PUBLIC SERVICE CO OF OKLAHOMA - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended MARCH 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from to

Commission Registrant, State of Incorporation I.R. S. Employer
File Number Address, and Telephone Number Identification No.

1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640
(A New York Corporation)
0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833
0-346 AEP TEXAS CENTRAL COMPANY (A Texas Corporation) 74-0550600
0-340 AEP TEXAS NORTH COMPANY (A Texas Corporation) 75-0646790
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA 73-0410895
(An Oklahoma Corporation)
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY 72-0323455
(A Delaware Corporation)

All Registrants 1 Riverside Plaza, Columbus, Ohio 43215-2373
Telephone (614) 223-1000

Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Sections 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

Indicate by check mark whether American Electric Power Company, Inc. is an accelerated filer (as defined in Rule 12b-2 of
the Exchange Act).

Yes X
No

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 Exchange
Act).

Yes
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 H(1)(a) and (b) of Form 10-Q and are
therefore filing this Form 10-Q with the reduced disclosure format specified in
General Instruction H(2) to Form 10-Q.

The number of shares outstanding of American Electric Power Company, Inc. Common
Stock, par value $6.50, at April 30, 2003 was 394,993,420.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

FORM 10-Q

For The Quarter Ended March 31, 2003
CONTENTS

Page
Glossary of Terms i - iii
Forward-Looking Information iv

Part I. FINANCIAL INFORMATION
Items 1 and 2 Financial Statements and Management's Discussion
and Analysis of Results of Operations:

American Electric Power Company, Inc. and Subsidiary Companies:
Management's Discussion and Analysis of Results of Operations A-1 - A-3
Consolidated Financial Statements A-4 - A-8

AEP Generating Company:
Management's Narrative Analysis of Results of Operations B-1 - B-2
Financial Statements B-3 - B-6

AEP Texas Central Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations C-1 - C-4
Consolidated Financial Statements C-5 - C-9

AEP Texas North Company:
Management's Narrative Analysis of Results of Operations D-1 - D-3
Financial Statements D-4 - D-8

Appalachian Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations E-1 - E-3
Consolidated Financial Statements E-4 - E-8

Columbus Southern Power Company and Subsidiaries:
Management's Narrative Analysis of Results of Operations F-1 - F-2
Consolidated Financial Statements F-3 - F-7

Indiana Michigan Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations G-1 - G-3
Consolidated Financial Statements G-4 - G-8

Kentucky Power Company:
Management's Narrative Analysis of Results of Operations H-1 - H-2
Financial Statements H-3 - H-7

Ohio Power Company:
Management's Discussion and Analysis of Results of Operations I-1 - I-3
Financial Statements I-4 - I-8

Public Service Company of Oklahoma and Subsidiary:
Management's Narrative Analysis of Results of Operations J-1 - J-2
Consolidated Financial Statements J-3 - J-7

Southwestern Electric Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations K-1 - K-2
Consolidated Financial Statements K-3 - K-7

Combined Notes to Financial Statements L-1 - L-33

Item 2. Registrants' Combined Management's Discussion and Analysis of
Financial Condition, Accounting Policies and Other Matters M-1 - M-14
Item 3. Quantitative and Qualitative Disclosures About Risk Management Activities N-1 - N-13
Item 4. Controls and Procedures O-1

Part II. OTHER INFORMATION
Item 5. Other Information P-1
Item 6. Exhibits and Reports on Form 8-K P-1
(a) Exhibits
Exhibit 12
Exhibit 99.1
Exhibit 99.2
(b) Reports on Form 8-K

SIGNATURES Q-1

CERTIFICATIONS R-1 - R-4

This combined Form 10-Q is separately filed by 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 and Southwestern Electric Power Company. Information
contained herein relating to any individual registrant is filed by such
registrant on its own behalf. Each registrant makes no representation as to
information relating to the other registrants.

