)TOTAL 39,082 44,197 87,006 39,409 85,263 18,961 36,242 20,570 27,189 397,919 36,081 64,385 80,391 37,582 104,960 42,898 22,295 43,620 22,471 (11.814)442,869 177,140 70,395 56,656 111,248 22,343 50,705 28,319 6.262 523.068 OPERATING INCOME 68,027 7,871 33,390 Nonoperating Income Nonoperating Expenses Nonoperating Income Tax Expense (Credit)Interest Charges 68,451 55,692 3,074 22.049 53,884 54,876 (289)20.845 12,199 10,695 (691)23.275 Income (Loss) Before Extraordinary Items and Cumulative Effect of Accounting Changes Extraordinary (Loss) -(Net of Tax)Cumulative Effect of Accounting Changes (Net of Tax)55,663 (177)3.071 (13,677)12,310 NET INCOME (LOSS)58,557 (13,677)12,310 Gain on Reacquired Preferred Stock Preferred Stock Dividend Requirements 3 104 104 104 EARNINGS (LOSS) APPLICABLE TO COMMON STOCK$58.456_$12.206 The common stock of TNC is owned by a wholly-owned subsidiary of.AEP.See Notes to Respective Financial Statements beginning on page L-J.D-8 AEP TEXAS NORTH COMPANY STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME For the Years Ended December 31, 2003, 2002 and 2001 (in thousands) Accumulated Other Comprehensive Income (Loss)Common Paid-in Retained Stock Capital Earnines Total DECEMBER 31,2000 S137,214$2,351$122,588$- $262,153 Common Stock Dividends Declared Preferred Stock Dividends Declared TOTAL COMPREHENSIVE INCOME NET INCOME TOTAL COMPREHENSIVE INCOME (28,824)(104)12,310 (28,824)(104)233,225 12.310 12.310 DECEMBER 31,2001$137,214$2,351$105,970 '$- $245,535 Common Stock Dividends Preferred Stock Dividends TOTAL (20,247)(104)(20,247)(104)225.184 COMPREHENSIVE INCOME Other Comprehensive Income, Net of Taxes: Unrealized Loss on Cash Flow Hedges Minimum Pension Liability NET INCOME (LOSS)TOTAL COMPREHENSIVE INCOME (15)(30,748)(15)(30,748)(13.677)(44.440)(13,677)DECEMBER 31,2002$137,214$2,351$71,942$(30,763) $180,744 Common Stock Dividends Preferred Stock Dividends Gain on Reacquired Preferred Stock TOTAL COMPREHENSIVE INCOME Other Comprehensive Income (Loss), Net of Taxes: Unrealized Loss on Cash Flow Hedges Minimum Pension Liability NET INCOME TOTAL COMPREHENSIVE INCOME (4,970)(104)3 (4,970)(104)3 175.673 (586)4,631 (586)4,631 58.557 62.602 58,557 DECEMBER 31,2003_$137,214 .351 __25,28 __$(26M18) See Notes to Respective Financial Statements beginning on page L-1.D-9 AEP TEXAS NORTH COMPANY BALANCE SFIEETS ASSETS December 31,2003 and December 31,2002 2003 2002 (in thousands) ELECTRIC UTILITY PLANT Production Transmission Distribution General Construction Work in Progress TOTAL Accumulated Depreciation and Amortization TOTAL-NET$360,463 268,695 456,278 117,792 30,199 1,233,427 460,513 772.914$353,087 254,483 445,486 111,679 37.012 1,201,747 446,818 754.929 OTHER PROPERTY AND INVESTMENTS Non-Utility Property, Net Other Investments TOTAL CURRENT ASSETS Cash and Cash Equivalents Advances to Affiliates Accounts Receivable: Customers Affiliated Companies Accrued Unbilled Revenues Miscellaneous Allowance for Uncollectible Accounts Fuel Inventory Materials and Supplies Risk Management Assets Margin Deposits Prepayments and Other TOTAL 1,286 1,086 127 1,213 2,863 41,593 1,219 56,670 28,910 4,871 3,411 (175)10,925 8,866 10,340 1,285 1.834 171,393 62,646 43,632 6,829 14 (5,041)12,677 9,574 4,130 37 1.033 136.750 DEFERRED DEBITS AND OTHER ASSETS Regulatory Assets: Deferred Fuel Costs Deferred Debt -Restructuring Unamortized Loss on Reacquired Debt Other Long-term Risk Management Assets Deferred Charges TOTAL 26,680 6,579 3,929 3,332 3,106 20.290 63.916 26,680 10,134 3,283 5,000 2,248 11.912 59.257 TOTAL ASSETS$IQ09U50 See Notes to Respective Financial Statements beginning on page L-1.D-10 AEP TEXAS NORTH COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31,2003 and 2002 2003 2002 (in thousands) CAPITALIZATION Common Shareholder's Equity: Common Stock -$25 Par Value: Authorized -7,800,000 Shares Outstanding -5,488,560 Shares Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total Common Shareholder's Equity Cumulative Preferred Stock Not Subject to Mandatory Redemption Total Shareholder's Equity Long-term Debt TOTAL CURRENT LIABILITIES Short-termn Debt -Affiliates Long-term Debt Due Within One Year Advances from Affiliates Accounts Payable: General Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued Risk Management Liabilities Obligations Under Capital Leases Other TOTAL$137,214 2,351 125,428 (26.718)238,275 2.357 240,632 314.249 554,881 42,505 28,190 40,601 161 22,877 6,038 8,658 203 9,419 158.652$137,214 2,351 71,942 (30.763)180,744 2.367 183,111 132.500 315.611 125,000 80,407 32,714 76,217 117 3,697 2,776 3,801 17.414 342.143 DEFERRED CREDITS AND OTHER LIABILITIES Deferred Income Taxes Long-term Risk Management Liabilities Regulatory Liabilities: Asset Removal Costs Deferred Investment Tax Credits Retail Clawback Excess Earnings SFAS 109 Regulatory Liability, Net Other Obligations Under Capital Leases Deferred Credits and Other TOTAL 113,019 1,094 76,740 19,990 11,804 14,262 13,655 1,826 270 43,316 295,976 117,521 557 21,510 14,328 17,419 12,280 7,285 103,495 294.395 Commitments and Contingencies (Note 7)TOTAL CAPITALIZATION AND LIABILITIES $92.1M49 See Notes to Respective Financial Statements beginning on page L-1.D-11 AEP TEXAS NORTH COMPANY STATEMENTS OF CASH FLOWS For the Years Ended December 31,2003,2002 and 2001 2003 2002 2001 (in thousands) OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities: Depreciation and Amortization Extraordinary (Loss) -Net of Tax Write Down of Utility Plant Assets Write Dowvn of Wind Farm Assets Deferred Income Taxes Deferred Investment Tax Credits Cumulative Effect of Accounting Changes Mark-to-Market of Risk Management Contracts Changes in Certain Assets and Liabilities: Accounts Receivable, Net Fuel, Materials and Supplies Accounts Payable Taxes Accrued Fuel Recovery Change in Other Assets Change in Other Liabilities Net Cash Floas From Operating Activities $58,557 36,242 177 (3,493)(1,520)(3,071)(2,558)14,393 2,460 (40,140)19,180 (8,955)5.996 77,268$(13,677)43,620 38,154 4,744 (12,275)(1,271)(1,127)(80,900)(2,754)63,761 (13,661)14,169 (16,928)16,514 38.369$12,310 50,705 (11,891)(1,271)(3,506)24,844 3,187 (42,604)(1,543)32,505 (1,432)11,056 72,360 INVESTING ACTIVITIES Construction Expenditures Other Net Cash Flows Used For Investing Activities (46,683)688 (45.995)(43,563)150 (43.413)(39,662)(127)(39.789)FINANCING ACTIVITIES Change in Short-term Debt -Affiliates Issuance of Long-term Debt Retirement of Long-term Debt Retirement of Preferred Stock Change in Advances to/from Affiliates, Net Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net Cash Flowvs From (Used For) Financing Activities Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period (125,000)222,455 (10)(122,000)(4,970)(104)(29.629)1,644 1,219--- $63 125,000 (130,799)29,959 (20,247)(104)3,809 (1,235)2.454 (8,130)(28,824)(104)(37.058)(4,487)6.941 J2Afi SUPPLEMENTAL DISCLOSURE: Cash paid for interest net of capitalized amounts was $16,384,000, $19,934,000 and $19,279,000 and for income taxes wvas $16,081,000, $15,544,000 and $21,997,000 in 2003, 2002 and 2001 respectively. See Notes to Respective Financial Statements beginning on page L-J.D-12 AEP TEXAS NORTH1 COMPANY STATEMENTS OF CAPITALIZATION December 31,2003 and 2002 2003 2002 (in thousands) COMMON SHAREHOLDER'S EQUITY$238,275 $180,744 PREFERRED STOCK: $100 par value -authorized shares 810,000 Call Price Series December 31.2003 Number of Shares Redeemed Year Ended December 31, 2003 2002 2001 Shares Outstanding December 31, 2003 Not Subject to Mandatory Redemption: 4.40% $107 102 23,570 2.357 2.367 LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Senior Unsecured Notes Less Portion Due Within One Year 88,236 44,310 224,208 (42,505)88,190 44,310 Long-term Debt Excluding Portion Due Within One Year 314,249 132.500 TOTAL CAPITALIZATION $554.8AL $31261 See Notes to Respective Financial Statements beginning on page L-J.D-13 AEP TEXAS NORTH COMPANY SCHEDULE OF LONG-TERM DEBT December 31,2003 and 2002 First Mortgage Bonds outstanding were as follows:% Rate Due 7.00 2004 -October 1 6-1/8 2004 -February I 6-3/8 2005 -October 1 7-3/4 2007 -June 1 Unamortized Discount Total 2003 (in thousands) $18,469 24,036 37,609 8,151 (29!S &8.23 6 2002$18,469 24,036 37,609 8,151 (75.8-8.19 First Mortgage Bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Interest payments are made semi-annually. Installment Purchase Contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: 2003 2002 (in thousands) % Rate Due Red River Authority of Texas: 6.00 2020- June I$A44310 Under the terms of the Installment Purchase Contracts, TNC is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Interest payments are made semi-annually. Senior Unsecured Notes outstanding were as follows: 2003 2002 (in thousands) % Rate Due 5.50 2013-March I Unamortized Discount Total$225,000 (792)$224.2Q&At December 31,2003, future annual Long-term Debt payments are as follows: 2004 2005 2006 2007 2008 Later Years Total Principal Amount Unamortized Discount Total Amount (in thousands) $42,505 37,609 8,151 269.310 357,575 (821)$356.74 D-14 AEP TEXAS NORTH CONMPANY INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to TNC's financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to TNC. The footnotes begin on page L-1.Footnote Reference Organization and Summary of Significant Accounting Policies Note I New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes Note 2 Rate Matters Note 4 Effects of Regulation Note 5 Customer Choice and Industry Restructuring Note 6 Commitments and Contingencies Note 7 Guarantees Note 8 Sustained Earnings Improvement Initiative Note 9 Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used Note 10 Benefit Plans Note 11 Business Segments Note 12 Derivatives, Hedging and Financial Instruments Note 13 Income Taxes Note 14 Leases Note 15 Financing Activities Note 16 Related Party Transactions Note 17 Jointly Owned Electric Utility Plant Note 18 Unaudited Quarterly Financial Information Note 19 D-15 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of AEP Texas North Company: We have audited the accompanying balance sheets and statements of capitalization of AEP Texas North Company as of December 31, 2003 and 2002, and the related statements of operations, changes in common shareholder's equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Texas North Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.As discussed in Note 2 to the financial statements, the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003.Asl Deloitte & Touche LLP Columbus, Ohio March 5, 2004 D-16 APPALACHIAN POWER COMPANY AND SUBSIDIARIES APPALACHIAN POWER COMPANY AND SUBSIDIARIES SELECTED CONSOLIDATED FINANCIAL DATA 2003 INCOME STATEMENTS DATA Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Income Before Extraordinary Item and Cumulative Effect of Accounting Changes Extraordinary Gain Income Before Cumulative Effect of Accounting Changes Cumulative Effect of Accounting Changes (Net of Tax)Net Income Preferred Stock Dividend Requirements (Including Capital Stock Expense)Earnings Applicable to Common Stock$1,957,358 1,638 547 318,811 (826)115.202 2002$1,814,470 1.512.407 302,063 20,106 116.677 2001 (in thousands) $1,784,259 1.509.273 274,986 6,868 120.036 2000$1,759,253 1.558.099 201,154 11,752 148.000 202,783 205,492 161,818 64,906 8.938 1999$1,586,050 1,344.814 241,236 8,096 128,840 120,492 120,492 120,492 2,706 202,783 77.257 280,040 3.495_$2X£9 205,492 205,492 2.898_-$202.S 161,818 73,844 161,818 73,844 2.011 2,504__sm _ 71.34Q0 BALANCE SHEETS DATA Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant$6,140,931 $5,895,303 $5,664,657 $5,418,278 2.321,360 2.330.012 X,819 5 $,565.291$4,97,01 2$4,72 2,207,072 2.103.471$3,45,585 $3807 S4.M1.2 -$6,5,2$5,262,951 1,998,112$2264>83 4.4433,597 TOTAL ASSETS Common Stock and Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total Common Shareholder's Equity$980,357 408,718$977,700 260,439$976,244 150,797 (340)$IJ2L$975,676 120,584$974,717 175,854 (52,088) (72.082)$1,336987 6 0 Z 31.062 Cumulative Preferred Stock: Not Subject to Mandatory Redemption Subject to Mandatory Redemption Total Cumulative Preferred Stock$17,784 5.360_$23.144$17,790 10.860_$28,60k$17,790 10.860_$S28,a$17,790 10.860 S28,60$18,491 20.310 Long-term Debt (a)$1=86,081 LU8E Obligations Under Capital Leases (a)$46, $63,160 _$64,6L4 TOTAL CAPITALIZATION AND LIABILITIES $4,7,1 _$4.22.S4.S2 36,6UJ2 $4, (a) Including portion due within one year.E-1 APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS APCo is a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 929,000 retail customers in our service territory in southwestern Virginia and southern West Virginia. As a member of the AEP Power Pool, we share the revenues and the costs of the AEP Power Pool's sales to neighboring utilities and power marketers. We also sell power at wvholesale to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member's prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR), which determines each member's percentage share of revenues and costs.In 2003 our relative share of the AEP Power Pool revenues and expenses increased over the prior period as a result of our reaching a new peak demand in January 2003, which increased our allocation factor.Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other AEP registrant subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas. The electricity and gas contracts include physical transactions, over-the-counter options and swaps and exchange traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts. Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and \Vest companies' allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and \Vest companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and \Vest companies, respectively, for the remainder of 2003.Results of Operations Net Income for 2003 increased $75 million over the prior year period primarily due to the Cumulative Effect of Accounting Changes of $77 million recorded in 2003. See "Cumulative Effect of Accounting Changes" in Note 2 for further information. Income Before Cumulative Effect of Accounting Changes decreased slightly from 2002 as improvements in Operating Income were offset by reduced gains from risk management activities included in Nonoperating Income (Expense). The improvement in Operating Income was driven by increased earnings on system sales and reduced employee related expenses partially offset by increased capacity charges included in Purchased Electricity from AEP Affiliates. 2003 Compared to 2002 Operating Income Operating Income for 2003 increased by $17 million from 2002 primarily due to the following:

An increase in system sales and transmission revenues totaling $93 million reflecting an increase in the volume of AEP Power Pool transactions, as well as our relative share based on the higher MLR.* An increase of $36 million in Sales to AEP Affiliates due to strong wholesale sales by the AEP Power Pool.* A decrease in Other Operation expense of $24 million due to severance expenses of $13 million incurred in 2002 related to the SEI initiative (see Note 9, "Sustained Earnings Improvement Initiative"), as well as reduced employee related expenses and insurance premiums in 2003. These decreases were partially offset by an increase in transmission equalization charges due to the increase in APCo's MLR as described above.E-2
A decrease in Depreciation and Amortization expense of$14 million primarily due to reduced amortization of generation related regulatory assets due to the return to SFAS 71 for the West Virginia jurisdiction in the first quarter of 2003 (see Note 5, "Effects of Regulation").
An increase in gains from risk management activities of$l0 million.The increase in Operating Income for 2003 was partially offset by:* An increase in purchased power expenses and fuel expense of $150 million reflecting the $62 million increase in capacity charges resulting from the increase in APCo's MLR as described above, the increase in our relative share of the AEP Power Pool expenses and increased generation.

Also, wve accrued additional fuel expense to increase fuel costs to match fuel revenues billed to ratepayers (see "Deferred Fuel Costs" in Note 1, "Summary of Significant Accounting Policies').

An increase in Maintenance expense of $13 million primarily due to increased maintenance of overhead lines required due to severe storm damage in the first quarter of 2003 and increased overhead line maintenance throughout the year.Other Impacts on Earnings Nonoperating income decreased

$36 million in 2003 compared to 2002 primarily due to lower profit from power sold outside AEP's traditional marketing area resulting from AEP's plan to exit risk management activities in areas outside of its traditional market area. The decrease in nonoperating income was partially offset by a $12 million decrease in nonoperating income taxes resulting primarily from the reduced pre-tax nonoperating book income.Cinulative Effect ofAccounting Changes The Cumulative Effect of Accounting Changes of $77 million is due to the implementation of SFAS 143 and EITF 02-03 (see "Cumulative Effect" section of Note 2).2002 Compared to 2001 ANet Income Net Income for 2002 increased $44 million over the prior year due to higher retail sales resulting from weather related electricity demands and reductions in Maintenance expense. Most significantly the Mountaineer, Amos and Glen Lyn plants, down for boiler maintenance in 2001, were back online in 2002 resulting in increased availability of generation and decreased maintenance expense. In addition, net nonoperating income increased $10 million as a result of a reduction in incentive compensation partially offset by decreased gains from risk management activities. Operating Income Operating Income for 2002 increased $27 million compared to the prior year primarily due to the following:

Retail sales increased

$42 million primarily due to -veather related electricity demands.* An increase in Sales to AEP Affiliates of $15 million due to an increase in generation capacity and power available to be delivered to the AEP Power Pool.* A decrease of $10 million in Maintenance expense due to the boiler maintenance incurred in 2001 as discussed above.* A $97 million decrease in purchase power expense resulting from increased internal generation based on the higher plant availability partially offset by a $79 million increase in Fuel expense necessary to support the increased generation.

A $5 million decrease in Taxes Other Than Income Taxes primarily due to the replacement of the municipal license tax imposed on APCo with the Virginia consumption tax that was imposed on the consumer.E-3 These increases in Operating Income for 2002 were offset by:* A net $32 million decrease in system sales partially offset by gains from risk management activities.
An increase of $9 million in Other Operation expense mainly due to $13 million of severance expenses related to the SEI initiative, a reduction in gains recorded on the dispositions of S02 emission allowances and increased insurance premiums and other employee benefit costs.* An increase of $9 million in Depreciation and Amortization due to increased amortization for the net generation-related regulatory assets related to our WVest Virginia jurisdiction which %vere assigned to the distribution portion of our business and are being recovered through regulated rates.* An increase of $18 million in Income Taxes due to an increase in pre-tax income.Other Inmpacts on Earnings Nonoperating income decreased

$20 million for 2002, primarily due to a decrease in gains from risk management activities driven by a decline in market prices. Nonoperating Expenses decreased $30 million due to decreased incentives related to risk management activities. Financial Condition Credit Ratings The rating agencies currently have us on stable outlook. Current ratings are as follows: Moody's S&P Fitch First Mortgage Bonds Baal BBB A-Senior Unsecured Debt Baa2 BBB BBB+In February 2003, Moody's Investors Service (Moody's) completed their review of AEP and its rated subsidiaries. The results of that review included a downgrade of our rating for unsecured debt from Baal to Baa2 and a downgrade of secured ratings from A3 to Baal. The completion of this review -was a culmination of ratings action started during 2002.In March 2003, S&P lowered AEP and its subsidiaries senior unsecured ratings from BBB+ to BBB along with the first mortgage bonds of AEP subsidiaries. Cash Flow Cash flows for 2003, 2002 and 2001 were as follows: 2003 2002 2001 (in thousands) Cash and cash equivalents at beginning of period $4.285 $13.663 $5.847 Cash flow from (used for): Operating activities 461,276 280,709 393,854 Investing activities (286,608) (275,475) (313,298)Financing activities (133,072) (14.612) (72.740)Net increase (decrease) in cash and cash equivalents 41.596 (9.378) 7.816 Cash and cash equivalents at end of period _S_45.8 &L _$ 6 63L Operating Activities Cash flow from operating activities in 2003 increased $181 million over the prior year primarily due to decreases in various accounts receivable balances in 2003 and changes in Federal and state income tax accruals.E-4 Investing Activities Construction expenditures in 2003 versus 2002 increased $12 million. The current year expenditures of $289 million were focused primarily on projects to improve service reliability for transmission and distribution, as well as environmental upgrades.Financing Activities In 2003, we issued two series of Senior Unsecured Notes, each in the amount of $200 million which were used to call First Mortgage Bonds and Senior Unsecured Notes and fund maturities. Additionally, we incurred obligations of $188 million in Installment Purchase Contracts to redeem higher costing Installment Purchase Contracts. Summary Obligation Information Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2003: Payments Due by Period (in thousands) Contractual Cash Obligations Less Than I Vear 2-3 vears 4-5vears After5vears Total Long-term Debt Advances from Affiliates Preferred Stock Subject to Mandatory Redemption Capital Lease Obligations Unconditional Purchase Obligations (a)Noncancellable Operating Leases Total$161,008 82,994 11,735 311,826 5.998$53,6$677,521 $400,027 $625,525 $1,864,081 ---82,994 12,036 351,760 9,609$1,00.92 5,360 5,309 90,163 5,696$5-06.1,802 6.094$633.21 5,360 30,882 753,749 27,397$2.764.463 (a) Represents contractual obligations to purchase coal as fuel for electric generation along with related transportation of the fuel.Significant Factors See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-1 for additional discussion of factors relevant to us.Quantitative And Oualitative Disclosures About Risk Management Activities Market Risks Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effect on this specific registrant. E-5 MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.MTM Risk Management Contract Net Assets Year Ended December 31,2003 (in thousands) Domestic Power Beginning Balance December 31, 2002 $96,852 (Gain) Loss from Contracts Realized/Settled During the Period (a) (33,846)Fair Value of New Contracts When Entered Into During the Period (b)Net Option Premiums Paid/(Received) (c) 143 Change in Fair Value Due to Valuation Methodology Changes Effect of EITF 98-10 Rescission (d) (4,664)Changes in Fair Value of Risk Management Contracts (e) 9,305 Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (f) 276 Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges 68,066 Net Cash Flow Hedge Contracts (g) 553 DETM Assignment (h) (32.287)Ending Balance December 31, 2003 $36,32 (a) "(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003.(b) The "Fair Value of New Contracts \When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location.(c) "Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003.(d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes." (e) "Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.(f) "Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Operations. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.(g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in Accumulated Other Comprehensive Income (Loss).(h) See Note 17 "Related Party Transactions." Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.E-6 Maturity and Source of Fair Value of AMi Risk Management Contract Net Assets Fair Value of Contracts as of December 31,2003 After 2004 2005 2006 2007 2008 2008 Total (c)(in thousands)

Prices Actively Quoted -Exchange Traded Contracts $1,219 $(245) $29 $191 $- $- $1,194 Prices Provided by Other External Sources-OTC Broker Quotes (a) 23,753 8,514 8,350 3,395 1,703 -45,715 Prices Based on Models and Other Valuation Methods (b) (7) 36 3,313 3,829 3,521 10.465 21,157 Total .$2A_,6 $8.5 $1L6 $,15 $5.224 $1QA $68.Q0 (a) "Prices Provided by Other External Sources -OTC Broker Quotes" reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.(b) "Prices Based on Models and Other Valuation Methods" is in absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the Modeled category varies by market.(c) Amounts exclude Cash Flow Hedges.Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. (However, given that under SFAS 133 only cash flow hedges are recorded in AOCI, the table does not provide an all-encompassing picture of our hedging activity). The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll-off of hedges). In accordance with GAAP, all amounts are presented net of related income taxes.Total Accumulated Other Comprehensive Income (Loss) Activity Year Ended December 31, 2003 Domestic Foreign Power Currency Interest Rate Consolidated (in thousands) Beginning Balance December 31,2002 $(394) $(190) $(1,336) $(1,920)Changes in Fair Value (a) 272 -(720) (448)Reclassifications from AOCI to Net Income (b) 481 7 311 799 Ending Balance December 31,2003 _$352 .$ L $(1LlU $(1.59 (a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes.(b) "Reclassifications from AOCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above.The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a$1,325 thousand gain.E-7 Credit Risk Our counterparty credit quality and exposure is generally consistent with that of AEP.VaR Associated ivith Risk Management Contracts The following table shows the end, high, average, and low market risk as measured by VaR year-to-date: December 31,2003 (in thousands) End High Average Low$596 $2,314 $969 $230 December 31, 2002 (in thousands) End H1ih Average Low$1,289 $3,948 $1,412 $286 VaR Associated iwith Debt Outstanding The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $102 million and $87 million at December 31, 2003 and 2002, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.E-8 APPALACIUAN PONVER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31,2003, 2002 and 2001 2003 OPERATING REVENUES Electric Generation, Transmission and Distribution Sales to AEP Affiliates TOTAL 2002 (in thousands) $1,627,993 186.477 1.814.470 2001$1,612,974 171.285 1.784.259$1,734,565

222,793 1.957.358 OPERATING EXPENSES Fuel for Electric Generation Purchased Electricity for Resale Purchased Electricity from AEP Affiliates Other Operation Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Income Taxes TOTAL 454,901 66,084 351,210 245,308 135,596 175,772 90,087 119.589 1,638,547 430,963 57,091 234,597 269,426 122,209 189,335 95,249 113.537 1.512.407 351,557 42,092 346,878 260,518 132,373 180,393 99,878 95.584 1.509.273 OPERATING INCOME 318,811 302,063 274,986 Nonoperating Income (Expense)Nonoperating Expenses Nonoperating Income Tax Expense (Credit)Interest Charges (5,661)9,534 (14,369)115.202 30,020 12,525 (2,611)116.677 50,268 42,261 1,139 120.036 Income Before Cumulative Effect of Accounting Changes Cumulative Effect of Accounting Changes (Net of Tax)202,783 77.257 205,492 161,818 NET INCOME 280,040 205,492 161,818 Preferred Stock Dividend Requirements (Including Capital Stock Expense)3.495 2.898 2.011 EARNINGS APPLICABLE TO COM1ON STOCK The common stock of APCo is wholly-owned byAEP.See Notes to Respective Financial Statements beginning on,$276,545 -$2D2,59I

_$__SM80 E-9 APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME For the Years Ended December 31,2003,2002 and 2001 (in thousands) Common Stock Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Total$- $1,096,260 DECEMBER 31,2000$260,458 $715,218 $120,584 Common Stock Dividends Preferred Stock Dividends Capital Stock Expense TOTAL (129,594)(1,443)(568)(129,594)(1,443)568 COMPREHENSIVE INCOME Other Comprehensive Income (Loss), Net of Taxes: Unrealized Loss on Cash Flow Hedges NET INCOME TOTAL COMPREHENSIVE INCOME (340)161,818 (340)161.818 161,478 DECEMBER 31,2001$260,458 $715,786 $150,797$(340) $1,126,701 Common Stock Dividends Preferred Stock Dividends Capital Stock Expense TOTAL (92,952)(1,442)(1,456)(92,952)(1,442)1.032.307 1,456 COMPREHENSIVE INCOME Other Comprehensive Income (Loss), Net of Taxes: Unrealized Loss on Cash Flow Hedges Minimum Pension Liability NET INCOME TOTAL COMPREHENSIVE INCOME 205,492 (1,580) (1,580)(70,162) (70,162)205.492 133.750$(72,082) $1,166,057 DECEMBER 31,2002$260,458 $717,242 $260,439 Common Stock Dividends Preferred Stock Dividends Capital Stock Expense SFAS 71 Reapplication TOTAL (128,266)(1,001)(2,494)2,494 163 (128,266)(1,001)163 1.036.953 COMPREHENSIVE INCOME Other Comprehensive Income, Net of Taxes: Unrealized Gain on Cash Flow Hedges Minimum Pension Liability NET INCOME TOTAL COMPREHENSIVE INCOME 351 19,643 351 19,643 280.040 300.034 280,040 DECEMBER 31,2003 S2 , -719899 See Notes to Respective Financial Statements beginning on page L-1.Q$408,IL E-1 0 APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS December 31,2003 and 2002 2003 2002 (in thousands) ELECTRIC UTILITY PLANT Production Transmission Distribution General Construction Work in Progress TOTAL Accumulated Depreciation and Amortization TOTAL -NET$2,287,043 1,240,889 2,006,329 294,786 311,884 6,140,931 2.321.360 3,819,571$2,245,945 1,218,108 1,951,804 272,901 206.545 5,895,303 2.330,012 3.565,291 OTHER PROPERTY AND INVESTMENTS Non-Utility Property, Net Other Investments TOTAL 20,574 26.668 47,242 20,550 34,103 54.653 CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable: Customers Affiliated Companies Accrued Unbilled Revenues Miscellaneous Allowance for Uncollectible Accounts Fuel Inventory Materials and Supplies Risk Management Assets Margin Deposits Prepayments and Other TOTAL 45,881 4,285 133,717 137,281 35,020 3,961 (2,085)42,806 71,978 71,189 11,525 13.301 564.574 155,521 122,665 30,948 5,374 (13,439)53,646 59,886 94,010 1,238 12.386 526.520 DEFERRED DEBITS AND OTHER ASSETS Regulatory Assets: Transition Regulatory Assets SFAS 109 Regulatory Asset, Net Unamortized Loss on Reacquired Debt Other Regulatory Assets Long-term Risk Management Assets Deferred Property Taxes Other Deferred Charges TOTAL 30,855 325,889 19,005 41,447 70,900 35,343 22.185 545.624 158,708 209,884 9,147 17,814 115,748 35,323 29.354 575.978.$4.722-42. TOTAL ASSETS__$4X2QJL See Notes to Respective Financial Statements beginning on page L-1.E-1 I APPALAChIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES December31, 2003 and 2002 2003 2002 (in thousands) CAPITALIZATION Common Shareholder's Equity: 'Common Stock -No Par Value: Authorized -30,000,000 Shares Outstanding-13,499,500 Shares Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total Common Shareholder's Equity Cumulative Preferred Stock Not Subject to Mandatory Redemption Total Shareholder's Equity Liability for Cumulative Preferred Stock Subject to Mandatory Redemption Long-term Debt TOTAL CURRENT LIABILITIES Long-term Debt Due Within One Year Advances from Affiliates Accounts Payable: General Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued Risk Management Liabilities Obligations Under Capital Leases Other TOTAL$260,458 719,899 408,718 (52,088 1,336,987 17.784 1,354,771 5,360 1.703.073 3.063.204 161,008 82,994 140,497 81,812 33,930 50,259 22,113 51,430 9,218 60.289 693.550$260,458 717,242 260,439 (72.082)1,166,057 17,790 1,183,847 10,860 1.738.854 2,933.561 155,007 39,205 141,546 98,374 26,186 29,181 22,437 69,001 9,598 70.234 660.769 DEFERRED CREDITS AND OTHER LIABILITIES Deferred Income Taxes Regulatory Liabilities: Asset Removal Costs Deferred Investment Tax Credits WV Rate Stabilization Deferral Over Recovery of Fuel Cost Other Regulatory Liabilities Long-term Risk Management Liabilities Obligations Under Capital Leases Asset Retirement Obligation Deferred Credits and Other TOTAL 803,355 92,497 30,545 68,704 17,326 54,327 16,134 21,776 115.593 1,220.257 701,801 33,691 75,601 72 44,517 23,991 248.439 1.128.112 Commitments and Contingencies (Note 7)TOTAL CAPITALIZATION AND LIABILITIES $4,977, A$AX22442-See Notes to Respective Financial Statements beginning on page L-J.E-12 APPALACHIAN PONVER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31,2003,2002 and 2001 2003 OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities: Cumulative Effect of Accounting Changes Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax Credits Deferred Power Supply Costs, Net Mark to Market of Risk Management Contracts Changes in Certain Assets and Liabilities: Accounts Receivable, Net Fuel, Materials and Supplies Accounts Payable Taxes Accrued Incentive Plan Accrued Rate Stabilization Deferral Change in Operating Reserves Change in Other Assets Change in Other Liabilities Net Cash Flows From Operating Activities $280,040 (77,257)175,772 24,563 (3,146)74,071 56,409 (6,825)(1,252)(17,611)21,078 (7,210)(75,601)(46,984)(17,813)83,042 461 276 2002 (in thousands) $205,492 189,335 16,777 (4,637)6,365 (21,151)(83,453)3,016 27,805 (26,402)(858)(3,190)(43,338)14948 280,709 2001$161,818 180,505 42,498 (4,765)1,411 (68,254)169,691 (19,957)(45,073)(7,675)(2,451)(5,358)19,418 (273954)393,854 INVESTING ACTIVITIES Construction Expenditures Proceeds from Sale of Property and Other Net Cash Flows Used For Investing Activities (288,577)1,969 (286,608)(276,549)1,074 (275.475)(306,046)(7,252)(313,298)FINANCING ACTIVITIES Issuance of Long-term Debt Retirement of Long-term Debt Retirement of Preferred Stock Change in Short-term Debt (net)Change in Advances from Affiliates, Net Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net Cash Flows Used For Financing Activities Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period 580,649 (622,737)(5,506)43,789 (128,266)(1,001)(133.072)41,596 4,285-$45,88 647,401 (315,007)(252,612)(92,952)(1,442)(14.612)(9,378)13,663$_285 124,588 (175,000)(191,495)300,204 (129,594)1.443!(72.740!7,816 5,847.iS16 SUPPLEMENTAL DISCLOSURE: Cash paid for interest net of capitalized amounts was $108,045,000, $111,528,000 and $117,283,000 and for income taxes was $62,673,000, $125,120,000 and $56,981,000 in 2003, 2002 and 2001, respectively. See Notes to Respective Financial Statements beginning on page L-1.E-13 APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31,2003 and 2002 2003 2002 (in thousands) COMMON SHAREHOLDER'S EQUITY$1.336.987 $1.166,057 PREFERRED STOCK: No Par Value -Authorized 8,000,000 shares Call Price December 31, Series 2003 (a)Shares Number of Shares Redeemed Outstanding Year Ended December31, December31.2003 2003 2002 2001 Not Subject to Mandatory Redemption -$100 Par: 4-1/2% $110 60 6 -177,839 17.784 17,790 Subject to Mandatory Redemption -$100 Par(b): 5.90% (c)5.92% (c)Total 25,000 30,000 22,100 31,500 LONG-TERM DEBT (See Schedule of Long-tenn Debt): First Mortgage Bonds Installment Purchase Contracts Senior Unsecured Notes Other Long-term Debt Less Portion Due Within One Year 2,210 3,150 5.360 340,269 276,477 1,244,813 2,522 (161,008)4,710 6.150 10.860 489,697 235,027 1,166,609 2,528 (155.007)1.738,854 Long-term Debt Excluding Portion Due Within One Year 1.703.073 TOTAL CAPITALIZATION $306204 (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends. The involuntary liquidation preference is $100 per share. The aggregate involuntary liquidation price for all shares of cumulative preferred stock may not exceed $300 million. The unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance.(b) The sinking fund provisions of each series subject to mandatory redemption have been met by shares purchased in advance of the due date.(c) Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per share 25,000 shares of the 5.90%series and 30,000 shares of the 5.92% series outstanding under sinking fund provisions at its option and all outstanding shares must be redeemed in 2008. Shares previously redeemed may be applied to meet the sinking fund requirement. See Notes to Respective Financial Statements beginning on page L-J.E-14 APPALACHIAN POWER COMPANY AND SUBSIDIARIES SCHEDULE OF LONG-TERM DEBT December 31, 2003 and 2002 First Mortgage Bonds outstanding were as follows:% Rate Due 6.00 2003 -November 1 7.70 2004 -September 1 7.85 2004 -November 1 8.00 2005 -May I 6.89 2005 -June 22 6.80 2006-March 1 8.50 2022-December 1 7.80 2023 -May 1 7.15 2023 -November 1 7.125 2024-May 1 8.00 2025-June 1 Unamortized Discount Total 2003 2002 (in thousands) $- $30,000 21,000 21,000 50,000 50,000 50,000 50,000 30,000 30,000 100,000 100,000-70,000-30,237-20,000 45,000 45,000 45,000 45,000 (731) (1.540)$3M2O $A96 First Mortgage Bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment Purchase Contracts have been entered into, in revenue bonds, by governmental authorities as follows:% Rate Due Industrial Development Authority of Russell County, Virginia: 7.70 2007 -November 1 (a) 2007 -November 1 5.00 2021 -November 1 connection with the issuance of pollution control 2003 2002 (in thousands) 17,500 19,500$17,500 19,500 Putnam County, WVest Virginia: (b)6.60 5.45 (c)2019 -June 1 2019-July 1 2019 -June 1 2019-May I Mason County, WVest Virginia: 7-7/8 2013 -November 1 6.85 2022 -June 1 6.60

2022- October 1 6.05 2024 -December 1 5.50 2022 -October I Unamortized Discount Total 40,000 40,000 30,000 30,000 100,000 (523)$2_76A1T 30,000 40,000 10,000 40,000 50,000 30,000 (1,973)$2352I E-15 (a) Rate is an annual long-term fixed rate of 2.70% through November 1, 2006. After that date the rate may be daily, wveekly, commercial paper, auction or other long-term rate as designated by APCo (fixed rate bonds).(b) In December 2003 an auction rate was established.