iii
GLOSSARY OF TERMS
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............A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount
of stranded costs and the recovery of such costs.
AEGCo..............................AEP Generating Company, an electric utility subsidiary of AEP.
AEP................................American Electric Power Company, Inc.
AEP Consolidated...................AEP and its majority owned consolidated subsidiaries.
AEP Credit.........................AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
revenues for affiliated and non-affiliated domestic electric utility companies.
AEP East companies.................APCo, CSPCo, I&M, KPCo and OPCo.
AEPR...............................AEP Resources, Inc.
AEP System or the System...........The American Electric Power System, an integrated electric utility system, owned and operated
by AEP's electric utility subsidiaries.
AEPSC..............................American Electric Power Service Corporation, a service subsidiary providing management and
professional services to AEP and its subsidiaries.
AEP Power Pool.....................AEP System Power Pool. 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.
AEP West companies.................PSO, SWEPCo, TCC and TNC.
Amos Plant.........................John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.
APCo...............................Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission................Arkansas Public Service Commission.
Buckeye............................Buckeye Power, Inc., an unaffiliated corporation.
COLI...............................Corporate owned life insurance program.
Cook Plant.........................The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo..............................Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW............................... Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the
legal name of Central and South West
Corporation was changed to AEP Utilities, Inc.).
CSW Energy.........................CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.
CSW International..................CSW International, Inc., an AEP subsidiary which invests in energy projects and entities
outside the United States.
D.C. Circuit Court.................The United States Court of Appeals for the District of Columbia Circuit.
DOE................................United States Department of Energy.
ECOM...............................Excess Cost Over Market.
EITF...............................The Financial Accounting Standards Board's Emerging Issues Task Force.
EITF 02-3..........................Recognition and Reporting of Gains and Losses on Energy Contracts under Issues No. 98-10 and
00-17.
ERCOT..............................The Electric Reliability Council of Texas.
FASB...............................Financial Accounting Standards Board.
Federal EPA........................United States Environmental Protection Agency.
FERC...............................Federal Energy Regulatory Commission.
GAAP...............................Generally Accepted Accounting Principles.
I&M................................Indiana Michigan Power Company, an AEP electric utility subsidiary.
ICR................................Interchange Cost Reconstruction.
IRS................................Internal Revenue Service.
IURC...............................Indiana Utility Regulatory Commission.
ISO................................Independent System Operator.
KPCo...............................Kentucky Power Company, an AEP electric utility subsidiary.
KPSC...............................Kentucky Public Service Commission.
KWH................................Kilowatthour.
LIG................................Louisiana Intrastate Gas.
Michigan Legislation...............The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
customer choice of electricity supplier.
MISO...............................Midwest Independent System Operator (an independent operator of transmission assets in the
Midwest).
MLR................................Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool.........................AEP System's Money Pool.
MPSC...............................Michigan Public Service Commission.
MTM................................Mark-to-Market.
MW.................................Megawatt.
MWH................................Megawatthour.
NOx................................Nitrogen oxide.
NOx Rule...........................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.
NRC................................Nuclear Regulatory Commission.
OCC................................The Corporation Commission of the State of Oklahoma.
Ohio Act...........................The Ohio Electric Restructuring Act of 1999.
Ohio EPA...........................Ohio Environmental Protection Agency.
OPCo.............................. Ohio Power Company, an AEP electric utility subsidiary.
PJM................................Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO................................Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO...............................The Public Utilities Commission of Ohio.
PUCT...............................The Public Utility Commission of Texas.
PUHCA..............................Public Utility Holding Company Act of 1935, as amended.
PURPA..............................The Public Utility Regulatory Policies Act of 1978.
RCRA...............................Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries............AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
TCC and TNC.
REP................................Retail Electric Provider.
Rockport Plant.....................A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
Indiana owned by AEGCo and I&M.
RTO................................Regional Transmission Organization.
SEC................................Securities and Exchange Commission.
SFAS...............................Statement of Financial Accounting Standards issued by the Financial Accounting Standards
Board.
SFAS 71............................Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain
Types of Regulation.
SFAS 101...........................Statement of Financial Accounting Standards No. 101, Accounting for the
Discontinuance of Application of Statement 71.
SFAS 133...........................Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities.
SFAS 143...........................Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement
Obligations.
SNF................................Spent Nuclear Fuel.
SPP................................Southwest Power Pool.
STP................................South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an
AEP electric utility subsidiary.
STPNOC.............................STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of
its joint owners including TCC.
SWEPCo.............................Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC................................AEP Texas Central Company, an AEP electric utility subsidiary [formerly known as Central
Power and Light Company (CPL)].
Texas Legislation..................Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC................................AEP Texas North Company, an AEP electric utility subsidiary [formerly known as West Texas
Utilities Company (WTU)].
TVA ...............................Tennessee Valley Authority.
U.K................................The United Kingdom.
VaR................................Value at Risk, a method to quantify risk exposure.
Virginia SCC.......................Virginia State Corporation Commission.
WVPSC..............................Public Service Commission of West Virginia.
WPCo...............................Wheeling Power Company, an AEP electric distribution subsidiary.
Zimmer Plant.......................William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus
Southern Power Company, an AEP subsidiary.

iv
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:

o Electric load and customer growth.
o Abnormal weather conditions.
o Available sources and costs of fuels.
o Availability of generating capacity.
o The speed and degree to which competition is introduced to our service
territories.
o The ability to recover stranded costs in connection with
possible/proposed deregulation.
o New legislation and government regulation.
o Oversight and/or investigation of the energy sector or
its participants.
o Our ability to successfully control costs.
o The success of acquiring new business ventures and disposing of
existing investments that no longer match our corporate profile.
o International and country-specific developments affecting foreign
investments including the disposition of any current foreign
investments and potential additional foreign investments.
o The economic climate and growth in our service territory and
changes in market demand and demographic patterns.
o Inflationary trends.
o Electricity and gas market prices.
o Interest rates.
o Liquidity in the banking, capital and wholesale power markets.
o Actions of rating agencies.
o Changes in technology, including the increased use of distributed
generation within our transmission and distribution service territory.
o Other risks and unforeseen events, including wars, the effects of terrorism,
embargoes and other catastrophic events.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