Auction rates are determined by standard procedures every 35 days. The rate on December 31, 2003 was 1.10%. The proceeds from the issuance were used to redeem the 5.45%Putnam County Installment Purchase Contracts on January 12, 2004.(c) Rate is an annual long-term fixed rate of 2.80% through November 1, 2006. After that date the rate may be daily, weekly, commercial paper, auction or other long-term rate as designated by APCo (fixed rate bonds).Under the terms of the installment purchase contracts, APCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.Senior Unsecured Notes outstanding were as follows:% Rate Due (a) 2003 -August 20 7.45 2004 -November 1 4.80 2005 -June 15 4.32 2007-November 12 3.60 2008-May 15 6.60 2009-May 1 5.95 2033 -May 15 7.20 2038 -March 31 7.30 2038-June 30 Unamortized Discount Total 2003 2002 (in thousands) $- $125,000 50,000 50,000 450,000 450,000 200,000 200,000 200,000 150,000 150,000 200,000 --100,000-100,000 (5.187) (8.391)$L244.SI $SLM6.(a) A floating interest rate was determined monthly. The rate on December 31, 2002 was 2.167%.At December 31, 2003, future annual long-terrn debt payments are as follows: 2004 2005 2006 2007 2008 Later Years Total Principal Amount Unamortized Discount Total Amount (in thousands) $161,008 530,010 147,511 200,013 200,014 631,966 1,870,522 (6.441)$184.8 E-16 APPALACHIAN POWER COMPANY AND SUBSIDIARIES INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to APCo's consolidated financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to APCo. The footnotes begin on page L-l.Footnote Reference Organization and Summary of Significant Accounting Policies Note I New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes Note 2 Rate Matters Note 4 Effects of Regulation Note 5 Customer Choice and Industry Restructuring Note 6 Commitments and Contingencies Note 7 Guarantees Note 8 Sustained Earnings Improvement Initiative Note 9 Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used Note 10 Benefit Plans Note 11 Business Segments Note 12 Derivatives, Hedging and Financial Instruments Note 13 Income Taxes Note 14 Leases Note 15 Financing Activities Note 16 Related Party Transactions Note 17 Unaudited Quarterly Financial Information Note 19 E-17 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Appalachian Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Appalachian Power Company and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, changes in common shareholder's equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as wvell as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Appalachian Power Company and subsidiaries as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.As discussed in Note 2 to the consolidated financial statements, the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations" and EITF 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," effective January 1, 2003.Is/ Deloitte & Touche LLP Columbus, Ohio March 5, 2004 E-1 8 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES SELECTED CONSOLIDATED FINANCIAL DATA 2003 2002 2001 (in thousands) 2000 1999 INCOME STATEMENTS DATA Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Income Before Extraordinary Item and Cumulative Effect Extraordinary Loss (Net of Tax)Cumulative Effect of Accounting Changes (Net of Tax)Net Income Preferred Stock Dividend Requirements (including Capital Stock Expense)Earnings Applicable to Common Stock$1,431,851 1.206.365 225,486 (1,391)50.948 173,147 27.283 200,430 1.016 S1,400,160 1,180.381 219,779 15,263 53.869 181,173 181,173$1,350,319 1.098.142 252,177 7,738 68.015 191,900 (30,024)161,876$1,304,409 1.108,532 195,877 5,153 80.828 120,202 (25,236)94,966$1,190,997 968,207 222,790 2,709 75,229 150,270 150,270 2.131 1.365.$!9.9.414 $LoJ2 BALANCE SHEETS DATA Electric Utility Plant Accumulated Depreciation Net Electric Utility Plant$3,570,443 1.389.586_S21 L$3,467,626 1.369.153 AQ2,0W i$3,354,320 1.283.712_$2,1,6$3,266,794 1.211.728__s0 6$3,151,619 1,129.007_2.&22.6AZ TOTAL ASSETS Common Stock and Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total Common Shareholder's Equity 5_3,95,460 _$2P8iQ=$613,899 246,584$617,426 326,782 (46.327)$616,410 290,611$615,395 176,103$614,380 99,069 (59.357)_$7198 $713,492 Cumulative Preferred Stock -Subject to Mandatory Redemption (a)$~10.000 Long-term Debt (a)_$899615 Obligations Under Capital Leases (a)_$2.i2 TOTAL CAPITALIZATION AND LIABILITIES S$2I4J=.S2.8M0.61Q (a) Including portion due within one year.F-1 COLUMBUS SOUTHERN POWER COMNIPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS CSPCo is a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 698,000 retail customers in central and southern Ohio. As a member of the AEP Power Pool, we share the revenues and the costs of the AEP Power Pool's sales to neighboring utilities and power marketers. The cost of the AEP Power Pool's generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member's prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs.The result of this calculation is the member load ratio (MLR), which determines each member's percentage share of revenues and costs.Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other AEP registrant subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas.The electricity and gas contracts include physical transactions, over-the-counter options and swaps and exchange traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts. Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and West companies' allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and West companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism wvas triggered in June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and WVest companies, respectively, for the remainder of 2003.Results of Operations 2003 Compared to 2002 The increase in Net Income of $19 million in 2003 compared to 2002 was primarily due to a $32 million increase in operating revenues, a $37 million decrease in income taxes (includes Operating Income Taxes and Nonoperating Income Tax Expense) and a $27 million net-of-tax Cumulative Effect of Accounting Changes, which were partially offset by a $48 million increase in fuel and purchased power expenses and a $34 million decrease in results from risk management activities. Operating Income Operating Income increased $6 million primarily due to:* An increase of $27 million in Sales to AEP Affiliates and an increase of $34 million of wholesale sales to non-affiliates due primarily to an increase in sales of MWSH.* A decrease in Other Operation expense of $19 million primarily due to decreases in factored receivables expenses, AEP transmission equalization expenses and personal injuries and property damage expenses.Administrative and general salaries also decreased due to the impact of cost reduction efforts instituted in the fourth quarter of 2002 and related employment termination benefits recorded in 2002.* Income Taxes decreased by $20 million primarily due to state income tax return and accrual adjustments. F-2 The increase in Operating Income xvas partially offset by:* A decrease of $34 million in retail revenues resulting from milder spring and summer weather and a sluggish economy. A decrease of 42% in cooling degree days from the prior year was partially offset by a 7% increase in heating degree days.* An increase of$18 million in fuel expense due to a 3% increase in coal costs and a 6% increase in MWVH of powver generation.

An increase of $27 million in Purchased Electricity from AEP Affiliates to support wholesale sales to non-affiliated entities.* An increase of $15 million in Maintenance expense due primarily to boiler overhaul work from scheduled and forced outages and increased maintenance of overhead lines resulting from severe storm damage.Other Impacts on Earnings Nonoperating Income decreased

$36 million primarily due to lower profit from power sold outside AEP's traditional marketing area resulting from AEP's plan to exit risk management activities in areas outside of its traditional market area.Nonoperating Income Tax Credit increased due to a decrease in pre-tax nonoperating book income and changes related to consolidated tax savings.Cumnlalive Effect ofAccounting Changes The Cumulative Effect of Accounting Changes is due to the one-time, after-tax impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see Note 2).Financial Condition Credit Ratings The rating agencies currently have us on stable outlook. Current ratings are as follows: Moody's S&P Fitch First Mortgage Bonds A3 BBB A Senior Unsecured Debt A3 BBB A-In February 2003, Moody's Investors Service (Moody's) completed their review of AEP and its rated subsidiaries. The completion of this review was a culmination of ratings action started during 2002. In March 2003, S&P lowered AEP and its subsidiaries senior unsecured ratings from BBB+ to BBB along with the first mortgage bonds of AEP subsidiaries. F-3 Surmmarn Obligation Information Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2003: Payments Due by Period (in thousands) 2-3 vears 45 years After 5 years Contractual Cash Oblinations Less Than 1 year Total Long-term Debt Advances from Affiliates Capital Lease Obligations Unconditional Purchase Obligations (a)Noncancellable Operating Leases Total$11,000 6,517 4,959 81,500 5,078$36,000 $112,000 6,701 9,854 7.438 3,823 3.814..1&14.$738,564 $897,564-6,517 2,096 17,579 2,726 M1.8 91,354 19.056$-L0mQ (a) Represents contractual obligations to purchase coal as fuel for electric generation along with related transportation of the fuel.Significant Factors See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-1 for additional discussion of factors relevant to us.Quantitative And Qualitative Disclosures About Risk Mananement Activities Market Risks Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effect on this specific registrant. F-4 TMI Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.MTM Risk Management Contract Net Assets Year Ended December 31,2003 (in thousands) Domestic Power Beginning Balance December 31,2002 $65,117 (Gain) Loss from Contracts Realized/Settled During the Period (a) (23,010)Fair Value of New Contracts When Entered Into During the Period (b)Net Option Premiums Paid/(Received) (c) 81 Change in Fair Value Due to Valuation Methodology Changes Effect of EITF 98-10 Rescission (d) (3,135)Changes in Fair Value of Risk Management Contracts (e) (716)Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (f)Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges 38,337 Net Cash Flow Hedge Contracts (g) 311 DETM Assignment (h) (18.185)Ending Balance December 31, 2003 $(a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003.(b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location.(c)"Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003.(d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes." (e)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.(f)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.(g)"Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in Accumulated Other Comprehensive Income (Loss).(h)See Note 17 "Related Party Transactions." F-5 Maturity and Source of Fair Value of AMTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
The maturity, by year, of our net assetsAiabilities, giving an indication of when these MTM amounts will settle and generate cash.Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets Fair Value of Contracts as of December 31,2003 After 2004 2005 2006 2007 2008 2008 Total (c)(in thousands)

Prices Actively Quoted -Exchange Traded Contracts $687 $(138) $16 $108 $- $- $673 Prices Provided by Other External Sources -OTC Broker Quotes (a) 13,378 4,795 4,703 1,911 959 -25,746 Prices Based on Models and Other Valuation Methods (b) (3) 20 1.866 2.157 1,984 5,894 11.918 Total $14.062 $4.677 $6,585 2 X,943 $4B.33L (a) "Prices Provided by Other External Sources -OTC Broker Quotes" reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.(b) "Prices Based on Models and Other Valuation Methods" if there is absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the Modeled category varies by market.(c) Amounts exclude Cash Flow Hedges.F-6 Cash flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. (However, given that under SFAS 133 only cash flow hedges are recorded in AOCI, the table does not provide an all-encompassing picture of our hedging activity). The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll-off of hedges). In accordance with GAAP, all amounts are presented net of related income taxes.Total Accumulated Other Comprehensive Income (Loss) Activity Year Ended December 31, 2003 Domestic Power (in thousands) Beginning Balance December 31, 2002 $(267)Changes in Fair Value (a) 194 Reclassifications from AOCI to Net Income (b) 275 Ending Balance December 31, 2003 $ 202 (a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes.(b) "Reclassifications from AOCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above.The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a$940 thousand gain.Credit Risk Our counterparty credit quality and exposure is generally consistent with that of AEP.VaR Associated with Energy and Gas Risk Management Contracts The following table shows the end, high, average, and low market risk as measured by VaR for year-to-date: December 31, 2003 December 31, 2002 (in thousands) (in thousands) End High Average Low End High Average Low$336 $1,303 $546 $130 $867 $2,654 $949 $192 VaR Associated with Debt Outstanding The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $98 million and $33 million at December 31, 2003 and 2002, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.F-7 COLUMBUS SOUITHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31,2003,2002 and 2001 2003 OPERATING REVENUES Electric Generation, Transmission and Distribution Sales to AEP Affiliates TOTAL OPERATING EXPENSES Fuel for Electric Generation Purchased Electricity for Resale Purchased Electricity from AEP Affiliates Other Operation Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Income Taxes TOTAL$1,347,482 84.369 1.431.851 203,399 17,730 337,323 218,466 75,319 135,964 133,754 84,410 1.206.365 2002 (in thousands) $1,342,958 57.202 1.400.160 185,086 15,023 310,605 237,802 60,003 131,624 136,024 104,214 1.180.381 2001$1,282,808 67.511 1.350,319 175,153 10,957 292,199 219,497 62,454 127,364 111,481 99,037 1.098.142 OPERATING INCOME 225,486 219,779 252,177 Nonoperating Income (Loss)Nonoperating Expenses Nonoperating Income Tax Expense (Credit)Interest Charges (7,489)4,650 (10,748)50.948 28,280 6,228 6,789 53.869 34,656 22,995 3,923 68.015 Income Before Extraordinary Item and Cumulative Effect of Accounting Changes Extraordinary Loss -Discontinuance of Regulatory Accounting for Generation -Net of Tax (Note 2)Cumulative Effect of Accounting Changes (Net of Tax)NET INCOME 173,147 181,173 191,900 (30,024)200,430 181,173 161,876 Preferred Stock Dividend Requirements (Including Capital Stock Expense)1.365 EARNINGS APPLICABLE TO COMMON STOCK J122AU1-$1722.8 The common stock of CSPCo is wholly-owned byAEP.See Notes to Respective Financial Statements beginning on Page L-1.F-8 COLUMBUS SOU8THERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME For the Years Ended December 31,2003,2002 and 2001 (in thousands) Common Stock Paid-in Capital Retained Earninos Accumulated Other Comprehensive Income (Loss)Total DECEMBER 31,2000$41,026 $573,354$99,069$- $713,449 Common Stock Dividends Declared Preferred Stock Dividends Declared Capital Stock Expense TOTAL (82,952)(875)(1,015)(82,952)(875)629,622 1,015 COMPREHENSIVE INCOME NET INCOME TOTAL COMPREHENSIVE INCOME 161,876 161.876 161.876 DECEMBER 31,2001$41,026 $574,369$176,103$- $791,498 Common Stock Dividends Declared Preferred Stock Dividends Declared Capital Stock Expense TOTAL (65,300)(350)(1,015)1,015 COMPREHNSIVE INCOME Other Comprehensive Income, Net of Taxes: Unrealized Loss on Cash Flow Power Hedges Minimum Pension Liability NET INCOME TOTAL COMPREHENSIVE INCOME (65,300)(350)725.848 (267) (267)(59,090) (59,090)181.173 121,816 181,173 DECEMBER 31,2002$41,026 $575,384$290,611$(59,357) $847,664 Common Stock Dividends Declared Capital Stock Expense TOTAL (163,243)(1,016)1,016 (163,243)684.421 COMPREHENSIVE INCOME Other Comprehensive Income, Net of Taxes: Unrealized Gain on Cash Flow Power Hedges Minimum Pension Liability NET INCOME TOTAL COMPREHENSIVE INCOME 469 12,561 469 12,561 200,430 213.460 200,430 DECEMBER 31,2003 AL9 $$576,AQQ -6 ,32-6 See Notes to Respective Financial Statements beginning on page L-l.F-9 COLUMBUS SOUTHERN POWVER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS December 31,2003 and 2002 2003 2002 (in thousands) ELECTRIC UTILITY PLANT Production Transmission Distribution General Construction Work in Progress TOTAL$1,610,888 425,512 1,253,760 166,002 114.281 3,570,443 1.389.586 2.180.857$1,582,627 413,286 1,208,255 165,025 98.433 3,467,626 1.369.153 2.098,473 Accumulated Depreciation and Amortization TOTAL -NET OTHER PROPERTY AND INVESTMENTS Non-Utility Property, Net Other Investments TOTAL 22,417 8.663 31.080 23,680 12.079 35.759 CURRENT ASSETS Cash and Cash Equivalents Advances to Affiliates, Net Accounts Receivable: Customers Affiliated Companies Accrued Unbilled Revenues Miscellaneous Allowance for Uncollectible Accounts Fuel Materials and Supplies Risk Management Assets Margin Deposits Prepayments and Other TOTAL 4,142 47,099 68,168 23,723 5,257 (531)14,365 44,377 40,095 6,636 12.444 265,775 1,479 31,257 70,704 54,518 12,671 867 (634)24,844 40,339 63,197 824 6.635 306,701 DEFERRED DEBITS AND OTHER ASSETS Regulatory Assets: SFAS 109 Regulatory Assets, Net Transition Regulatory Assets Unamortized Loss on Reacquired Debt Other Long-term Risk Management Assets Deferred Property Taxes Deferred Charges TOTAL 16,027 188,532 13,659 24,966 39,932 62,262 15.276 360,654 26,290 204,961 5,978 20,453 77,810 61,733 11.103 408,328 TOTAL ASSETS-S2. SA9 221 See Notes to Respective Financial Statements beginning on page L-J.F-1 0 COLUMBUS SOUTHERN POWvER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31,2003 and 2002 2003 2002 (in thousands) CAPITALIZATION Common Shareholder's Equity: Common Stock -No Par Value: Authorized -24,000,000 Shares Outstanding -16,410,426 Shares Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total Common Sharcholder's Equity Long-term Debt: Nonaffiliated Affiliated Total Long-term Debt TOTAL$41,026 576,400 326,782 (46.327)897,881 886,564 886.564 1.784.445$41,026 575,384 290,611 (59.357)847,664 418,626 160.000 578,626 1.426.290 CURRENT LIABILITIES Short-term Debt -Affiliates Long-term Debt Due Within One Year -Nonaffiliated Advances from Affiliates, Net Accounts Payable: General Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued Risk Management Liabilities Obligations Under Capital Leases Other TOTAL 11,000 6,517 58,220 53,572 19,727 132,853 16,528 28,966 4,221 25.364 356.968 290,000 43,000 89,736 81,599 14,719 112,172 9,798 46,375 5,967 16.104 709.470 DEFERRED CREDITS AND OTHER LIABILITIES Deferred Income Taxes Regulatory Liabilities: Asset Removal Costs Deferred Investment Tax Credits Long-term Risk Management Liabilities Obligations Under Capital Leases Asset Retirement Obligations Deferred Credits and Other TOTAL 458,498 99,1 19 30,797 30,598 11,397 8,740 57.804 696.953 437,771 33,907 29,926 21,643 190.254 713,501 Commitments and Contingencies (Note 7)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Respective Financial Statements beginning on page L-J.F-11 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31,2003,2002 and 2001 2003 OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities: Cumulative Effect of Accounting Changes Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax Credits Mark-to-Market of Risk Management Contracts Extraordinary Loss Changes in Certain Assets and Liabilities: Accounts Receivable, Net Fuel, Materials and Supplies Accounts Payable Taxes Accrued Interest Accrued Deferred Property Tax Change in Other Assets Change in Other Liabilities Net Cash Flows From Operating Activities $200,430 (27,283)135,964 (4,514)(3,110)41,830 (5,590)6,441 (59,543)20,681 6,730 (529)(20,563)(8,762)282.182 2002 (in thousands) $181,173 131,753 23,292 (3,269)(16,667)(9,576)(6,180)26,949 (4,192)(1,108)(13,732)5,705 (17,148)297,000 2001$161,876 128,500 24,108 (4,058)(44,680)30,024 22,538 (7,780)(16,249)(46,540)(2,462)22,920 (14)(34.739)233A444 INVESTING ACTIVITIES Construction Expenditures Proceeds from Sale of Property Net Cash Flows Used For Investing Activities FINANCING ACTIVITIES Issuance of Long-term Debt -Affiliated Issuance of Long-term Debt -Nonaffiliated Change in Advances to/from Affiliates, Net Retirement of Long-term Debt -Nonaffiliated Retirement of Long-term Debt -Affiliated Retirement of Cumulative Preferred Stock Change in Short-term Debt -Affiliates Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net Cash Flows Used For Financing Activities (136,291)1,644 (134.647)643,097 37,774 (212,500)(160,000)(290,000)(163,243)(144.872)(136,800)730 (136.070)160,000 (212,641)(133,343)(200,000)(10,000)290,000 (65,300)(525)(171,809)(132,532)10,841 (121.691)200,000 92,652 (314,733)(5,000)(82,952)(962)(110.995s Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period 2,663 1,479 (10,879)12.358$1,472 758 11,600$12.35 SUPPLEMENTAL DISCLOSURE: Cash paid for interest net of capitalized amounts was $42,601,000, $53,514,000 and $68,596,000 and for income taxes was $63,907,000, $117,591,000 and $80,485,000 in 2003, 2002 and 2001, respectively.. Non-cash acquisitions under capital leases wvas $1,019,000 in 2001. There wvere no nontcash capital lease acquisitions in 2003 or 2002.See Nlotes to Respective Financial Statements beginning on page L-J.F-12 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31,2003 and 2002 2003 2002 (in thousands) EIIOLDER'S EQUITY $897.881 $847j(COMMON SHARI 564 PREFERRED STOCK (a)LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Senior Unsecured Notes Notes -Affiliated Less Portion Due Within One Year 10,944 91,329 795,291 (11.000)222,797 91,275 147,554 160,000 (43.000)Total Long-term Debt Excluding Portion Due Within One Year 886.564 578,626 TOTAL CAPITALIZATION $1,784,4 ffi2Q (a) At December 31, 2003 and 2002 there wvere no shares outstanding, 2,500,000 authorized shares at $100 par value and 7,000,000 authorized shares at $25 par value.See Notes to Respective Financial Statements beginning on page L-J.F-13 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES SCHEDULE OF LONG-TERM DEBT December 31,2003 and 2002 First Mortgage Bonds outstanding were as follows:% Rate Due 6.80 2003 -May 1 6.60 2003 -August 1 6.10 2003 -November 1 6.55 2004 -March 1 6.75 2004 -May I 8.70 2022 -July 1 8.55 2022-August 1 8.40 2022 -August 15 8.40 2022 -October 15 7.90 2023 -May I 7.75 2023 -August 1 7.60 2024 -May I (a)Unamortized Discount Total 2003 11,000 (56'$10,944 2002 (in thousands) $13,000 25,000 5,000 26,500 26,000 2,000 15,000 14,000 13,000 40,000 33,000 11,000 L (703)L $222,12 (a) This bond will be redeemed in May 2004 and has been classified for payment in 2004.First Mortgage Bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Interest payments are made semi-annually. Installment Purchase Contracts have been entered into in connection with the issuance of pollution control revenue bonds by the Ohio Air Quality Development Authority: % Rate Due 6.3 75 2020 -December 1 6.25 2020 -December 1 Unamortized Discount Total 2003 2002 (in thousands) $48,550 $48,550 43,695 43,695 (916) (970)LM29. $21,275 Under the terms of the Installment Purchase Contracts, CSPCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at the Zimmer Plant. Interest payments are made semi-annually. Senior Unsecured Notes outstanding were as follows:% Rate Due 6.85 2005 -October 3 6.51 2008-February 1 6.55 2008 -June 26 4.40 2010-December 1 5.50 2013-March 1 6.60 2033-March 1 Unamortized Discount Total 2003 2002 (in thousands) $36,000 $36,000 52,000 52,000 60,000 60,000 150,000 -250,000 -250,000 -(2,709) (446)$7 9 $147,5 F-14 Notes Payable to parent company were as follows:% Rate Due 6.501% 2006-May 15 2003 2002 (in thousands) $-_ $10.Q0 At December 31,2003, future annual long-term debt payments are as follows: 2004 2005 2006 2007 2008 Later Years Total Principal Amount Unamortized Discount Total Amount (in thousands) $11,000 36,000 112,000 742.245 901,245 (3.681)$897564 F-1 5 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to CSPCo's consolidated financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to CSPCo. The footnotes begin on page L-l.Footnote Reference Organization and Summary of Significant Accounting Policies Note 1 New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes Note 2 Rate Matters Note 4 Effects of Regulation Note 5 Customer Choice and Industry Restructuring Note 6 Commitments and Contingencies Note 7 Guarantees Note 8 Sustained Earnings Improvement Initiative Note 9 Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used Note 10 Benefit Plans Note 11 Business Segments Note 12 Derivatives, Hedging and Financial Instruments Note 13 Income Taxes Note 14 Leases Note 15 Financing Activities Note 16 Related Party Transactions Note 17 Jointly Owned Electric Utility Plant Note 18 Unaudited Quarterly Financial Information Note 19 F-16 INDEPENDENT AUDITORS' REPORT To the Shareholder and Board of Directors of Columbus Southern Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Columbus Southern Power Company and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, changes in common shareholder's equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Columbus Southern Power Company and subsidiaries as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.As discussed in Note 2 to the consolidated financial statements, the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations" and EITF 02-3, "Issues Involved in Accounting for. Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," effective January 1, 2003./s/ Deloitte & Touche LLP Columbus, Ohio March 5, 2004 F-17 INDIANA MICHIGAN PONWER COMPANY AND SUBSIDIARIES INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES SELECTED CONSOLIDATED FINANCIAL DATA 2003 2002 INCOME STATEMENTS DATA Operating Revenues Operating Expenses Operating Income (Loss)Nonoperating Items, Net Interest Charges Net Income (Loss) Before Cumulative Effect of Accounting Change Cumulative Effect of Accounting Change (Net of Tax)Net Income (Loss)Preferred Stock Dividend Requirements (Including Capital Stock Expense)Earnings (Loss) Applicable to Common Stock$1,595,596 1,409.529 186,067 (13,465)83.054 89,548 (3.160)86,388$1,526,764 1.375.575 151,189 16,726 93,923 73,992 73,992 2001 (in thousands) $1,526,997 1,367.292 159,705 9,730 93,647 75,788 2000$1,488,209 1,522.911 (34,702)9,933 1073263 (132,032)1999$1,351,666 1,243.014 108,652 4,530 80,406 32,776 32,776 75,788 (132,032)-5-839 __$a239 $X,167_BALANCE SHEETS DATA Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant$5,306,182 $5,029,958 $4,923,721 2,490.912 2.318.063 2.198,524$2,81 S23n 7211,89i $212$4,871,473 2.057.542$S2.1,3$4,770,027 1.981,430$2597 TOTAL ASSETS$4,5907 $,87,32_S4.632.2$5.92LQ.8 $A,88.1 Common Stock and Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total Common Shareholder's Equity Cumulative Preferred Stock: Not Subject to Mandatory Redemption Subject to Mandatory Redemption (a)Total Cumulative Preferred Stock$915,278 187,875 (25.106)$107L9,4$8,101 63.445$7154$915,144 143,996 (40.487)$1.08,$8,101 64.945$789,800 74,605 (3,835)$8,736 64.945$789,656 3,443$789,323 166,389$23,099.$8,736 64.945$9,248 64.945$74,193 Long-term Debt (a)Sly 1,61,06 Obligations Under Capital Leases (a).$Th~4 _ $S.84&$163,17 TOTAL CAPITALIZATION AND LIABILITIES (a) Including portion due within one year.$4AL659 .0$AL6.51Q S48J1J2 G-1 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS We are a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 575,000 retail customers in our service territory in northern and eastern Indiana and a portion of southwestern Michigan. As a member of the AEP Power Pool, wve share the revenues and the costs of the AEP Power Pool's sales to neighboring utilities and powver marketers. We also sell power at wholesale to municipalities and electric cooperatives. The cost of the AEP Power Pool's generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member's prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs.The result of this calculation is the member load ratio (MLR), which determines each member's percentage share of revenues and costs.Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other AEP registrant subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas. The electricity and gas contracts include physical transactions, over-the-counter options and swaps and exchange traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts. Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. *This resulted in an AEP East and WVest companies' allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and \Vest companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and West companies, respectively, for the remainder of 2003.Results of Onerations During 2003, Net Income increased $12 million including an unfavorable $3 million Cumulative Effect of Accounting Change (see Note 2). During 2003, Net Income Before Cumulative Effect of Accounting Change increased $15 million due to reduced financing costs and an improvement in Operating Income resulting from higher margins on wholesale sales and lower Other Operation expense.During 2002, Net Income decreased by $2 million due to increased operations and maintenance costs incurred as part of planned and unplanned outages at Cook and Rockport plants.2003 Compared to 2002 Operating Income Operating Income increased $35 million primarily due to:* Increased wholesale sales of $69 million including system and power optimization sales, transmission revenues and risk management activities reflecting availability of AEP's generation and market conditions.

Increased Sales to AEP Affiliates of $35 million due to increased capacity revenue.* Decreased Other Operations expense of $45 million due primarily to the impact of cost reduction efforts instituted in the fourth quarter of 2002 and related employment termination benefits of $15 million recorded in 2002.G-2 The increase in Operating Income -*vas partially offset by:* Decreased retail revenues of $37 million due primarily to milder summer weather and economic pressures on industrial customers.

Cooling degree days declined approximately 42% this year compared with last year.Industrial revenues dropped 3% from prior year.* Increased Fuel for Electric Generation expense of $11 million reflecting an increase in the average cost of fuel and increased coal-fired generation in 2003 as Rockport's availability increased.

Increased Purchased Electricity from AEP Affiliates of $41 million due to purchasing more power from the AEP Power Pool to support wholesale sales to unaffiliated entities.* Increased Income Tax expense of $12 million reflecting an increase in pre-tax operating income partially offset by temporary differences accounted for on a flowv-through basis and tax return adjustments.

Other Impacts on Earnings Nonoperating Income decreased $30 million primarily due to lower margins for power sold outside of AEP's traditional market reflecting AEP's plan to exit those risk management activities. Nonoperating Expenses increased $16 million primarily due to a $10 million write-down of western coal lands (see Note 10).Nonoperating Income Taxes decreased $16 million reflecting the decrease in pre-tax nonoperating income.Interest Charges decreased $11 million primarily due to a reduction in outstanding long-term debt of $255 million which wvas retired in May 2003 using lower rate short-term debt.Cumulative Effect ofAccoaunting Change The Cumulative Effect of Accounting Change is due to the implementation of the requirements of EITF 02-3 (see Note 2).2002 Compared to 2001 Operating Income Operating Income decreased $9 million primarily due to:* Decreased Sales to AEP Affiliates of $41 million reflecting less energy to sell due to outages. In 2002, both units of Cook plant were shut down for refueling and both Rockport units were down for planned boiler maintenance.

Increased Other Operation expense of $14 million due to increased costs for pensions, insurance and other benefits.* Increased Maintenance expense of $24 million reflecting two nuclear refueling outages in 2002.The decrease in Operating Income was partially offset by:* Increased Retail revenues of $35 million reflecting a 4% increase in sales.* Decreased Fuel for Electric Generation expense of $11 million reflecting a decline in the average cost of fuel and decreased nuclear generation.
An $8 million decrease in Taxes Other Than Income Taxes reflects a favorable tax law change in Indiana effective March 2002.* Decreased Income Taxes of $15 million reflecting a decrease in pre-tax operating income.G-3 Other Impacts on Earnings Nonoperating Expenses decreased

$10 million due to a decrease in trading overheads and traders' incentive compensation. Financial Condition Credit Ratings The rating agencies currently have us on stable outlook. Current ratings are as follows: Moody's S&P Fitch First Mortgage Bonds Senior Unsecured Debt Baal Baa2 BBB BBB+BBB BBB During the first quarter of 2003, Moody's Investors Service (Moody's), Standard & Poors (S&P) and Fitch Rating Service completed their reviews of AEP and its rated subsidiaries. The reviews resulted in downgrades of debt ratings. The completion of these reviews was a culmination of ratings action started during 2002.Cash Flow Cash flows for 2003, 2002 and 2001 were as follows: 2003 2002 2001 (in thousands) Cash and cash equivalents at beginning of period Cash flow from (used for): Operating activities Investing activities Financing activities Net increase (decrease) in cash and cash equivalents Cash and cash equivalents at end of period$3.237 222,773 (182,703)(39.393)677__$3.1$16.804 228,234 (165,725)(76.076)(13.567)_-$1231-$14,835 236,207 (182,594)(51.644)1,969_$16.80 Operating Activities Operating activities during 2003 provided $5 million less cash than during 2002 which was $8 million less than during 2001 largely due to working capital requirements and changes in mark-to-market of risk management contracts. Investing Activities Cash flows used for investing activities during 2003 were $183 million compared to $166 million during 2002. The primary reason for the year-over-year variance was increased construction expenditures of $17 million. Construction expenditures increased $76 million comparing 2002 with 2001. In 2001, we bought out nuclear fuel leases using $93 million of operating cash. Construction expenditures for the nuclear plant and transmission and distribution assets are to upgrade or replace equipment and improve reliability. Financing Activities Financing activities for 2003 used $39 million of cash from operations primarily to pay common dividends. During 2003, we redeemed $285 million of long-term debt using short-term debt and refinanced $65 million of our installment purchase contracts at lower fixed rates until October 2006.G4 During 2002, we redeemed $340 millioh of long-term debt and $145 hillion of short-term debt using cash from operations, a $125 million capital contribution from our parent company and proceeds from the issuance of $300 million of long-termn debt.During 2001, we issued $300 million of long-term debt to reduce short-term debt.Financing Activity Long-term debt issuances and retirements during 2003 were: Issuances Principal Tvpe of Debt Amount (in millions)Installment Purchase Contracts $25 Installment Purchase Contracts 40 (a) Fixed Until October 1, 2006 Retirements Principal Type of Debt Amount (in millions)First Mortgage Bonds $30 First Mortgage Bonds 75 First Mortgage Bonds 15 Junior Debentures 40 Junior Debentures 125 Installment Purchase Contracts 25 Installment Purchase Contracts 40 Interest Rate (%/6)2.625(a)2.625(a)Interest Rate (%)6.10 8.50 7.35 8.00 7.60 7.00 7.60 Due Date 2019 2025 Due Date 2003 2022 2023 2026 2038 2015 2016 Off-Balance Sheet Arrangements

Ve enter into off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties. The following identifies significant off-balance sheet arrangements:

Rockport Plant Unit 2 AEGCo and I&M entered into a sale and leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated unconsolidated trustee for Rockport Plant Unit 2 (the plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and certain institutional investors. The future minimum lease payments for each respective company are $1.4 billion.The FASB and other accounting constituencies continue to interpret the application of FIN 46 (revised December 2003)(FIN 46R). As a result, we are continuing to review the application of this new interpretation as it relates to the Rockport Plant Unit 2 transaction. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the plant and leases it to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the lease footnote. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the plant.Neither AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and none of these entities guarantee its debt.G-5 Summary Obligation Information Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2003: Payments Due by Period (in millions)Contractual Cash Obligations Less Than 1 year 2-3 vears 45 vears After 5 years Total Long-term Debt Advances from Affiliates Preferred Stock Subject to Mandatory Redemption Capital Lease Obligations Unconditional Purchase Obligations (a)Noncancellable Operating Leases Total$205 99 10 107 104$525$365 14 89 191$X59$100 16 16 82 182$396$669 $1,339-99 47 6 161 1.097$1.98 63 46 439 1,574 Trio (a) Represents contractual obligations to purchase coal as fuel for electric generation along with related transportation of the fuel.Some of the transactions, described under "Off-Balance Sheet Arrangements" above, have been employed for a contractual cash obligation reported in the above table. The lease of Rockport Unit 2 is reported in Noncancellable Operating Leases.Significant Factors See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-1 for additional discussion of factors relevant to us.Quantitative And Qualitative Disclosures About Risk Management Activities Market Risks Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effect on this specific registrant. G-6 MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.MTM Risk Management Contract Net Assets Year Ended December 31,2003 (in thousands) Domestic Power Beginning Balance December 31,2002 $70,861 (Gain) Loss from Contracts Realized/Settled During the Period (a) (18,666)Fair Value of New Contracts When Entered Into During the Period (b)Net Option Premiums Paid/(Received) (c) 88 Change in Fair Value Due to Valuation Methodology Changes Effect of EITF 98-10 Rescission (d) (4,861)Changes in Fair Value of Risk Management Contracts (e) 765 Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (f) (6.192)Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges 41,995 Net Cash Flow Hedge Contracts (g) 341 DETM Assignment (h) (19,932)Ending Balance December 31,2003 $22.404 (a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003.(b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location.(c)"Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003.(d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes." (e)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.(f)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.(g)"Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in Accumulated Other Comprehensive Income (Loss).(h)See Note 17 "Related Party Transactions." Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

The source of fair value used in determining the carrying amount of our total MTM asset or liability (extemal sources or modeled internally).
The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.G-7 Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets Fair Value of Contracts as of December 31,2003 After 2004 2005 2006 2007 2008 2008 Total (c)(in thousands)