FIRST QUARTER 2003 vs. FIRST QUARTER 2002

American Electric Power Company, Inc.'s principal operating business segments
and their major activities are:

Utility Operations
oDomestic generation of electricity for sale to retail
and wholesale customers
oDomestic electricity transmission and distribution

Investments - Gas Operations
oGas pipeline and storage services

Investments - UK Operations
oInternational generation of electricity for sale to wholesale customers

Investments - Other
oCoal mining, bulk commodity barging operations and other
energy supply businesses

o
Results of Operations

Net Income of $440 million or $1.24 per share in the first quarter of 2003
included $193 million of Income from Cumulative Effect of Accounting Changes
(see Note 3). Income Before Discontinued Operations and Cumulative Effect
increased $97 million or 61% due to improved earnings from system sales
resulting from the interactions of plant availability, the colder winter weather
and higher margins.

Changes in Revenues

AEP's total revenue increased 36% in the first quarter of 2003. The following
table shows the components of revenue.
Increase (Decrease)
(in millions) %
REVENUES:
Electric Generation $ 441 31
Electric Transmission and
Distribution 74 9
Gas Pipeline and Storage 669 155
Investments ( 96) (32)
TOTAL REVENUES $ 1,088 36

The increase in revenues was primarily due to higher levels of Electric
Generation and Electric Transmission and Distribution resulting from plant
availability and the colder winter weather as well as the higher revenue from
Gas Pipeline and Storage sales resulting primarily from higher prices. Heating
degree days were up 20% which resulted in higher residential KWH sales of 4%.
System sales volume increased 10% to 7,681 gigawatt hours. Higher gas prices
were caused by the decreasing availability of gas. Fuel inventories at gas
storage facilities were reduced to low levels reflecting the colder winter
weather compared to 2002. Investment revenues decreased 32% due to the completed
construction of a gas-fired plant for a third party in the summer of 2002 and a
reduction in U.K. operating margins due to market conditions.

Changes in Expenses

Increase (Decrease)
(in millions) %
EXPENSES:
Fuel for Electric Generation $ 39 6
Purchased Electricity for Resale 176 N.M.
Purchased Gas for Resale 795 225
Maintenance and Other Operation (43) (4)
Depreciation and Amortization (17) (5)
Taxes Other Than Income Taxes (3) (2)

TOTAL OPERATING EXPENSES $947 37

N.M. = Not Meaningful

The increase in Fuel for Electric Generation includes the effect of an increase
in AEP's domestic net generation of 6% and higher generation output of 31% in
the U.K. operation. The increase in Purchased Electricity for Resale expense was
primarily attributable to an increase in MWH purchased to meet the demand.
Purchased Gas for Resale increased due primarily to higher market prices.

Maintenance and Other Operation expense decreased primarily due to the effect of
material and labor costs related to the construction of a gas-fired plant for a
third party that was completed in 2002. Project fees for the construction of the
gas-fired plant for a third party were recognized in revenues on a percentage of
completion method, consequently, the decrease in expense for material and labor
cost does not affect net income. In addition, payroll expense decreased due in
part to personnel reductions in late 2002. These decreases were partially offset
by increases in U.K. operational expenses, pension and postretirement benefits
expense, accretion expense related to asset retirement obligations (ARO) SFAS
143 (see Note 2 and explanation of decrease in Depreciation and Amortization
expense below) and nuclear refueling outage amortization expenses.

The decrease in Depreciation and Amortization expense is primarily due to the
adoption of SFAS 143 for certain subsidiary utility companies effective January
1, 2003. Effective January 1, 2003 the generation depreciation rate for certain
non-regulated jurisdictions was reduced to exclude the non-ARO removal cost
portion that was included in the depreciation rate. In addition, certain
amortization related to nuclear decommissioning costs was reclassified as ARO
accretion expense which is included in Maintenance and Other Operations expense.
Additionally, APCo reduced its Depreciation and Amortization expense related to
the amortization of generation related regulatory assets due to the return to
SFAS 71 regulatory accounting for the West Virginia jurisdiction (see Note 6 for
further discussion of the return to SFAS 71 regulatory accounting).

Other Income and Other Expenses

Other Income includes non-operating revenue including non-utility revenue
associated with energy related projects for customers, equity earnings of
non-consolidated subsidiaries, a gain on the sale of our customer care
operations in Texas, and interest and miscellaneous income.

Other Expenses includes non-utility expenses associated with energy related
projects for customers, losses on dispositions of property, donations and
various other non-operating and miscellaneous expenses.

Other Income increased mainly due to a gain of $39 million on the sale of our
customer care operations in Texas and an increase in miscellaneous income. In
the first quarter of 2003, AEP sold Mutual Energy Service Company, a customer
care operation which was created to serve retail customers in the deregulated
Texas market, to Alliance Data Systems. This sale continues our exit of the
retail electric supply business in Texas and refocuses our resources on
wholesale generation and power supply markets. Miscellaneous income increased
due to additional contracts for the staffing of nonassociated companies'
outages. Other Expenses increased due to increased non-utility expenses
associated with energy related construction projects for third parties.