Prices Actively Quoted -Exchange Traded Contracts $753 $(151) $18 $118 $- $- $738 Prices Provided by Other External Sources-OTC Broker Quotes (a) 14,786 5,256 5,154 2,095 1,051 -28,342 Prices Based on Models and Other Valuation Methods (b) (151) 23 _2045 2.364 2.174 6,460 12,915 Total 15 $5J1 $L2I7 $4,577 $3,22 $G.6A $41.99 (a) "Prices Provided by Other External Sources" reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.(b) "Prices Based on Models and Other Valuation Methods" is in absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the Modeled category varies by market.(c) Amounts exclude Cash Flow Hedges.Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. (However, given that under SFAS 133 only cash flow hedges are recorded in AOCI, the table does not provide an all-encompassing picture of our hedging activity). The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll-off of hedges). In accordance with GAAP, all amounts are presented net of related income taxes.Total Accumulated Other Comprehensive Income (Loss) Activity Year Ended December 31,2003 Domestic Power (in thousands) Beginning Balance December 31,2002 $(286)Changes in Fair Value (a) 209 Reclassifications from AOCI to Net Income (b) 299 Ending Balance December 31,2003 -S (a)"Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes.(b) "Reclassifications from AOCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above.The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a$1,031 thousand gain.G-8 Credit Risk Our counterparty credit quality and exposure is generally consistent with that of AEP.VaR Associated Nwith Risk Management Contracts The following table shows the end, high, average, and low market risk as measured by VaR for year-to-date: December 31, 2003 (in thousands) End High Average Low$368 $1,429 $598 $142 December 31, 2002 (in thousands) End High Averape Low$927 $2,840 $1,016 $206 VaR Associated with Debt Outstanding The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $79 million and $85 million at December 31, 2003 and 2002, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.G-9 INDIANA MICHiGAN PONER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31,2003,2002 and 2001 2003 OPERATING REVENUES Electric Generation, Transmission and Distribution Sales to AEP Affiliates TOTAL$1,346,393 249.203 1.595.596 2002 (in thousands) $1,312,626 214.138 1.526.764 2001$1,271,958 255,039 1,526.997 OPERATING EXPENSES Fuel for Electric Generation Purchased Electricity for Resale Purchased Electricity from AEP Affiliates Other Operation Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Income Taxes TOTAL 250,890 28,327 274,400 417,636 158,281 171,281 57,788 50.926_1.409.529 239,455 23,443 233,724 462,707 151,602 168,070 57,721 38,853 1.375.575 250,098 18,707 238,237 449,115 127,263 164,230 65,518 54,124 1.367.292 OPERATING INCOME 186,067 151,189 159,705 Nonoperating Income Nonoperating Expenses Nonoperating Income Tax Expense (Credit)Interest Charges 53,928 77,171 (9,778)83.054 84,084 61,374 5,984 93.923 85,673 70,900 5,043 93,647 75,788 75,788 Net Income Before Cumulative Effcct of Accounting Change Cumulative Effect of Accounting Change (Net of Tax)89,548 73,992 (3.160) _ _ _NET INCOME 86,388 73,992 Preferred Stock Dividend Requirements (Including Capital Stock Expense)2.509 4.601 EARNINGS APPLICABLE TO COMISION STOCK S&The common stock ofI&M is wholly-owned by AEP See ANotes to Respective Financial Statements beginning on page L-1.$71,167 G-10 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME For the Years Ended December 31,2003,2002 and 2001 (in thousands) Common Paid-in Stock Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total DECEMBER 31,2000 Preferred Stock Dividends Capital Stock Expense COMPREHENSIVE INCOME Other Comprehensive Income, Net of Taxes: Cash Flow Interest Rate Hedge NET INCOME TOTAL COMPREHENSIVE INCOME$56,584 $733,072 144$3,443 (4,487)(139)$- $793,099 (4,487)5 788.617 (3,835) (3,835)75.788 71.953 75,788 DECEMBER 31,2001$56,584 $733,216$74,605$(3,835)$860,570 Capital Contributions from Parent Company Preferred Stock Dividends Capital Stock Expense I COMPREHENSIVE INCOME Other Comprehensive Income, Net of Taxes: Cash Flow Interest Rate Hedge Unrealized Loss on Cash Flow Power Hedges Minimum Pension Liability NET INCOME TOTAL COMPREHENSIVE INCOME 125,000 344 (4,467)(134)125,000 (4,467)210 981.313 3,835 3,835 (286) (286)(40,201) (40,201)73.992 37.340 73,992 DECEMBER 31,2002$56,584 $858,560 $143,996 $(40,487) $1,018,653 Common Stock Dividends Preferred Stock Dividends Capital Stock Expense (40,000)(2,375)(134)134 COMPREHENSIVE INCOME Other Comprehensive Income, Net of Taxes: Unrealized Gain on Cash Flow Power Hedges Minimum Pension Liability NET INCOME TOTAL COMPREHENSIVE INCOME (40,000)(2,375)976.278 508 508 14,873 14,873 86,388 101.769 86,388 DECEMBER 31,2003$56.584- $85869 .17 7_$(25.106) 51078.04 See ANotes to Respective Financial Statements beginning on page L-1.G-11 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS December31, 2003 and 2002 2003 2002 (in thousands) ELECTRIC UTILITY PLANT Production Transmission Distribution General (including nuclear fuel)Construction Work in Progress TOTAL Accumulated Depreciation and Amortization TOTAL -NET$2,878,051 1,000,926 958,966 274,283 193.956 5,306,182 2.490.912 2.815.270$2,768,463 971,599 921,835 220,137 147,924 5,029,958 2.318.063 2.711.895 OTHER PROPERTY AND INVESTMENTS Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds Non-Utility Property, Net Other Investments TOTAL 982,394 52,303 43,797 1.078.494 870,754 69,252 51,689 991.695 CURRENT ASSETS Cash and Cash Equivalents Advances to Affiliates Accounts Receivable: Customers Affiliated Companies Accrued Unbilled Revenues Miscellaneous Allowance for Uncollectible Accounts Fuel Materials and Supplies Risk Management Assets Margin Deposits Prepayments and Other TOTAL 3,914 61,084 124,826 2,000 4,498 (531)33,968 105,328 44,071 7,245 10.673 397.076 3,237 191,226 92,929 122,489 6,511 4,872 (578)32,731 95,552 67,985 890 11.172 629,016 DEFERRED DEBITS AND OTHER ASSETS Regulatory Assets: SFAS 109 Regulatory Asset, Net Deferred Fuel Costs Cook Plant Restart Costs Incremental Nuclear Refueling Outage Expenses, Net Other Long-term Risk Management Assets Deferred Property Taxes Deferred Charges and Other Assets TOTAL 151,973 57,326 66,978 43,768 21,916 26.270 368.231 163,928 37,501 40,000 29,572 77,211 83,265 22,271 51.378 505.126 TOTAL ASSETS S4.532 See Notes to Respective Financial Statements beginning on page L-1.G-12 INDIANA MICHIGAN POWVER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31,2003 and 2002 2003 2002 (in thousands) CAPITALIZATION Common Shareholder's Equity: Common Stock -No Par Value: Authorized -2,500,000 Shares Outstanding-1,400,000 Shares Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total Common Shareholder's Equity Cumulative Preferred Stock -Not Subject to Mandatory Redemption Total Shareholder's Equity Liability for Cumulative Preferred Stock -Subject to Mandatory Redemption Long-term Debt TOTAL CURRENT LIABILITIES Long-term Debt Due Within One Year Advances from Affiliates Accounts Payable: General Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued Risk Management Liabilities Obligations Under Capital Leases Other TOTAL$56,584 858,694 187,875 (25.106)1,078,047 8.101 1,086,148 63,445 1.134.359 2.283.952 205,000 98,822 101,776 47,484 21,955 42,189 17,963 31,898 6,528 57.675 631.290$56,584 858,560 143,996 (40.487)1,018,653 8.101 1,026,754 64,945 1.587.062 2.678.761 30,000 125,048 93,608 16,660 71,559 21,481 48,568 8,229 76.162 491.315 DEFERRED CREDITS AND OTHER LIABILITIES Deferred Income Taxes Regulatory Liabilities: Asset Removal Costs Deferred Investment Tax Credits Excess ARO for Nuclear Decommissioning Other Deferred Gain on Sale and Leaseback -Rockport Plant Unit 2 Long-term Risk Management Liabilities Obligations Under Capital Leases Asset Retirement Obligations Nuclear Decommissioning Deferred Credits and Other TOTAL 337,376 263,015 90,278 215,715 61,268 70,179 33,537 31,315 553,219 87.927 1.743.829 356,197 97,709 65,983 73,885 32,261 42,619 620,672 378.330 1.667.656 Commitments and Contingencies (Note 7)TOTAL CAPITALIZATION AND LIABILITIES $_A624_W.h2 -See Alotes to Respective Financial Statements beginning on page L-1.S-13 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31,2003,2002 and 2001 2003 OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities: Impairments Cumulative Effect of Accounting Change Depreciation and Amortization Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net Unrecovered Fuel and Purchased Powver Costs Amortization of Nuclear Outage Costs Deferred Income Taxes Deferred Investment Tax Credits Mark-to-Market of Risk Management Contracts Changes in Certain Assets and Liabilities: Accounts Receivable, Net Fuel, Materials and Supplies Accounts Payable Taxes Accrued Change in Other Assets Change in Other Liabilities $86,388 10,300 3,160 171,281 (27,754)37,501 40,000 (14,894)(7,431)43,938 34,346 (11,013)(69,396)(29,370)(24,302)(19,981)2002 (in thousands) $73,992 168,070 (26,577)37,501 40,000 (16,921)(7,740)(9,517)(106,683)(7,854)87,934 1,798 (29,264)23.495 2001$75,788 166,360 418 37,501 40,000 (29,205)(8,324)(62,647)62,769 (19,426)(60,185)1,345 2,622 29.191 Net Cash Flows From Operating Activities INVESTING ACTIVITIES Construction Expenditures Buyout of Nuclear Fuel Leases Other Net Cash Flows Used For Investing Activities 222.773 (184,188)1.485 (182.703)228.234 (167,484)1.759 (165,725)236,207 (91,052)(92,616)1,074 (182,594)FINANCING ACTIVITIES Capital Contributions from Parent Issuance of Long-term Debt Retirement of Cumulative Preferred Stock Retirement of Long-term Debt Change in Advances to/from Affiliates, Net Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net Cash Flows Used For Financing Activities Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period 64,434 (1,500)(350,000)290,048 (40,000)(2.375)(39,393)677 3.237$3,914 125,000 288,732 (424)(340,000)(144,917)(4.467)(76,076)(13,567)16.804__$S,2R 297,656 (44,922)(299,891)(4,487)(51.644!1,969 14,835$16,804-SUPPLEMENTAL DISCLOSURE: Cash paid for interest net of capitalized amounts was $82,593,000, $89,984,000 and $92,140,000 and for income taxes was $94,440,000, $60,523,000 and $100,470,000 in 2003, 2002 and 2001, respectively. Non-cash acquisitions under capital leases were $1,023,000 and $22,218,000 in 2002 and 2001, respectively. There were no non-cash capital lease acquisitions in 2003.See Notes to Respective Financial Statements beginning on page L-J.G-14 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31,2003 and 2002 2003 2002 (in thousands) COMMON SILAREHOLDER'S EQUITY$1.078.047 $1.018,653 PREFERRED STOCK:$ 100 Par Value -Authorized 2,250,000 shares$25 Par Value -Authorized 11,200,000 shares Call Price December 31, Number of Shares Redeemed Series 2003 (a) Year Ended December31, 2003 2002 2001 Not Subject to Mandatory Redemption -$100 Par: 4-1/8% 106.125 4.56% 102 ---4.12% 102.728 -6,326 Total Subject to Mandatory Redemption -$100 Par(b): 5.90% (c) 1/4% (c) ---6.30% (c) ---6-7/8% (d) 15,000 Total Shares Outstanding December 31, 2003 55,369 14,412 11,230 152,000 192,500 132,450 157,500 5,537 1,441 1,123 8.101 15,200 19,250 13,245 15.750 63.445 54,725 310,676 747,873 226,085 (205.000)1.134.359 5,537 1,441 1.123_8.101 15,200 19,250 13,245 17,250 64.945 174,245 310,336 747,027 223,736 161,718 (30,000 1,587.062 LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Senior Unsecured Notes Other Long-term Debt (e)Junior Debentures Less Portion Due Within One Year Long-term Debt Excluding Portion Due Within One Year TOTAL CAPITALIZATION $2,283,252 $S27-61 (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends.(b) Sinking fund provisions require the redemption of 67,500 shares in each of 2004, 2005, 2006 and 2007 and 52,500 shares in 2008. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of these due dates. Shares previously purchased may be applied to meet the sinking fund requirement.(c) Commencing in 2004 and continuing through 2008 I&M may redeem, at $100 per share, 20,000 shares of the 5.90%series, 15,000 shares of the 6-1/4% series and 17,500 shares of the 6.30% series outstanding under sinking fund provisions at its option and all remaining outstanding shares must be redeemed not later than 2009. The series are callable beginning November 1, 2003 for the 5.90% series, December 1, 2003 for the 6-1/4% series and March 1, 2004 for the 6.30% series at $100 plus accrued dividends.(d) Commencing in 2003 and continuing through the year 2007, a sinking fund will require the redemption of 15,000 shares each year and the redemption of the remaining shares outstanding on April 1, 2008, in each case at $100 per share. Callable at $100 per share plus accrued dividends beginning February 1, 2003.(e) Represents a liability for SNF disposal including interest payable to the DOE. See Note 7.See Notes to Respective Financial Statements beginning on page L-1.G-15 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES SCHEDULE OF LONG-TERM DEBT December 31,2003 and 2002 First Mortgage Bonds outstanding werc as follows:% Rate Due 6.10 2003 -November 1 8.50 2022-December 15 7.35 2023 -October 1 7.20 2024 -February 1 7.50 2024 -March 1 Unamortized Discount Total 2003 2002 (in thousands) $- $30,000-75,000-15,000 30,000 (a) 30,000 25,000 (a) 25,000 (275) (755)$5A.725 $174.245 (a) These bonds will be redeemed in April 2004 and have been classified for payment in 2004.First Mortgage Bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Interest payments are made semi-annually. Installment Purchase Contracts have been entered in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: 2003 2002 (in thousands) % Rate City of Lawvrenceburg, Indiana: 7.00 (a)5.90 City of Rockport, Indiana: 7.60 (a)6.55 (b)4.90(c)Due 2015 -April 1 2019 -October 1 2019 -November 1 2016 -March 1 2025-April 1 2025-June 1 2025-June 1 2025 -June 1 25,000 52,000 40,000 50,000 50,000 50,000 45,000 (1.324)$310,676$25,000 52,000 40,000 50,000 50,000 50,000 45,000 (1.664)$31033 City of Sullivan, Indiana: 5.95 2009-May 1 Unamortized Discount Total (a) Rate is an annual long-term fixed rate of 2.625% through October 1, 2006. After that date the rate may be a daily or'weekly reset rate, commercial paper, auction or other long-term rate as designated by I&M (fixed rate bonds).(b) In 2001, an auction rate was established. Auction rates are determined by standard procedures every 35 days. The auction rate for 2003 ranged from 0.85% to 1.35% and averaged 1.05%. The auction rate for 2002 ranged from 1.3%to 1.7% and averaged 1.5%.(c) Rate is fixed until June 1, 2007 (term rate bonds).G-16 The terms of the installment purchase contracts require I&M to pay amounts sufficient for the cities to pay interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants. The fixed rate bonds due 2019 and 2025 are subject to mandatory tender for purchase on October 1, 2006. Consequently, the fixed rate bonds have been classified for repayment purposes in 2006. The term rate bonds due 2025 are subject to mandatory tender for purchase on the term maturity date (June 1, 2007). Accordingly, the term rate bonds have been classified for repayment purposes in 2007 (the terrn end date). Interest payments range from every 35 days to semi-annually. Senior Unsecured Notes outstanding were as follows:% Rate Due 6-7/8 2004-July 1 6.125 2006 -December 15 6.45 2008 -November 10 6.375 2012-November 1 6.00 2032 -December 31 Unamortized Discount Total 2003 2002 (in thousands) $150,000 $150,000 300,000 300,000 50,000 50,000 100,000 100,000 150,000 150,000 (2,127) (2,973)$S4M871 $12Q2 Junior Debentures outstanding were as follows:% Rate Due 8.00 2026 -March 31 7.60 2038 -June 30 Unamortized Discount Total 2003 2002 (in thousands) $- $40,000-125,000-(3,282)$-_ $161,71 At December 31, 2003 future annual long-term debt payments are as follows: 2004 2005 2006 2007 2008 Later Years Total Principal Amount Unamortized Discount Total Amount (in thousands) $205,000 365,000 50,000 50,000 673,085 1,343,085 (3,726)ILME5 G-17 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to l&M's consolidated financial statements are combined wxith the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to l&M. The footnotes begin on page Lb-.Footnote Reference Organization and Summary of Significant Accounting Policies Note I New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes Note 2 Rate Matters Note 4 Effects of Regulation Note 5 Customer Choice and Industry Restructuring Note 6 Commitments and Contingencies Note 7 Guarantees Note 8 Sustained Eamings Improvement Initiative Note 9 Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used Note 10 Benefit Plans Note 11 Business Segments Note 12 Derivatives, Hedging and Financial Instruments Note 13 Income Taxes Note 14 Leases Note 15 Financing Activities Note 16 Related Party Transactions Note 17 Unaudited Quarterly Financial Information Note 19 G-18 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Indiana Michigan Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Indiana Michigan Power Company and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, changes in common shareholder's equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as wvell as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and subsidiaries as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.As discussed in Note 2 to the consolidated financial statements, the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations" and EITF 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," effective January 1, 2003.Is! Deloitte & Touche LLP Columbus, Ohio March 5, 2004 G-19 KENTUCKY PONVER COMPANY KENTUCKY POWER COMPANY SELECTED FINANCIAL DATA 2003 2002 2001 (in thousands) 2000 1999 INCOME STATEMENTS DATA Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Income Before Cumulative Effect of Accounting Change Cumulative Effect of Accounting Change (Net of Tax)Net Income$416,470_351.726 64,744 (2,660)28,620 33,464 (1,134)_S32,3D$378,683 336,486 42,197 5,206 26,836 20,567$379,025 331.347 47,678 1,248 27.361 21,565$389,875 340.137 49,738 2,070 31.045 20,763$358,757 304,082 54,675 (327)28,918 25,430__$2A __M..$20.76- _$25.430 BALANCE SHEETS DATA Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant$1,349,746 $1,295,619 $1,128,415 360.319-$-Ms09$1,103,064 338,270$1,079,048 318.799-$16.2 381,876$96787 373,638 TOTAL ASSETS$L022.831 SLM2621$SLQ72 Common Stock and Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total Common Shareholder's Equity$259,200 64,151 (6,213$259,200 48,269 (9.451)$209,200 48,833 (1,903)$209,200 57,513$209,200 67,110 Long-term Debt (a)$34b.093$sa.8-8k Obligations Under Capital Leases (a)TOTAL CAPITALIZATION AND LIABILITIES $1S8.342$1A-2.8n S1.Q0Z (a) Including portion due within one year.H-1 KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS KPCo is a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 175,000 retail customers in our service territory in eastern Kentucky. As a member of the AEP Power Pool, we share the revenues and the costs of the AEP Power Pool's sales to neighboring utilities and power marketers. We also sell power at wholesale to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member's prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR), which determines each member's percentage share of revenues and costs.Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other AEP registrant subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas. The electricity and gas contracts include physical transactions, over-the-counter options and swaps and exchange traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts. Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and NVest companies' allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and WVest companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and WVest companies, respectively, for the remainder of 2003.Results of Onerations 2003 Compared to 2002 Net Income for 2003 increased $12 million over 2002 primarily due to improved earnings from system sales and transmission revenues, as well as decreased employee related expenses and maintenance expenses. These improvements were partially offset by net losses from risk management activities included in Nonoperating Income (Expense) that exceeded net gains from risk management activities included in Operating Income.Operating Income Operating Income for 2003 increased $23 million primarily due to:* Increases in system sales and transmission revenues of $16 million and an increase in gains from risk management activities of $7 million.* An increase in Sales to AEP Affiliates of $12 million due to strong wholesale sales by the AEP Power Pool.* An increase in residential and commercial sales of $4 million over 2002 due to the rate increase in mid 2003 to recover the cost of emission control equipment (see Note 4, "Rate Matters").

An $8 million decrease in Maintenance expense due to planned plant outages in 2002. Big Sandy plant Unit 2 was down for the entire fourth quarter of 2002 for planned boiler and electric plant maintenance.

In addition, Big Sandy Unit I was down for two months in 2002 for boiler maintenance.

A $6 million decrease in Other Operation expense primarily due to the impact of cost reduction efforts instituted in the fourth quarter of 2002 and related employment termination benefits recorded in 2002, partially offset by reduced gains from emission allowances.

H-2 The increases in Operating Income were partially offset by:* A decline in industrial sales of $2 million reflecting the weak economy and the reduced usage by a major customer in 2003.* An increase in fuel expense of $9 million due to increased generation based on the increased plant availability at Big Sandy in 2003.* An increase in purchased power expense of $10 million necessary to support system sales and Sales to AEP Affiliates. In addition, energy purchases increased from the Rockport Plant based on plant availability, as required by the unit power agreement with AEGCo, an affiliated company. The unit power agreement with AEGCo provides for our purchase of 15% of the total output of the two unit 2,600-MW capacity Rockport Plant.* An increase in Depreciation and Amortization of $6 million reflecting the completion and implementation of new capital projects in the third quarter of 2003, as well as the implementation of emission control equipment at the Big Sandy plant in the second quarter of 2003.* An increase in Income Taxes of $3 million due to an increase in pre-tax book operating income partially offset by federal and state tax return adjustments. Othler Impacts on Earnings Nonoperating income decreased $12 million in 2003 compared to 2002 primarily due to lower profit from power sold outside AEP's traditional marketing area resulting from AEP's plan to exit risk management activities in areas outside of its traditional market area. The decrease in nonoperating income was partially offset by a $4 million decrease in nonoperating income taxes resulting primarily from the reduced pre-tax nonoperating book income. Interest Charges increased $2 million primarily due to an increase in outstanding debt partially offset by lower market interest rates on newly issued debt.Financial Condition Credit Ratings The rating agencies currently have us on stable outlook. Current ratings are as follows: Moodv's S&P Fitch Senior Unsecured Debt Baa2 BBB BBB In February 2003, Moody's Investors Service (Moody's) completed their review of AEP and its rated subsidiaries. The completion of this review was a culmination of ratings action started during 2002.H-3 Summarv Obligation Information Our contractual obligations include amouiits reported on the Consolidated BIlance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2003: Payments Due by Period (in thousands) Contractual Cash Oblieations Less Than I vear 2-3 'ears 4-5 years After5 vears Total Long-term Debt $- $60,000 $352,964 $74,638 $487,602 Advances from Affiliates 38,096 ---38,096 Capital Lease Obligations 2,107 2,597 1,041 116 5,861 Unconditional Purchase Obligations (a) 39,658 16,636 --56,294 Noncancellable Operating Leases _1,209 1,877 1,246 1,785 6,117 Total $81,$L. $355^251 $M.2 $593.97 (a) Represents contractual obligations to purchase coal as fuel for electric generation along with related transportation of the fuel.Significant Factors See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-l for additional discussion of factors relevant to us.quantitative And Oualitative Disclosures About Risk Management Activities Market Risks Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effect on this specific registrant. MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.MTM Risk Management Contract Net Assets Year Ended December 31,2003 (in thousands) Domestic Power Beginning Balance December 31,2002 $24,998 (Gain) Loss from Contracts Realized/Settled During the Period (a) (6,682)Fair Value of New Contracts When Entered Into During the Period (b)Net Option Premiums Paid/(Received) (c) 32 Change in Fair Value Due to Valuation Methodology Changes Effect of EITF 98-10 Rescission (d) (1,744)Changes in Fair Value of Risk Management Contracts (e) 461 Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (f) (1.575)Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges 15,490 Net Cash Flow Hedge Contracts (g) 126 DETM Assignment (h) (7.349)Ending Balance December 31,2003 S8 H4 (a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003.(b)The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location.(c)'Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003.(d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes." (e)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.(f)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.(g)"Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in Accumulated Other Comprehensive Income (Loss).(h)See Note 17 "Related Party Transactions." Maturity and Source of Fair Value of MTMU Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets Fair Value of Contracts as of December 31,2003 After 2004 2005 2006 2007 2008 2008 Total (c)(in thousands)

Prices Actively Quoted -Exchange Traded Contracts $277 $(56) $7 $43 $- $- $271 Prices Provided by Other External Sources -OTC Broker Quotes (a) 5,405 1,937 1,899 772 388 -10,401 Prices Based on Models and Other Valuation Methods (b) (1) 12 754 871 801 2.381 4.818 Total S$LL $L893 $2.660 $1.6&6 $1VA% 2. $1 .A H-5 (a) "Prices Provided by Other External Sources -OTC Broker Quotes" reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.(b)"Prices Based on Models and Other Valuation Methods" is in absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the Modeled category varies by market.(c) Amounts exclude Cash Flow Hedges.Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. (However, given that under SFAS 133 only cash flow hedges are recorded in AOCI, the table does not provide an all-encompassing picture of our hedging activity). The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll-off of hedges). In accordance with GAAP, all amounts are presented net of related income taxes.Total Accumulated Other Comprehensive Income (Loss) Activity Year Ended December 31, 2003 Domestic Power Interest Rate Consolidated (in thousands) Beginning Balance December31, 2002 $(103) $425 $322 Changes in Fair Value (a) 75 -75 Reclassifications from AOCI to Net Income (b) 110 (87! 23 Ending Balance December 31, 2003 ______ $3 (a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes.(b) "Reclassifications from AOCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above.The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $466 thousand gain.Credit Risk Our counterparty credit quality and exposure is generally consistent with that of AEP.H-6 VaR Associated waith Risk Management Contracts The following table shows the end, high, average, and low market risk as measured by VaR for year-to-date: December31, 2003 (in thousands) End High Average Low$136 $527 $220 $52 December 31, 2002 (in thousands) End High Average Low$333 $1,019 $364 $74 VaR Associated with Debt Outstanding The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $29 million and $30 million at December 31, 2003 and 2002, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not negatively affect our results of operation or financial position.H-7 KENTUCKY POWER COMPANY STATEMENTS OF INCOME For the Ycars Ended December 31, 2003,2002 and 2001 2003 OPERATING REVENUES Electric Generation, Transmission and Distribution Sales to AEP Affiliates TOTAL OPERATING EXPENSES Fuel for Electric Generation Purchased Electricity for Resale Purchased Electricity from AEP Affiliates Other Operation Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Income Taxes TOTAL$376,662 39.808 416.470 74,148 963 141,690 47,325 27,328 39,309 8,788 12,175 351.726 2002 (in thousands) $350,719 27,964 378,683 65,043 29 133,002 52,892 35,089 33,233 8,240 8.958 336.486 2001$336,659 42.366 379.025 70,635 86 130,204 58,275 22,444 32,491 7,854 9.358 331.347 OPERATING INCOME 64,744 42,197 47,678 Nonoperating Income (Expense)Nonoperating Expenses Nonoperating Income Tax Expense (Credit)Interest Charges (4,036)1,124 (2,500)28.620 7,950 840 1,904 26,836 10,979 9,047 684 27.361 Income Before Cumulative Effect of Accounting Change Cumulative Effect of Accounting Change (Net of Tax)33,464 20,567 21,565 (1,134)NET INCOME il122.33T 71e common stock of KPCo is wholl.y-owned byAEP.See Notes to Respective Financial Statements beginning on page I-1.H-8 KENTUCKY POWVER COMPANY STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME For the Years Ended December 31,2003,2002 and 2001 (in thousands) Common Stock Paid-in Capital Retained Earnines Accumulated Other Comprehensive Income (Loss)Total DECEMBER 31,2000$50,450 $158,750$57,513$- $266,713 Common Stock Dividends TOTAL COMPREHENSIVE INCOME Other Comprehensive Income, Net of Taxes: Unrealized Loss on Cash Flow Hedges NET INCOME TOTAL COMPREHENSIVE INCOME (30,245)21,565 (30.245)236.468 (1,903)(1,903)21.565 19,662 DECEMBER 31,2001$50,450 $158,750$48,833$(1,903) $256,130 Capital Contribution from Parent Common Stock Dividends TOTAL 50,000 (21,131)50,000 (21.131)284.999 COMPREHENSIVE INCOME Other Comprehensive Income, Net of Taxes: Unrealized Gain on Cash Flow Hedges Minimum Pension Liability NET INCOME TOTAL COMPREHENSIVE INCOME 2,225 (9,773)2,225 (9,773)20.567 13,019 20,567 DECEMBER 31,2002$50,450 $208,750$48,269$(9,451) $298,018 Common Stock Dividends TOTAL (16,448)(16.448)281,570 COMPREHENSIVE INCOME Other Comprehensive Income, Net of Taxes: Unrealized Gain on Cash Flow Hedges Minimum Pension Liability NET INCOME TOTAL COMPREHENSIVE INCOME DECEMBER 31,2003 _$50,450 $20QB See Notes to Respective Financial Statements beginning on page L-1.98 3,140 32,330 98 3,140 32,330 35.568$3i2JL H-9 KENTUCKY POWER COMPANY BALANCE SHEETS ASSETS December 31,2003 and 2002 2003 2002 (in thousands) ELECTRIC UTILITY PLANT Production

Transmission Distribution General Construction Work in Progress TOTAL Accumulated Depreciation and Amortization TOTAL -NET$457,341 381,354 425,688 68,041 17.322 1,349,746 381.876 967.870$275,121 373,639 414,281 67,449 165.129 1,295,619 373.638 921.981 OTHER PROPERTY AND INVESTMENTS Non-Utility Property, Net Other Investments TOTAL CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable:

Customers Affiliated Companies Accrued Unbilled Revenues Miscellaneous Allowance for Uncollectible Accounts Fuel Materials and Supplies Accrued Tax Benefit Risk Management Assets Margin Deposits Prepayments and Other TOTAL 5,423 1.022 6.445 886 21,177 25,327 5,534 97 (736)9,481 16,585 16,200 2,660 1.696 98.907 5,477 1.427 6.904 2,304 24,716 23,802 5,301 217 (192)10,817 16,127 1,253 24,261 320 1.866 110.792 DEFERRED DEBITS AND OTHER ASSETS Regulatory Assets: SFAS 109 Regulatory Asset, Net Other Regulatory Assets Long-term Risk Management Assets Deferred Property Taxes Other Deferred Charges TOTAL 99,828 13,971 16,134 6,847 11.632 148.412 87,261 14,715 29,871 6,300 10.518 148,665 TOTAL ASSETS-M221631 See Notes to Respecthie Financial Statements beginning on page L-J.H-10 KENTUCKY PONVER COMPANY BALANCE SHEETS CAPATALIZATION AND LIABILITIES December 31,2003 and 2002 2003 2002 (in thousands) CAPITALIZATION Common Shareholder's Equity: Common Stock -$50 Par Value: Authorized -2,000,000 Shares Outstanding -1,009,000 Shares Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total Common Shareholder's Equity Long-term Debt: Nonaffiliated Affiliated Total Long-tcrm Debt TOTAL$50,450 208,750 64,151 (6.213)317,138 427,602 604000 487,602 804.740$50,450 208,750 48,269 (9.451)298.018 391,632 60.000 451.632 749.650 CURRENT LIABILITIES Long-tenn Debt Due Within One Year -Affiliated Advances from Affiliates Accounts Payable: General Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued Risk Management Liabilities Obligations Under Capital Leases Other TOTAL 38,096 22,802 22,648 9,894 7,329 6,915 11,704 1,743 8.628 129,759 15,000 23,386 46,515 44,035 8,048 6,471 17,803 2,155 12.167 175,580 DEFERRED CREDITS AND OTHER LIABILITIES Deferred Income Taxes Regulatory Liabilities: Asset Removal Costs Deferred Investment Tax Credits Other Regulatory Liabilities Long-term Risk Management Liabilities Obligations Under Capital Leases Deferred Credits and Other TOTAL 212,121 26,140 7,955 10,591 12,363 3,549 14.416 287.135 178,313 9,165 12,152 11,488 5,093 46.901 263,112 Commitments and Contingencies (Note 7)TOTAL CAPITALIZATION AND LIABILITIES-U.221634 See Notes to Respective Financial Statements beginning on page L-l.H-11 KENTUCKY PONER COMPANY STATEMENTS OF CASH FLOWS For the Years Ended December 31,2003,2002 and 2001 2003 OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities: Cumulative Effect of Accounting Change Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax Credits Deferred Fuel Costs, Net Mark-to-Market of Risk Management Contracts Changes in Certain Assets and Liabilities: Accounts Receivable, Net Fuel, Materials and Supplies Accounts Payable Taxes Accrued Change in Other Assets Change in Other Liabilities Net Cash Flows From Operating Activities $32,330 1,134 39,309 20,107 (1,210)233 15,112 2,445 878 (45,100)8,582 (16,588)4,565 61.797 2002 (in thousands) $20,567 33,233 9,839 (1,240)2,998 (12,267)(9,332)882 44,529 (11,558)(21,491)16,161 72,321 2001$21,565 32,491 6,293 (1,251)(4,707)(1,454)24,799 (7,658)(22,942)(1,580)(2,762)(9.446)33,348 INVESTING ACTIVITIES Construction Expenditures Proceeds from Sales of Property and Other Net Cash Flow Used for Investing Activities FINANCING ACTIVITIES Capital Contributions from Parent Company Issuance of Long-term Debt -Nonaffiliated Issuance of Long-term Debt -Affiliated Retirement of Long-term Debt -Nonaffiliated Retirement of Long-term Debt -Affiliated Change in Advances to/from Affiliates, Net Dividends Paid Net Cash Flows From Financing Activities (81,707)967 (80,740)74,263 (40,000)(15,000)14,710 (16.448)17,525 (178,700)217 (178.483)50,000 274,964 (154,500)(42,814)(21.131)106.519 (37,206)216 (36.990)75,000 (60,000)18,564 (30.245)3,319 Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period (1,418)2.304 357 1.947___2.30A (323)2.270$1,947 SUPPLEMENTAL DISCLOSURE: Cash paid for interest net of capitalized amounts was $26,988,000, $25,176,000 and $27,090,000 in 2003, 2002 and 2001, respectively. Cash (received) paid for income taxes was $(17,574,000), $13,041,000 and $7,549,000 in 2003, 2002 and 2001, respectively. Noncash acquisitions under capital leases were $22,000 and $817,000 in 2002 and 2001, respectively. There were no non-cash capital lease acquisitions in 2003.See Notes to Respective Financial Statements beginning on page L-J.H-12 KENTUCKY POWER COMPANY STATEMENTS OF CAPITALIZATION December 31,2003 and 2002 2003 2002 (in thousands) $317,138 $298,018 COMIAION SHAREHOLDER'S EQUITY LONG-TERMI DEBT (See Schedule of Long-term Debt): Senior Unsecured Notes Notes Payable Junior Debentures Less Portion Due Within One Year Long-term Debt Excluding Portion Due Within One Year TOTAL CAPITALIZATION See Nlotes to Respective Financial Statements beginning on page L-J.427,602 60,000 487.602 352,508 75,000 39,124 (15,000)451,632 H-13 KENTUCKY PONVER COMPANY SCHEDULE OF LONG-TERM DEBT December 31,2003 and 2002 Senior Unsecured Notes outstanding were as follows:% Rate Due 6.91 2007- October 1 6.45 2008 -November 10 5.50 2007-July 1 4.31 2007 -November 12 4.37 2007 -December 12 5.625 2032 -December 31 Unamortized Discount Total 2003 2002 (in thousands) $48,000 $48,000 30,000 30,000 125,000 125,000 80,400 80,400 69,564 69,564 75,000 -(362) (456)$127fi692 $352,5D8 Notes Payable to parent company were as follows:% Rate 4.336 6.501 Total Due 2003 -May 15 2006 -May 15 2003 2002 (in thousands) $- $15,000 60.000 60.000$60,0 $75,0K Junior Debentures outstanding were as follows:% Rate 8.72 Due 2025 -June 30 2003 2002 (in thousands) $- $40,000_~(876J$--- _39L>Unamortized Discount Total Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company.At December 31, 2003, future annual long-term debt payments are as follows: 2004 2005 2006 2007 2008 Later Years Total Principal Amount Unamortized Discount Total Amount (in thousands) 60,000 322,964 30,000 75,000 487,964 (362)&487.6f2_H-14 KENTUCKY PONVER COMPANY INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to KPCo's financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to KPCo. The footnotes begin on page L-1.Footnote Reference Organization and Summary of Significant Accounting Policies Note I New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes Note 2 Rate Matters Note 4 Effects of Regulation Note 5 Commitments and Contingencies Note 7 Guarantees Note 8 Sustained Earnings Improvement Initiative Note 9 Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used Note 10 Benefit Plans Note II Business Segments Note 12 Derivatives, Hedging and Financial Instruments Note 13 Income Taxes Note 14 Leases Note 15 Financing Activities Note 16 Related Party Transactions Note 17 Unaudited Quarterly Financial Information Note 19 H-15 INDEPENDENT AUDITORS' REPORT To the Shareholder and Board of Directors of Kentucky Power Company: We have audited the accompanying balance sheets and statements of capitalization of Kentucky Power Company as of December 31, 2003 and 2002, and the related statements of income, changes in common shareholder's equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. WXe believe that our audits provide a reasonable basis for our opinion.In our opinion, such financial statements present fairly, in all material respects, the financial position of Kentucky Power Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.As discussed in Note 2 to the financial statements, the Company adopted EITE 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," effective January 1, 2003.Isl Deloitte & Touche LLP Columbus, Ohio March 5, 2004 H-16 OIO POWER COMPANY CONSOLIDATED OHIO POWER COMPANY CONSOLIDATED SELECTED CONSOLIDATED FINANCIAL DATA 2003 2002 2001 (in thousands) 2000 1999 INCOME STATEMENTS DATA Operating Revenues Operating Expenses Operating Income Nonoperating Items, Net Interest Charges Income Before Extraordinary Item And Cumulative Effect Extraordinary Loss (Net of Tax)Cumulative Effect of Accounting Changes (Net of Tax)Net Income Preferred Stock Dividend Requirements Earnings Applicable To Common Stock$2,244,653 1.884,986 359,667 (2,172)106,464 251,031 375,663 1.098$2,113,125 1,814.796 298,329 5,376 83,682 220,023$2,098,105 1,857,395 240,710 18,686 93.603 165,793 (18,348)$2,140,331 1.913.504 226,827 (5,004)119.210 102,613 (18,876)83,737$1,978,826 1,689.997 288,829 7,000 832672 212,157 212,157 220,023 147,445 1.417$374,565 .$218.W5. _$1M,46&_$21 $20.74M BALANCE SHEETS DATA Electric Utility Plant Accumulated Depreciation Net Electric Utility Plant$6,531,315 2,485,947$5,685,826 2,469.837$5,390,576 2.360,857$5,577,631 2.678.606$2,899.025 $5,400,917 2.540.445$2,86QA22. TOTAL ASSETS$SAAMIIM$X2792491$456A25-Common Stock and Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total Common Shareholder's Equity$783,685 729,147 (48.807)$783,684 522,316 (72.886)$783,684 401,297$783,684 398,086$783,577 587,424 (196)$1,4A64,2I $1,184,78$11dL1h Cumulative Preferred Stock: Not Subject to Mandatory Redemption Subject to Mandatory Redemption (a)Total Cumulative Preferred Stock$16,645 7.250$16,648 8.850_-$25.49$16,648 8.850_$25.$16,648 8.850__$25.9$16,937 8.850__$25,Z8 Long-term Debt (a)$2,099 $,LQ0671 $SL2a84$1. 195,423 Obligations Under Capital Leases (a)TOTAL CAPITALIZATION AND LIABILITIES $534A $4.5 54 $4,485,787 $6.217929 (a) Including portion due within one year.1-1 OIO PONER COMPANY CONSOLIDATED MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS OPCo is a public utility engaged in the generation and purchase of electric power and the subsequent sale, transmission and distribution of that power to approximately 704,000 retail customers in the northwestern, east central, eastern and southern sections of Ohio. We also supply and market electric power at wholesale to other electric utility companies, municipalities and electric cooperatives. We, as a member of the AEP Power Pool, share in the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities. The cost of the AEP Power Pool's generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member's prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR), which determines each member's percentage share of revenues and costs.Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other AEP registrant subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas. The electricity and gas contracts include physical transactions, over-the-counter options and swaps and exchange traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts. Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and BVest companies' allocation of approximately 91 % and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and West companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and WVest companies, respectively, for the remainder of 2003.Effective July 1, 2003, *ve consolidated JMG Funding, LP (3MG) as a result of the implementation of FIN 46. OPCo now records the depreciation, interest and other operating expenses of JMG and eliminates JMG's revenues against OPCo's operating lease expenses. While there was no effect to net income as a result of consolidation, some individual income statement captions were affected. See Note 2, "New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes," and Note 15, "Leases," for further discussion of the effects of FIN 46.Results of Onerations During 2003, Net Income increased $156 million including a $125 million Cumulative Effect of Accounting Changes in the first quarter of 2003 (see Note 2). Income Before Cumulative Effect of Accounting Changes increased $31 million primarily due to increased revenues which were allocated to us from sales made to third parties by the AEP Power Pool.During 2002, Income Before Extraordinary Item increased $54 million due to reductions in operating expenses, predominantly fuel, and interest charges.1-2 2003 Compared to 2002 Operating Income Operating Income increased $61 million for the year 2O0i comrpared with 2002 due to:* A $22 million increase in revenues from non-affiliated system sales and a $119 million increase in Sales to AEP Affiliates. The increase in non-affiliated system sales is primarily the result of an 8.9% increase in the price per MWVH in 2003. The increase in affiliated sales is the result of optimizing our generation capacity and selling our excess generated power to the AEP Power Pool.* A $47 million decrease in Other Operation expense. This decrease was primarily due to a $23 million decrease in rent expense associated with the OPCo consolidation of JMG. OPCo now records the depreciation, interest and other expenses of JMG and eliminates operating lease expense against JMG's lease revenues (there was no change in overall net income due to the consolidation of JMG). In addition, operation expenses decreased due to a $7 million pre-tax adjustment to the workers' compensation reserve related to coal companies sold in July 2001, a $9 million decrease in expense related to post-employment benefits and an $8 million reduction in employee salary expenses.The increase in Operating Income was partially offset by:* An increase in Fuel for Electric Generation of $32 million as a result of a 9.7% increase in MWH generated.