Other Changes

The increase in Income Taxes is due to an increase in pre-tax income and the tax
effects of foreign operations.

The increase in Interest was primarily due to an increase in outstanding
balances of long-term debt in the first quarter of 2003. The increase was
partially offset by a decrease in short-term debt interest expense due to a
decrease in outstanding balances of short-term debt in the first quarter of
2003.

Cumulative Effect of Accounting 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
Notes 2 and 3).

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per-share amounts)
(UNAUDITED)
Three Months Ended March 31,
2003 2002

REVENUES:

Electric Generation $1,863 $ 1,422
Electric Transmission and Distribution 910 836
Gas Pipeline and Storage 1,102 433
Investments 205 301
TOTAL REVENUES 4,080 2,992
EXPENSES:
Fuel for Electric Generation 660 621
Purchased Electricity for Resale 205 29
Purchased Gas for Resale 1,149 354
Maintenance and Other Operation 963 1,006
Depreciation and Amortization 315 332
Taxes Other Than Income Taxes 188 191
TOTAL EXPENSES 3,480 2,533

OPERATING INCOME 600 459

OTHER INCOME 118 12

OTHER EXPENSES 45 20

LESS: INTEREST 205 195

PREFERRED STOCK DIVIDEND REQUIREMENTS OF
SUBSIDIARIES
3 2

MINORITY INTEREST IN FINANCE SUBSIDIARY 9 9

INCOME BEFORE INCOME TAXES 456 245
INCOME TAXES 200 86
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE
EFFECT 256 159
DISCONTINUED OPERATIONS (LOSS) INCOME (NET OF TAX) (9) 22
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX):
Goodwill and Other Intangible Assets - (350)
Accounting for Risk Management Contracts (49) -
Asset Retirement Obligation 242 -

NET INCOME (LOSS) $ 440 $ (169)

AVERAGE NUMBER OF SHARES OUTSTANDING 356 322

EARNINGS (LOSS) PER SHARE:
Income Before Discontinued Operations and
Cumulative Effect of Accounting Changes
$ 0.72 $ 0.49
Discontinued Operations (0.02) 0.07
Cumulative Effect of Accounting Changes 0.54 (1.08)

Earnings (Loss) Per Share (Basic and Diluted) $ 1.24 $(0.52)

CASH DIVIDENDS PAID PER SHARE $ 0.60 $ 0.60

See Notes to Consolidated Financial Statements beginning on page L-1.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in millions)
ASSETS

CURRENT ASSETS:

Cash and Cash Equivalents $ 1,764 $ 1,213
Accounts Receivable (net) 2,572 1,740
Fuel, Materials and Supplies 966 1,166
Risk Management Assets 1,105 1,012
Other 1,037 935

TOTAL CURRENT ASSETS 7,444 6,066

PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production 17,239 17,031
Transmission 5,909 5,882
Distribution 9,585 9,573
Other (including gas, coal mining and
nuclear fuel) 3,911 3,965
Construction Work in Progress 1,510 1,406
Total Property, Plant and Equipment 38,154 37,857
Accumulated Depreciation and Amortization 15,826 16,173

NET PROPERTY, PLANT AND EQUIPMENT 22,328 21,684

REGULATORY ASSETS 2,669 2,688

SECURITIZED TRANSITION ASSETS 726 735

INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS 291 283

GOODWILL 396 396

ASSETS HELD FOR SALE 280 292

LONG-TERM RISK MANAGEMENT ASSETS 812 819

OTHER ASSETS 1,955 1,783

TOTAL ASSETS $36,901 $34,746

See Notes to Consolidated Financial Statements beginning on page L-1.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:

Accounts Payable $ 2,930 $ 2,030
Short-term Debt 239 3,164
Long-term Debt Due Within One Year 1,696 1,633
Risk Management Liabilities 1,268 1,113
Other 2,020 1,802

TOTAL CURRENT LIABILITIES 8,153 9,742

LONG-TERM DEBT 10,436 8,487

EQUITY UNIT SENIOR NOTES 376 376

LONG-TERM RISK MANAGEMENT LIABILITIES 543 481

DEFERRED INCOME TAXES 4,037 3,916

DEFERRED INVESTMENT TAX CREDITS 448 455

DEFERRED CREDITS AND REGULATORY LIABILITIES 830 770

DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 183 185

LIABILITIES HELD FOR SALE 161 142

OTHER NONCURRENT LIABILITIES 2,073 1,903

COMMITMENTS AND CONTINGENCIES (Note 7)

CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE,
PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING
SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH
SUBSIDIARIES 321 321

MINORITY INTEREST IN FINANCE SUBSIDIARY 759 759

CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES 144 145

COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50:
2003 2002
Shares Authorized.. . 600,000,000 600,000,000
Shares Issued. . . . .403,993,412 347,835,212
(8,999,992 shares were held in treasury at
March 31, 2003 and December 31, 2002) 2,626 2,261
Paid-in Capital 4,175 3,413
Accumulated Other Comprehensive Income (Loss) (602) (609)
Retained Earnings 2,238 1,999
TOTAL COMMON SHAREHOLDERS' EQUITY 8,437 7,064