An increase in Purchased Electricity from AEP Affiliates of $20 million resulting from a 31% volume increase in MWIIs purchased from the AEP Power Pool.* A $30 million increase in Maintenance expenses.

The increase in 2003 is primarily due to increased boiler overhaul costs for planned and forced outages coupled with increased expense in maintaining overhead lines due to storm damage in Southern Ohio.* An increase in Depreciation and Amortization associated with the OPC6 consolidation of JMG. Depreciation expense related to the assets owned by JMG are now consolidated with OPCo.* An increase in Income Taxes of $32 million as a result of an increase in pre-tax operating book income and tax return adjustments. Other Impacts of Earnings Nonoperating Income decreased $34 million for the year 2003 compared to 2002 primarily due to lower profit from power sold outside AEP's traditional marketing area resulting from AEP's plan to exit risk management activities in areas outside of its traditional market area.Nonoperating Income Tax Expense decreased $26 million as a result of a decrease in pre-tax nonoperating book income and changes related to consolidated tax savings.Interest charges increased $23 million due primarily to the consolidation of JMG and its associated debt along with replacement of lower cost floating-rate short-term debt with higher cost fixed-rate longer-term debt.Ctumulative Effect ofAccozmting Changes The Cumulative Effect of Accounting Changes is due to the one-time after-tax impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see Note 2).1-3 2002 Compared to 2001 Operating Income Operating Income increased $58 million from the yeart 20U1 to tie year 2002 primarily due to:* A $61 million increase in nonaffiliated revenues resulting from a 39% increase in cooling degree days during the summer months along with a 32% increase in the heating degree days during the fall season. This reflects a return to more normal weather conditions since 2001 weather was abnormally mild.* A $102 million decrease in Fuel for Electric Generation expense. This reflects a reduction of 19% in average cost of fuel for generation, offset in part by a slight increase in MWVH generated. The decrease in fuel costs are the result of purchasing coal at lower prices on the open market in 2002 instead of affiliated company coal.The increase in Operating Income was partially offset by:* A $46 million decrease in Sales to AEP Affiliates. This decrease is due to a 15% decrease in price, reflective of lower average fuel cost, while MWVH sales rose slightly.* A $13 million increase in Purchased Electricity for Resale and Purchased Electricity from AEP Affiliates expenses. This was the result of an 11% increase in MWVH sales and an 18% increase of MWVH purchased from affiliates, partially offset by a decrease in price.* A $16 million increase in Taxes Other Than Income Taxes as a result of increases in state excise tax created from a change in the base tax calculation.

A $12 million increase in both federal and state tax expenses.

Federal taxes increased due to higher pre-tax operating income offset in part by changes in certain book/tax timing differences accounted for on a flow-thru basis. State taxes increased predominately as a result of the State of Ohio's tax legislation revision involving utility deregulation. Other Impacts on Earnings Nonoperating Expenses decreased $25 million during 2002 due to reductions in variable incentive compensation expenses associated with risk management activities. Nonoperating Income Tax Expense increased $20 million as a result of a favorable tax benefit recognized in 2001 from the sale of the Ohio Coal companies. Interest Charges decreased $10 million due primarily to a decrease in the outstanding balances of long-term debt, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.Extraordinary Loss In the second quarter of 2001, an extraordinary loss of $18 million net of tax was recorded to write-off prepaid Ohio excise taxes stranded by Ohio deregulation (see Note 2).Financial Condition Credit Ratings The rating agencies currently have us on stable outlook. Current ratings are as follows: Moody's S&P Fitch First Mortgage Bonds A3 BBB A-Senior Unsecured Debt A3 BBB BBB+1-4 ..In February 2003, Moody's Investor Service (Moody's) completed their review of AEP and its rated subsidiaries. The completion of this review was a culmination of ratings action started during 2002 In March 2003, S&P lowered AEP and its subsidiaries senior unsecured ratings from BBB+ to BBB along with the first mortgage bonds of AEP subsidiaries. Cash Flow I Cash flows years ended December 31, 2003, 2002 and 2001 were as follows: 2003 2002 (in thousands) $5.285 $8.848 Cash and cash equivalents at beginning of period Cash flows from (used for): Operating activities Investing activities Financing activities Net increase (decrease) in cash and cash equivalents 373,443 (237,011)(83,467)478,973 (348,298)(134.238)2001$31.393 86,756 (359,908)250.607 (22.545)(3.563)Cash and cash equivalents at end of period $58,2 _$5 .$8.8A Operating Activities Cash flows from operating activities for the year 2003 decreased $106 million compared to the year 2002 as they wvere adversely impacted primarily by significant reductions of accounts payable balances partially associated with a wind down of risk management activities in the current year.Cash flows from operating activities for the year 2002 compared to the year 2001 increased $392 million as they were adversely impacted primarily by significant increases in Employee Benefits and OtherNoncurrent Liabilities. Investing Activities Cash flows used for investing activities were reduced in the year 2003 compared with the year 2002 due primarily to a$ 110 million decrease in construction expenditures. Cash flows used for investing activities remained relatively consistent from the year 2001 to the year 2002.Financing Activities Cash flows used for financing activities for the year of 2003 compared to the year 2002 used $51 million less primarily due to the retirement and restructuring of our long-term and short-term debt during 2003. We retired $300 million of Long-term Debt to Affiliated Companies and $275 million of Short-term Debt to Affiliated Companies with the proceeds of two Senior Unsecured Notes at $250 million each. In addition we issued two series of Senior Unsecured Notes, each in the amount of $225 million in July 2003.Cash flows used for financing activities for the year 2002 compared to the year 2001 increased $385 million. This is primarily due to a decrease in the change in Advances to/from Affiliates, net during 2002.1-5 Summarv Oblieation Information Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2003: Payments Due by Period (in millions)Contractual Cash Obligations Less Than I cear 2-3 years 4-5 vears After 5 years Total Long-term Debt $432 $25 $73 $1,510 $2,040 Short-term Debt 26 ---26 Preferred Stock Subject to Mandatory Redemption 2 4 1 -7 Capital Lease Obligations 11 16 9 5 41 Unconditional Purchase Obligations (a) 626 917 511 578 2,632 Noncancellable Operating Leases 13 23 22 67 125 Total $1110 $985 $616 $21 $4.711 (a) Represents contractual obligations to purchase coal as fuel for electric generation along with related transportation of the fuel.In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business. These commitments include standby letters of credit and other commitments. Our commitments outstanding at December 31,2003 under these agreements are summarized in the table below: Amount of Commitment Expiration Per Period (in millions)Other Commercial Commitments Less Than 1 year 2-3 years 4-5 years After 5 years Total Standby Letters of Credit (a) $5 $- $- $- $5 Other Commercial Commitments (b) 14 14 _ -28 Total Commercial Commitments $19 $14 $33 (a) We have issued standby letters of credit to third parties. These letters of credit cover gas and electricity risk management contracts, construction contracts, insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. All of these letters of credit were issued in the ordinary course of business. AEP holds all assets of OPCo as collateral. There is no recourse to third parties in the event these letters of credit are drawn.(b) CVe have entered into a 30-year power purchase agreement for electricity produced by an unaffiliated entity's three-unit natural gas fired plant. The plant was completed in 2002 and the agreement will terminate in 2032. Under the terms of the agreement, we have the option to run the plant until December 31, 2005, taking 100% of the power generated and making monthly capacity payments.The capacity payments are fixed through December 2005 at $1.2 million per month. For the remainder of the 30-year contract term, we will pay the variable costs to generate the electricity it purchases which could be up to 20% of the plant's capacity.Other Power Generation Facility AEP has agreements with Juniper Capital L.P. (Juniper) for Juniper to develop, construct, and finance a non-regulated merchant power generation facility (Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to AEP.The Facility is a "qualifying cogeneration facility" for purposes of PURPA. Construction of the Facility was begun by 1-6 Katco Funding, Limited Partnership (Katco), an unrelated unconsolidated special purpose entity. Katco assigned its interest in the Facility to Juniper in June 2003.Juniper is an unaffiliated limited partnership, formed to construct or otherwise acquire real and personal property for lease to third parties, to manage financial assets and to undertake other activities related to asset financing. Juniper arranged to finance the Facility with debt financing up to $494 million and equity up to $31 million from investors with no relationship to AEP or any of AEP's subsidiaries. Juniper will own the Facility and lease it to AEP after construction is completed. Another AEP subsidiary is the construction agent for Juniper. They expect to achieve COD in the spring of 2004, at which time the obligation to make payments under the lease agreement will begin to accrue and AEP will sublease the Facility to The Dow Chemical Company (Dow). If COD does not occur on or before March 14, 2004, Juniper has the right to terminate the project. In the event the project is terminated before COD, AEP has the option to either purchase the Facility for 100% of Juniper's acquisition cost (in general, the outstanding debt and equity associated with the Facility) or terminate the project and make a payment to Juniper for 89.9% of project costs (in general, the acquisition cost less certain financing costs).The initial term of the lease agreement between Juniper and AEP commences on COD and continues for five years. The lease contains extension options, and if all extension options are exercised, the total term of the lease will be 30 years.AEP's lease payments to Juniper during the initial term and each extended term are sufficient for Juniper to make required debt payments under Juniper's debt financing associated with the Facility and provide a return on equity to the investors in Juniper. AEP has the right to purchase the Facility for the acquisition cost during the last month of the initial term or on any monthly rent payment date during any extended term. In addition, AEP may purchase the Facility from Juniper for the acquisition cost at any time during the initial term if AEP has arranged a sale of the Facility to an unaffiliated third party. A purchase of the Facility from Juniper by AEP should not alter Dow's rights to lease the Facility or our contract to purchase energy from Dow. If the lease were renewed for up to a 30-year lease term, AEP may further renew the lease at fair market value subject to Juniper's approval, purchase the Facility at its acquisition cost, or sell the Facility, on behalf of Juniper, to an independent third party. If the Facility is sold and the proceeds from the sale are insufficient to pay all of Juniper's acquisition costs, AEP may be required to make a payment (not to exceed $396 million) to Juniper of the excess of Juniper's acquisition costs over the proceeds from the sale, provided that AEP would not be required to make any payment if AEP has made the additional rental prepayment described below. AEP has guaranteed the performance of our subsidiaries to Juniper during the lease term. Because AEP now reports the debt related to the Facility on our balance sheet, the fair value of the liability for our guarantee (the $396 million payment discussed above) is not separately reported.At December 31, 2003, Juniper's acquisition costs for the Facility totaled $496 million, and total costs for the completed Facility are currently expected to be approximately $525 million. For the 30-year extended lease term, the base lease rental is a variable rate obligation indexed to three-month LIBOR. Consequently, as market interest rates increase, the base rental payments under the lease will also increase. Annual payments of approximately $18 million represent future minimum payments for interest on Juniper's financing structure during the initial term calculated using the indexed LIBORrate (1.15% atDecember31, 2003). An additional rental prepayment (upto $396 million) maybe due on June 30, 2004 unless Juniper has refinanced its present debt financing on a long-term basis. Juniper is currently planning to refinance by June 30, 2004. The Facility is collateral for the debt obligation of Juniper. At December 31, 2003, we reflected $396 million of the $496 million recorded obligation as long-term debt due within one year. Our maximum required cash payment as a result of our financing transaction with Juniper is $396 million as well as interest payments during the lease term. Due to the treatment of the Facility as a financing of an owned asset, the recorded liability of $496 million is greater than our maximum possible cash payment obligation to Juniper.Dow will use a portion of the energy produced by the Facility and sell the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow. OPCo has also agreed to sell up to approximately 800 MWV of energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as non-conforming. OPCo entered into an agreement with an affiliate that eliminates OPCo's market exposure related to the PPA. AEP has guaranteed this affiliate's performance under the agreement. 1-7 On September 5, 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. AEP alleges that TEM has breached the PPA, and is seeking a determination of OPCo's rights under the PPA. TEM alleges that the PPA never became enforceable, or alternatively, that the PPA has already been terminated as the result of AEP breaches. If the PPA is deemed terminated or found to be unenforceable by the court, AEP could be adversely affected to the extent we are unable to find other purchasers of the power with similar contractual terms to the extent we do not fully recover claimed termination value damages from TEM. The corporate parent of TEM has provided a limited guaranty.On November 18, 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols related to the dispatching, operation and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM basically argued that in the absence of mutually agreed upon protocols there was no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the "creation of protocols" was not subject to arbitration, but did not rule upon the merits of TEM's claim that the PPA is not enforceable. If commercial operation is not achieved for purposes of the PPA by April 30, 2004, TEM may claim that it can terminate the PPA and is owed liquidating damages of approximately $17.5 million. TEM may also claim that we are not entitled to receive any termination value for the PPA.Significant Factors See the "Registrants' Combined Management's Discussion and Analysis" section beginning on page M-1 for additional discussion of factors relevant to us.Quantitative And Qualitative Disclosures About Risk Management Activities Market Risks Our risk management policies and procedures are instituted and administered at the AEP consolidated level. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about our risk management activities' effect on this specific registrant. Roll-Fonvard of MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.MTM Risk Management Contract Net Assets Year Ended December31, 2003 (in thousands) Do'mestic Power Beginning Balance December 31,2002 $94,106 (Gain) Loss from Contracts Realized/Settled During the Period (a) (38,249)Fair Value of New Contracts When Entered Into During the Period (b)Net Option Premiums Paid/(Received) (c) 106 Change in Fair Value Due to Valuation Methodology Changes Effect of EITF 98-10 Rescission (d) (4,159)Changes in Fair Value of Risk Management Contracts (e) 2,134 Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges 53,938 Net Cash Flow Hedge Contracts (g) 412 DETM Assignment (h) (24.055 Ending Balance December 31,2003 $, 1-8 (a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003.(b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location.(c)"Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003.(d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes." (e)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.(f)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.(g)"Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in Accumulated Other Comprehensive Income (Loss).(h) See Note 17 "Related Party Transactions." Maturity and Source of Fair Value of MTMI Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets Fair Value of Contracts as of December 31,2003 After 2004 2005 2006 2007 2008 2008 Total (c)(in thousands)