TOTAL LIABILITIES AND SHAREHOLDERS'EQUITY
$36,901 $34,746

See Notes to Consolidated Financial Statements beginning on page L-1.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in millions)
OPERATING ACTIVITIES:

Net Income (Loss) $ 440 $(169)
Plus: Discontinued Operations 9 (22)
Net Income from Continuing Operations 449 (191)
Adjustments for Noncash Items:
Depreciation and Amortization 315 336
Deferred Income Taxes 27 (59)
Deferred Investment Tax Credits (7) (9)
Cumulative Effect of Accounting Changes (193) 350
(Gain)/Loss on Sale of Assets (36) -
Mark to Market of Risk Management Contracts 69 158
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (834) (796)
Fuel, Materials and Supplies 165 101
Accrued Utility Revenues (48) (51)
Prepayments and Other (74) (49)
Accounts Payable 905 43
Taxes Accrued 196 12
Interest Accrued 29 94
Rent Accrued - Rockport Plant Unit 2 37 37
Over/Under Fuel Recovery 74 (31)
Change in Other Assets (209) (341)
Change in Other Liabilities (90) 376
Net Cash Flows From (Used For) Operating Activities 775 (20)

INVESTING ACTIVITIES:
Construction Expenditures (324) (300)
Proceeds from Sale of Assets 35 -
Other - (32)
Net Cash Flows Used For Investing Activities (289) (332)

FINANCING ACTIVITIES:
Issuance of Common Stock 1,177 14
Issuance of Long-term Debt 2,525 872
Change in Short-term Debt (net) (2,925) (49)
Retirement of Long-term Debt (509) (295)
Dividends Paid on Common Stock (203) (193)
Net Cash Flows From Financing Activities 65 349

Effect of Exchange Rate Change on Cash - (14)

Net Increase (Decrease) in Cash and Cash Equivalents 551 (17)
Cash and Cash Equivalents at Beginning of Period 1,213 224
Cash and Cash Equivalents at End of Period $1,764 $ 207
Net Decrease in Cash and Cash Equivalents from Discontinued Operations
$ (3) $ (9)
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period
8 108
Cash and Cash Equivalents from Discontinued Operations - End of Period
$ 5 $ 99

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $177 million and $126
million in 2003 and 2002, respectively. There was no cash paid for income taxes
in 2003. Cash paid for income taxes in 2002 was $94 million.

See Notes to Consolidated Financial Statements beginning on page L-1.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
(in millions)

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

JANUARY 1, 2002 $2,153 $2,906 $3,296 $(126) $8,229

Issuance of Common Stock 3 3
Common Stock Dividends (193) (193)
Other 6 4 10
8,049
Comprehensive Income (Loss):
Other Comprehensive Income (Loss),
Net of Taxes
Foreign Currency Translation Adjustments
(6) (6)
Unrealized Losses on Cash Flow
Hedges (38) (38)
Net Loss (169) (169)
Total Comprehensive Income (Loss) (213)

MARCH 31, 2002 $2,156 $2,912 $2,938 $(170) $7,836

JANUARY 1, 2003 $2,261 $3,413 $1,999 $(609) $7,064

Issuance of Common Stock 365 812 1,177
Common Stock Dividends (203) (203)
Common Stock Expense (35) (35)
Other (15) 2 (13)
7,990
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes
Foreign Currency Translation Adjustments
13 13
Unrealized Gains on Securities 1 1
Unrealized Losses on Cash Flow Hedges
(22) (22)
Minimum Pension Liability 15 15
Net Income 440 440
Total Comprehensive Income 447

MARCH 31, 2003 $2,626 $4,175 $2,238 $(602) $8,437
See Notes to Consolidated Financial Statements beginning on page L-1.

AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

FIRST QUARTER 2003 vs. FIRST QUARTER 2002

AEGCo is engaged in the generation and wholesale sale of electric power to two
affiliates under long-term agreements. Operating revenues are derived from the
sale of Rockport Plant energy and capacity to two affiliated companies pursuant
to FERC approved long-term unit power agreements. The unit power agreements
provide for recovery of costs including a FERC approved rate of return on common
equity and a return on other capital net of temporary cash investments.

Results of Operations
Net Income declined $97 thousand or 5% for the first quarter of 2003 as a result
of terms in the unit power agreements which limits recovery of return on capital
related to operating and in-service ratios of the Rockport Plant calculated and
adjusted monthly.

Changes in Operating Revenues
An increase in Operating Revenues of $10.6 million resulted from an increase in
recoverable expenses, primarily fuel, as generation increased 50% due to an
increase in the Rockport Plant's availability during 2003. Outages for planned
maintenance at both units decreased the Rockport Plant's generation in 2002.

Changes in Operating Expenses Operating expenses increased 22% as follows:

Increase (Decrease)
(in thousands) %

Fuel for Electric Generation $12,897 74
Rent - Rockport Plant
Unit 2 - -
Other Operation (673) (21)
Maintenance (1,325) (45)
Depreciation (12) -
Taxes Other Than Income
Taxes (262) (25)
Income Taxes (156) (24)
Total Operating Expenses $10,469 22

Fuel for Electric Generation expense increased due to a 50% increase in
generation in 2003. Planned maintenance outages during the first quarter of 2002
reduced the Rockport Plant's availability and generation in 2002.

The decreases in Other Operation and Maintenance expenses are primarily due to
higher costs incurred during the 2002 plant outages.

The decrease in Taxes Other Than Income Taxes reflects a decline in the accrual
of real and personal property tax for Indiana for the Rockport Plant, reflecting
a favorable change in the law effective March 2002.

Income Taxes attributable to operations decreased primarily due to a decrease in
pre-tax operating income and a decrease in accrued state income.

Other Changes

The increase in Nonoperating Expense reflects additional expenses related to a
construction project.

AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)

OPERATING REVENUES $60,428 $49,875

OPERATING EXPENSES:
Fuel for Electric Generation 30,397 17,500
Rent - Rockport Plant Unit 2 17,071 17,071
Other Operation 2,549 3,222
Maintenance 1,651 2,976
Depreciation 5,621 5,633
Taxes Other Than Income Taxes 791 1,053
Income Taxes 497 653

TOTAL OPERATING EXPENSES 58,577 48,108

OPERATING INCOME 1,851 1,767

NONOPERATING INCOME 2 2

NONOPERATING EXPENSES 217 12

NONOPERATING INCOME TAX CREDITS 894 832

INTEREST CHARGES 734 696

NET INCOME $ 1,796 $ 1,893

STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)

BALANCE AT BEGINNING OF PERIOD $18,163 $13,761

NET INCOME 1,796 1,893

CASH DIVIDENDS DECLARED 1,171 1,050

BALANCE AT END OF PERIOD $18,788 $14,604

The common stock of AEGCo is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.

AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)
ASSETS

ELECTRIC UTILITY PLANT:

Production $638,481 $637,095
General 4,643 4,728
Construction Work in Progress 10,707 10,390
Total Electric Utility Plant 653,831 652,213
Accumulated Depreciation 364,316 358,174
NET ELECTRIC UTILITY PLANT 289,515 294,039

OTHER PROPERTY AND INVESTMENTS 119 119

CURRENT ASSETS:
Accounts Receivable - Affiliated Companies 21,583 18,454
Fuel 18,005 20,260
Materials and Supplies 4,859 4,913
Prepayments 73 -
TOTAL CURRENT ASSETS 44,520 43,627

REGULATORY ASSETS 5,701 4,970

DEFERRED CHARGES 9,297 6,974

TOTAL ASSETS $349,152 $349,729

See Notes to Financial Statements beginning on page L-1.

AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:

Common Stock - Par Value $1,000:
Authorized and Outstanding - 1,000 Shares $ 1,000 $ 1,000
Paid-in Capital 23,434 23,434
Retained Earnings 18,788 18,163
Total Common Shareholder's Equity 43,222 42,597
Long-term Debt 44,804 44,802

TOTAL CAPITALIZATION 88,026 87,399

OTHER NONCURRENT LIABILITIES 1,333 301

CURRENT LIABILITIES:
Advances from Affiliates 9,650 28,034
Accounts Payable:
General - 26
Affiliated Companies 12,585 15,907
Taxes Accrued 7,294 2,327
Rent Accrued - Rockport Plant Unit 2 23,427 4,963
Other 633 1,111
TOTAL CURRENT LIABILITIES 53,589 52,368

DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT
PLANT UNIT 2 109,654 111,046

REGULATORY LIABILITIES:
Deferred Investment Tax Credit 52,108 52,943
Amounts Due to Customers for Income Taxes 16,143 16,670
TOTAL REGULATORY LIABILITIES 68,251 69,613

DEFERRED INCOME TAXES 28,299 29,002

COMMITMENTS AND CONTINGENCIES (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES $349,152 $349,729

See Notes to Financial Statements beginning on page L-1.

AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING ACTIVITIES:

Net Income $ 1,796 $ 1,893
Adjustment for Noncash Items:
Depreciation 5,621 5,633
Deferred Income Taxes (1,230) (1,470)
Deferred Investment Tax Credits (835) (835)
Amortization of Deferred Gain on Sale and Leaseback -
Rockport Plant Unit 2 (1,392) (1,392)
Deferred Property Taxes (2,329) (2,693)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (3,129) 1,337
Fuel, Materials and Supplies 2,309 (1,214)
Accounts Payable (3,348) (1,221)
Taxes Accrued 4,967 5,529
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Change in Other Assets (1,021) 586
Change in Other Liabilities 554 (545)

Net Cash Flow From Operating Activities 20,427 24,072

INVESTING ACTIVITIES - Construction Expenditures (872) (4,282)

FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) (18,384) (15,511)
Dividends Paid (1,171) (1,050)
Net Cash Flows Used For Financing Activities (19,555) (16,561)

Net Increase in Cash and Cash Equivalents - 3,229
Cash and Cash Equivalents at Beginning of Period - 983
Cash and Cash Equivalents at End of Period $ - $ 4,212

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $1,123,000 and
$1,108,000 and for income taxes was $(384,000) and $176,000 in 2003 and 2002,
respectively.