Prices Actively Quoted -Exchange Traded Contracts $908 $(183) $22 $142 $- $- $889 Prices Provided by Other External Sources -OTC Broker Quotes (a) 20,921 6,344 6,221 2,530 1,269 -37,285 Prices Based on Models and Other Valuation Methods (b) (4) 26 2,468 2.853 2,623 7,798 15.764 Total SS2,8226 _$15.I -n _$1.128 J5$.93B 1-9 (a) "Prices Provided by Other External Sources -OTC Broker Quotes" reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.(b)"Prices Based on Models and Other Valuation Methods" is in absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the Modeled category varies by market.(c) Amounts exclude Cash Flow Hedges.Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table still indicate the magnitude of SFAS 133 hedges we have in place. (However, given that under SFAS 133 only cash flow hedges are recorded in AOCI, the table does not provide an all-encompassing picture of our hedging activity). The table also includes a roll-forvard of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll-off of hedges). In accordance with GAAP, all amounts are presented net of related income taxes.Total Accumulated Other Comprehensive Income (Loss) Activity Year Ended December 31,2003 Domestic Foreign Power Currency Consolidated (in thousands) Beginning Balance December 31,2002 $(354) $(384) $(738)Changes in Fair Value (a) 256 -256 Reclassifications from AOCI to Net Income (b) 366 13 379 EndingBalanceDecember31,2003 $6 $(371L 103)(a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flowv hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes.(b) "Reclassifications from AOCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above.The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a$1,231 thousand gain.Credit Risk Our counterparty credit quality and exposure is generally consistent with that of AEP.1-10 VaR Associated with Risk Management Contracts The following table shows the end, high, average, ad"d iaw i4ariei isk as measured by VaR for year-to-date: December 31, 2003 (in thousands) End High Average Low$444 $1,724 $722 $172 December 31, 2002 (in thousands) End High Average Low$1,150 $3,521 $1,259 $255 VaR Associated with Debt Outstanding The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates was $214 million and $34 million at December 31, 2003 and 2002, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period, therefore a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.1-11 OHIO POWER COMPANY CONSOLIDATED CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31,2003,2002 and 2001 2003 OPERATING REVENUES Electric Generation, Transmission and Distribution Sales to AEP Affiliates TOTAL OPERATING EXPENSES Fuel for Electric Generation Purchased Electricity for Resale Purchased Electricity from AEP Affiliates Other Operation Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Income Taxes TOTAL$1,660,375 584.278 2.244.653 616,680 63,486 90,821 369,087 166,438 257,417 175,043 146.014 1.884.986 2002 (in thousands) $1,647,923 465.202 2.113,125 584,730 67,385 71,154 416,533 136,609 248,557 176,247 113,581 1.814.796 2001$1,586,739 511.366 2.098.105 686,568 63,441 62,585 400,790 142,878 239,982 159,778 101.373 1.857.395 OPERATING INCOME 359,667 298,329 240,710 Nonoperating Income Nonoperating Expenses Nonoperating Income Tax Expense (Credit)Interest Charges Income Before Extraordinary Item and Cumulative Effect Extraordinary Loss (Net of Tax)Cumulative Effect of Accounting Changes (Net of Tax)24,495 34,282 (7,615)106.464 58,289 34,903 18,010 83,682 76,341 60,035 (2,380)93.603 251,031 220,023 165,793-(18,348)124.632 NET INCOME 375,663 220,023 147,445 Preferred Stock Dividend Requirements 1.098 1,258 1.258 EARNINGS APPLICABLE TO COMMON STOCK$2183V65_$146187L The common stock of OPCo is wholly-owned by AEP.See Notes to Respective Financial Statements beginning on page L-1.1-12 OHIO POWER COMPANY CONSOLIDATED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME For the Years Ended December 31, 2003, 2002 and 2001 (in thousands) Common Stock Paid-in Capital Retained Earnines Accumulated Other Comprehensive Income (Loss)Total DECEMBER 31,2000$321,201 $462,483 $398,086$- $1,181,770 Common Stock Dividends Preferred Stock Dividends TOTAL COMPREHENSIVE INCOME Other Comprehensive Income (Loss)Net of Taxes: Unrealized Loss on Cash Flow Hedges NET INCOME TOTAL COMPREHENSIVE INCOME (142,976)(1,258)(142,976)(1.258)_1.037.536 (196)147,445 (196)147,445 147.249$11.1 82 DECEMBER 31,2001_.IL2QL _$M62A4 Common Stock Dividends Preferred Stock Dividends TOTAL COMPREHENSIVE INCOME Other Comprehensive Income (Loss)Net of Taxes: Unrealized Loss on Cash Flow Hedges Minimum Pension Liability NET INCOME TOTAL COMPREHENSIVE INCOME (97,746)(1,258)220,023 (97,746)(1.258)1,085.781 (542)(72,148)(542)(72,148)220.023 147.333 DECEMBER 31,2002.$522.316 =$(22.2 6)$1233.UA Common Stock Dividends Preferred Stock Dividends Capital Stock Gains TOTAL (167,734)(1,098)(167,734)(1,098)I 1.064,283 1 COMPREHENSIVE INCOME Other Comprehensive Income (Loss)Net of Taxes: Unrealized Gain on Cash Flow Hedges Minimum Pension Liability NET INCOME TOTAL COMPREHENSIVE INCOME 635 23,444 375,663 635 23,444 375,663 399.742$IA4645 DECEMBER31,2003 _$321.201 $4 See Notes to Respective Financial Statements beginning on page L-J.-$729,147- _2L8,L0iD 1-13 o01o POWER COMPANY CONSOLIDATED CONSOLIDATED BALANCE SHEETS ASSETS December 31, 2003 and 2002 2003 2002 (in thousands) ELECTRIC UTILITY PLANT Production Transmission Distribution General Construction \Work in Progress Total Accumulated Depreciation and Amortization TOTAL -NET$4,029,515 938,805 1,156,886 245,434 160.675 6,531,315 2,485.947 4.045,368$3,116,825 905,829 1,114,600 260,153 288.419 5,685,826 2,469.837 3.215.989 OTHER PROPERTY AND INVESTMENTS Non-Utility Property, Net Other TOTAL 29,291 24.264 53.555 29,037 32.649 61.686 CURRENT ASSETS Cash and Cash Equivalents Advances to Affiliates Accounts Receivable: Customers Affiliated Companies Miscellaneous Allowance for Uncollectible Accounts Fuel Materials and Supplies Risk Management Assets Margin Deposits Prepayments and Other TOTAL 58,250 67,918 5,285 100,960 120,532 736 (789)77,725 92,136 56,265 9,296 33.104 616.133 113,207 124,244 1,174 (909)87,409 85,379 91,872 1,636 10.683 519.980 DEFERRED DEBITS AND OTHER ASSETS Regulatory Assets: SFAS 109 Regulatory Asset, Net Transition Regulatory Assets Unamortized Loss on Reacquired Debt Other Long-term Risk Management Assets Deferred Property Taxes Deferred Charges and Other Assets TOTAL 169,605 310,035 10,172 22,506 52,825 67,469 26.850 659.462 165,106 375,409 4,899 23,227 103,230 66,621 17.876 756.368 TOTAL ASSETS See Notes to Respective Financial Statements beginning on page L-1.1-14 OHIO POWER COMPANY CONSOLIDATED CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES December31, 2003 and 2002 2003 2002 (in thousands) CAPITALIZATION Common Shareholder's Equity: Common Stock -No Par Value: Authorized -40,000,000 Shares Outstanding -27,952,473 Shares Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss)Total Common Shareholder's Equity Cumulative Preferred Stock Not Subject to Mandatory Redemption Total Shareholder's Equity Liability for Cumulative Preferred Stock Subject to Mandatory Redemption Long-term Debt: Nonaffiliated Affiliated Total Long-term Debt TOTAL$321,201 462,484 729,147 (48.807)1,464,025 16.645 1,480,670 7,250 1,608,086 1.608.086 3.096,006 16,314$321,201 462,483 522,316 (72.886)1,233,114 16.648 1,249,762 8,850 677,649 240.000 917.649 2,176.261 Minority Interest CURRENT LIABILITIES Short-term Debt -General Short-term Debt -Affiliates Long-term Debt Due Within One Year -Nonaffiliated Long-term Debt Due Within One Year -Affiliated Advances from Affiliates Accounts Payable: General Affiliated Companies Customer Deposits Taxes Accrued Interest Accrued Risk Management Liabilities Obligations Under Capital Leases Other TOTAL 25,941 431,854 104,874 101,758 17,308 132,793 45,679 38,318 9,624 71,642 979.791 275,000 89,665 60,000 129,979 170,563 145,718 12,969 111,778 18,809 61,839 14,360 80,608 1.171.288 DEFERRED CREDITS AND OTHER LIABILITIES Deferred Income Taxes Regulatory Liabilities: Asset Removal Costs Deferred Investment Tax Credits Other Long-term Risk Management Liabilities Deferred Credits Obligations Under Capital Leases Asset Retirement Obligations Other TOTAL 933,582 101,160 15,641 3 40,477 23,222 25,064 42,656 100,602 1.282.407 794,387 18,748 1,237 39,702 27,719 51,266 273.415 1.206,474 Commitments and Contingencies (Note 7)TOTAL CAPITALIZATION AND LIABILITIES See Notes to Respective Financial Statements beginning on page L-1.1-15 01O POWER COMPANY CONSOLIDATED CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended Deccmber 31, 2003, 2002 and 2001 2003 2002 (in thousands) OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities: Cumulative Effect of Accounting Changes Depreciation and Amortization Deferred Income Taxes Deferred Investment Tax Credits Extraordinary Loss Mark-to-Market of Risk Management Contracts Changes in Certain Assets and Liabilities: Accounts Receivable, Net Fuel, Materials and Supplies Accrued Utility Revenues Prepayments and Other Accounts Payable Customer Deposits Taxes Accrued Interest Accrued Employee Benefits and Other Noncurrent Liabilities Deferred Property Taxes Change in Other Assets Change in Other Liabilities Net Cash Flows From Operating Activities $375,663 (124,632)257,417 24,482 (3,107)60,064 16,335 2,927 (20,301)(13,096)(173,218)4,339 21,015 21,533 (75,822)(855)(23,302)24.001 373.443$220,023 248,557 46,010 (3,177)(28,693)14,571 704 3,081 8,783 8,704 7,517 (14,992)1,130 110,298 (1,818)(7,441)(134.284)478.973 2001$147,445 252,123 215,833 (3,289)18,348 (59,833)51,640 4,852 264 12,017 9,887 (34,284)(96,331)(2,779)(392,026)21,652 46,162 (104.925)86 756 INVESTING ACTIVITIES Construction Expenditures Proceeds from Sale of Property and Other Investment in Coal Companies Net Cash Flows Used For Investing Activities (244,312)7,301 (237.011)(354,797)6,499 (348.298)(344,571)16,778 (32,115)(359.908)FINANCING ACTIVITIES Issuance of Long-term Debt Issuance of Long-term Debt -Affiliated Change in Advances to/from Affiliates, Net Change in Short-term Debt, Net Change in Short-term Debt -Affiliates Net Retirement of Long-term Debt -Nonaffiliated Retirement of Long-term Debt -Affiliated Retirement of Cumulative Preferred Stock Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net Cash Flows From (Used For) Financing Activities Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period 988,914 (197,897)(671)(275,000)(128,378)(300,000)(1,603)(167,734)(1.098)(83.467)52,965 5,285 (170,234)275,000 (140,000)(97,746)(1.258)(134,238)(3,563)88948__$,25~300,000 392,699 (297,858)(142,976)(1.258)250,607 (22,545)31.393_$8.8 SUPPLEMENTAL DISCLOSURE: Cash paid (received) for interest net of capitalized amounts was $77,170,000, $81,041,000 and $94,747,000 and for income taxes was $98,923,000, $105,058,000 and $(22,417,000) in 2003,2002 and 2001, respectively. Noncash acquisitions under capital leases were $106,000 and $2,380,000 in 2002 and 2001, respectively. There were no noncash capital lease acquisitions in 2003. Noncash activity in 2003 included an increase in assets and liabilities of $469.6 million resulting from the consolidation of JMG (see Note 2).See Notes to Respective Financial Statements beginning on page L-1.1-16 ......01110 POWER COMPANY CONSOLIDATED CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31, 2003 and 2002 2003 2002 (in thousands) COMMON SHAREHOLDER'S EQUITY$1,46,025 $1.233,114 PREFERRED STOCK:$100 Par Value -Authorized 3,762,403 shares$25 Par Value -Authorized 4,000,000 shares Call Price December 31, Series 2003 (a)Number of Shares Redeemed Year Ended December 31.2003 2002 2001 Shares Outstanding December 31. 2003 Not Subject to Mandatory Redemption-$ 100 Par: 4.08% $103 --4.20% 103.20 --4.40% 104 --4-1/2% 110 23 -Total 14,595 22,824 31,512 97,523 1,460 2,282 3,151 9.752 16.645 1,460 2,282 3,151 9.755 16.648 Subject to Mandatory Redemption-S100 Par (b): 5.90% (c) $- --6.02% -11,000 -6.35% -5,000 -Total 72,500 7,250 7,250 1,100_ 500 7.250 8,850 LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds Installment Purchase Contracts Senior Unsecured Notes Notes Payable -Nonaffiliated Notes Payable -Affiliated Less Portion Due Within One Year 9,950 539,406 1,343,706 146,878 (43 1.854 136,633 233,340 397,341 300,000 (149.665)Long-term Debt Excluding Portion Due Within One Year 1j68986 917,649~~Q2 Q9~ $2 1l" 24 TOTAL CAPITALIZATION (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends.(b) Sinking fund provisions require the redemption of 35,000 shares in 2003 and 57,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of the due dates. Shares previously purchased may be applied to the sinking fund requirement. At the company's option, all shares are redeemable at $100 per share plus accrued and unpaid dividends with at least 30 days notice beginning on or after November 1, 2003 for the 5.90% series, October 1, 2003 for the 6.02% series, and April 1,2003 for the 6.35% series.(c) Commencing in 2004 and continuing through the year 2008, a sinking fund for the 5.90% cumulative preferred stock will require the redemption of 22,500 shares each year and the redemption of the remaining shares outstanding on January 1, 2009, in each case at $100 per share. Shares previously redeemed may be applied to meet sinking fund requirements. See Notes to Respective Financial Statements beginning on page L-1.1-17 0O110 POWER COMPANY CONSOLIDATED SCHEDULE OF LONG-TERM DEBT December 31,2003 and 2002 First Mortgage Bonds outstanding were as follows: 2003 2002% Rate Due 6.75 2003 -April 1 6.55 2003 -October 1 6.00 2003 -November 1 6.15 2003 -December 1 7.75 2023 -April 1 7.375 2023 -October 1 7.10 2023 -November 1 7.30 2024-April 1 (a)Unamortized Discount Total (in thousands) $- $29,850-27,315-12,500-20,000 5,000-20,250-12,000 10,000 10,000 (50) (282)$9.250$13-6,633 (a) This bond will be redeemed in April 2004 and has been classified for payment in 2004.First Mortgage Bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Interest payments are made semi-annually. Installment Purchase Contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: 2003 2002 (in thousands) % Rate Mason County, West Virginia: 5.45 Marshall County, \Vest Virginia: 5.45 5.90 6.85 (b)Due 2016 -December 1 2014-July 1 2022-April 1 2022-June 1 2022-June I$50,000 50,000 35,000 50,000 (a)50,000$50,000 50,000 35,000 50,000 Ohio Air Quality Development Authority: 5.15 2026-May 1 5.5625 2022 -October 1 5.5625 2023 -January I (d) 2028 -April I (e) 2028 -April 1 6.3750 2029 -January 1 6.3750 2029- April I (d) 2029 -April I (e) 2029 -April I Unamortized Discount Total 50,000 19,565 (c)19,565 (c)40,000 (c)40,000 (c)5 1,000 (c)5 1,000 (c)18,000 (c)18,000 (c)(2,724)$22,AQ 50,000 (1.660)$2n.4 1-18 (a) This amount was redeemed in January 2004 using the proceeds from the variable interest Marshall County Installment Purchase Contract issued in December 2003. As a result of the early redemption, this amount is shown as due within one year in tile debt maturity schedule.(b) A floating interest rate is determined daily. The rate on December 31, 2003 was 1.29%.(c) Due to FIN 46, OPCo wvas required to consolidate JMG during the third quarter of 2003 (see Note 2). Prior to consolidation, payments for an operating lease were made to JMG based on JMG's cost of financing (both debt and equity). As a result of the consolidation, operating lease payments were not recognized and OPCo recorded JMG's debt along with other balance sheet and income statement items. See Note 15, "Leases," for further discussion of JMG.(d) A floating interest rate is determined weekly. The rate on December 31, 2003 was 1.13%.(e) A floating interest rate is determined %veekly. The rate on December 31, 2003 was 1.20%Under the terms of the installment purchase contracts, OPCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Interest payments range from monthly to semi-annually. Senior Unsecured Notes outstanding were as follows:% Rate Due 6.75 2004 -July 1 7.00 2004 -July 1 6.73 2004 -November 1 6.24 2008 -December 4 7-3/8 2038 -June 30 (a)5.50 2013-February 15 4.85 2014 -January 15 6.60 2033-February 15 6.375 2033-July 15 Unamortized Discount Total 2003 2002 (in thousands) $100,000 $100,000 75,000 75,000 48,000 48,000 37,225 37,225 140,000 140,000 250,000 -225,000 250,000 225,000 (6.519) (2,884)$1.343,Q6 $397341 (a) This note was redeemed on March 1, 2004 and has been classified for payment in 2004.Notes Payable to parent company were as follows:% Ratc 4.336 6.501 Total Due 2003 -May 15 2006-May 15 2003 2002 (in thousands) $- $60,000-240.000 Lsm $M.0 Notes Payable to third parties outstanding were as follows:% Rate 6.81 6.27 7.49 7.21 Total Due 2008 -March 31 (a)2009 -March 31 (b)2009-April 15 2009 -June 15 (c)2003 2002 (in thousands) $24,878 (d) $-41,000 (d) -70,000 (d) -I 1.000 (d) -M$146,81 $-_1-19 (a) The terms of this note require quarterly principal payments of $5,853,659 per year through 2007 with the remaining$1,463,415 due at maturity. These payments are reflected in the debt maturity schedule.(b) The terms of this note require semi-annual principal payments of $3 million per year for the year 2004, $6.5 million per year for the years 2005 and 2006, $12 million per year for the years 2007 and 2008 with the remaining amount of$1 million due at maturity. These payments are reflected in the debt maturity schedule.(c) The terms of this note require a principal payment of $4.5 million in 2008 and the remaining amount of $6.5 million due in the year of maturity which is reflected in the debt maturity schedule.(d) Due to FIN 46, OPCo was required to consolidate JMG during the third quarter of 2003 (see Note 2). Prior to consolidation, payments for an operating lease wvere made to JMG based on JMG's cost of financing (both debt and equity). As a result of the consolidation, operating lease payments wvere not recognized and OPCo recorded JMG's debt along with other balance sheet and income statement items. See Note 15, "Leases," for further discussion of JMG.At December 31, 2003, future annual long-term debt payments are as follows: 2004 2005 2006 2007 2008 Later Years Total Principal Amount Unamortized Discount Total Amount t (in thousands) $431,854 12,354 12,354 17,853 55,188 1,519.630 2,049,233 (9.293)$2,039.9-4 1-20 01110 PONWER COMPANY CONSOLIDATED INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS The notes to OPCo's financial statements are combined with the notes to respective financial statements for other subsidiary registrants. Listed below are the notes that apply to OPCo. The footnotes begin on page L-l.Footnote Reference Organization and Summary of Significant Accounting Policies Note I New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes Note 2 Rate Matters Note 4 Effects of Regulation Note 5 Customer Choice and Industry Restructuring Note 6 Commitments and Contingencies Note 7 Guarantees Note 8 Sustained Earnings Improvement Initiative Note 9 Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used Note 10 Benefit Plans Note II Business Segments Note 12 Derivatives, Hedging and Financial Instruments Note 13 Income Taxes Note 14 Leases Note 15 Financing Activities Note 16 Related Party Transactions Note 17 Unaudited Quarterly Financial Information Note 19 1-21 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Ohio Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Ohio Power Company Consolidated as of December 31, 2003 and 2002, and the related consolidated statements of income, changes in common shareholder's equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with auditing standards generally accepted in the United States of America.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Ohio Power Company Consolidated as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.As discussed in Note 2 to the consolidated financial statements, the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations," and EITF 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," effective January 1, 2003.As discussed in Note 2 to the consolidated financial statements, the Company adopted FIN 46, "Consolidation of Variable Interest Entities," effective July 1, 2003./s/ Deloitte & Touche LLP Columbus, Ohio March 5, 2004 1-22}}

ML043380383

Text

Dear Fellow Shareholders:

4.3 Deferred

5.1 Reinvestment

5.1 Reinvestment

6.2 Manner

4.1 Participant

9.1 Nothing

1.1 Positions

3.3 Benefit

4.1 Termination

4.2 Permanent

4.4 Discharge

7.1 Nondisclosure

7.2 Restrictive

9.2 Resolution

SUMMARY

2.3 Notwithstanding

3.3 Notwithstanding

8.2 Distribution

6.5. Additional

8.5. Section

9.4. Section

SUMMARY

SUMMARY

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