See Notes to Financial Statements beginning on page L-1.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

FIRST QUARTER 2003 vs. FIRST QUARTER 2002

AEP Texas Central Company (TCC), formerly known as Central Power and Light
Company (CPL), is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power in southern Texas. TCC sells
electric power to utilities, municipalities, rural electric cooperatives and
beginning in 2002 to retail electric providers (REPs) in Texas.

Wholesale risk management activities are conducted on TCC's behalf by AEPSC.
TCC, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.

On January 1, 2002, customer choice of electricity supplier began in the
Electric Reliability Council of Texas (ERCOT) area of Texas where TCC operates.

Under the Texas Restructuring Legislation, each electric utility was required to
submit a plan to structurally unbundle its business into an affiliated REP, a
power generator, and a transmission and distribution utility. During the year
2000, TCC submitted a plan for separation that was subsequently approved by the
PUCT. TCC functionally separated its generation from its transmission and
distribution operations and AEP formed separate affiliated REPs, Mutual Energy
CPL and AEP Texas Commercial & Industrial Retail Limited Partnership. Mutual
Energy CPL provides default electric service to residential and small commercial
customers (customers eligible for price-to-beat rates). AEP Texas Commercial &
Industrial Retail Limited Partnership provides default electric service to large
commercial and industrial customers not eligible for price- to-beat rates.
Mutual Energy CPL, a separate legal entity that was an AEP subsidiary (not owned
by or consolidated with TCC), was sold in December 2002.

Since REPs are the electricity suppliers to retail customers in the ERCOT area,
TCC sells its generation to the REPs and other market participants and provides
transmission and distribution services to retail customers of the REPs in the
TCC service territory. As a result of the provision of retail electric service
by REPs, effective January 1, 2002, TCC no longer supplies electricity directly
to retail customers. The implementation of REPs as suppliers to retail customers
has caused a significant shift in TCC's sales as further described below under
"Results of Operations."

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 with Mutual Energy CPL
are classified as Electric Generation and delivery charges as Electric
Transmission and Distribution.

Results of Operations
In 2003 Net Income increased $40 million or 164% driven by a $56 million ($36
million, net of tax) increase in revenues associated with recognition of
stranded costs in Texas, and a $5.0 million ($3.2 million, net of tax) increase
in profits on derivative contracts.

Changes in Operating Revenues

Increase (Decrease)
(in millions) %

Electric Generation $166.4 198
Electric Transmission and Distribution
124.9 346
Sales to AEP Affiliates (141.9) (89)
Total Operating Revenues $149.4 54

In 2003, Electric Generation revenues increased due to the reclassification of
energy revenues as a result of the sale of Mutual Energy CPL in December 2002,
discussed above, and increased MWH sales at higher prices, and increased
revenues from ERCOT of $77 million. These revenues were offset in part by a
decrease in average electric rates, as 2002 included a transition period which
included fuel revenue collections from retail customers; and a reduction of $27
million resulting from a provision for rate refund (see Note 5).

Additionally, delivery charges provided to Mutual Energy CPL are classified as
Sales to AEP Affiliates in 2002, whereas in 2003 they are classified as
Electricity Transmission and Distribution revenue. Actual delivered MWHs
increased in 2003. Revenues for 2003 include $56 million of revenue associated
with recognition of stranded costs in Texas (see Note 6). Electric Transmission
and Distribution revenue also included revenues received for securitized assets
beginning in February 2002 and revenues from ERCOT for system management
services.

In 2003, Sales to AEP Affiliates decreased primarily due to the reclassification
of revenues as a result of the sale of Mutual Energy CPL in December 2002,
discussed above.

Changes in Operating Expenses

Increase (Decrease)
(in millions) %

Fuel for Electric Generation $ 0.3 1
Fuel from Affiliates for Electric Generation
11.0 40
Purchased Electricity for Resale 68.1 N.M.
Purchased Electricity from AEP Affiliates
3.6 46
Other Operation 3.4 5
Maintenance 5.2 47
Depreciation and Amortization 2.2 5
Taxes Other Than Income Taxes (4.9) (18)
Income Taxes 24.0 229
Total Operating Expenses $112.9 51

N.M. = Not meaningful

The increase in total fuel expense was due to an increase in the average unit
cost of fuel offset in part by decreased MWH generation. The increase in the
average unit cost was due to gas generation as the per unit cost of gas more
than doubled from 2002 to 2003, while the actual gas MWH generation decreased
due to the mothballing of several gas plants in late 2002. Nuclear generation
decreased due to outages at the STP nuclear plant during the first quarter of
2003. See Note 7 for further information regarding the outage at the STP nuclear
plant.

The increase in total purchased electricity expense in 2003 was mainly due to
increased MWHs purchased as a result of the mothballed plants, the STP outage
and higher open market purchase prices.

Other Operation expense increased due primarily to the accretion expense for
nuclear decommissioning associated with the adoption of SFAS 143 (see Note 2). A
corresponding offsetting decrease in Depreciation and Amortization is also a
result of the adoption of SFAS 143. See Depreciation and Amortization
explanation below.

Maintenance expense increased due to an unscheduled outage at one of the nuclear
units and a refueling outage at the other nuclear unit (see Note 7).

The increase in Depreciation and Amortization is attributable to the absence in
2003 of an excess earnings favorable true-up adjustment offset in part by
reduced expense attributable to the adoption of SFAS 143, the amortization of
regulatory assets associated with the securitization during the first quarter of
2002 and decreased depreciation due to several plants mothballed during late
2002.

The decrease in Taxes Other Than Income Taxes resulted primarily from decreased
gross receipts tax, due to deregulation.

The increase in Income Taxes is due to an increase in pre-tax income.

Other Changes

Nonoperating Income increased as a result of premium payments on derivative
contracts, offset in part by decreased non-utility revenue associated with
energy related construction projects for third parties. Nonoperating Expenses
also decreased due to lower expenses associated with energy related construction
projects for third parties.

Cumulative Effect of Accounting Change

This amount represents the one-time after-tax effect of the application of EITF
02-3 (see Notes 2 and 3).

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:

Electric Generation $250,377 $ 83,988
Electric Transmission and Distribution 161,006 36,060
Sales to AEP Affiliates 16,975 158,862
TOTAL OPERATING REVENUES 428,358 278,910

OPERATING EXPENSES:
Fuel for Electric Generation 27,339 26,989
Fuel from Affiliates for Electric Generation 38,289 27,339
Purchased Electricity for Resale 72,122 4,012
Purchased Electricity from AEP Affiliates 11,562 7,927
Other Operation 69,402 65,986
Maintenance 16,099 10,959
Depreciation and Amortization 44,073 41,847
Taxes Other Than Income Taxes 22,979 27,922
Income Taxes 34,483 10,484
TOTAL OPERATING EXPENSES 336,348 223,465

OPERATING INCOME 92,010 55,445

NONOPERATING INCOME 10,162 9,531

NONOPERATING EXPENSES 5,195 9,387

NONOPERATING INCOME TAX EXPENSE 558 133

INTEREST CHARGES 31,982 31,011

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 64,437 24,445

CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX)
122 -

NET INCOME 64,559 24,445

PREFERRED STOCK DIVIDEND REQUIREMENTS 60 60

EARNINGS APPLICABLE TO COMMON STOCK $ 64,499 $ 24,385

The common stock of TCC is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)

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

JANUARY 1, 2002 $168,888 $405,015 $826,197 $ - $1,400,100
Redemption of Common Stock (113,596) (272,409) (386,005)
Common Stock Dividends (38,502) (38,502)
Preferred Stock Dividends (60) (60)
975,533
Comprehensive Income:
Other Comprehensive Income - -
Net Income 24,445 24,445
Total Comprehensive Income 24,445

MARCH 31, 2002 $ 55,292 $132,606 $812,080 $ - $ 999,978

JANUARY 1, 2003 $ 55,292 $132,606 $986,396 $(73,160) $1,101,134
Common Stock Dividends (30,201) (30,201)
Preferred Stock Dividends (60) (60)
1,070,873
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (1,018) (1,018)
Net Income 64,559 64,559
Total Comprehensive Income 63,541

MARCH 31, 2003 $ 55,292 $132,606 $1,020,694 $(74,178) $1,134,414

See Notes to Financial Statements beginning on page L-1.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, December 31,
2003 2002
(in thousands)
ASSETS

ELECTRIC UTILITY PLANT:

Production $2,977,890 $2,903,942
Transmission 715,195 698,964
Distribution 1,305,884 1,296,731
General 260,834 258,386
Construction Work in Progress 180,178 200,947
Nuclear Fuel 270,521 266,766
Total Electric Utility Plant 5,710,502 5,625,736
Accumulated Depreciation and Amortization 2,356,530 2,405,492
NET ELECTRIC UTILITY PLANT 3,353,972 3,220,244

OTHER PROPERTY AND INVESTMENTS 4,219 3,977

SECURITIZED TRANSITION ASSETS 725,597 734,591

LONG-TERM RISK MANAGEMENT ASSETS 11,547 4,392

CURRENT ASSETS:
Cash and Cash Equivalents 32,796 85,420
Advances to Affiliates 18,346 -
Accounts Receivable:
General 190,905 113,543
Affiliated Companies 110,291 121,324
Allowance for Uncollectible Accounts (230) (346)
Fuel Inventory 22,103 32,563
Materials and Supplies 47,220 51,593
Accrued Utility Revenues 27,540 27,150
Risk Management Assets 21,395 22,493
Prepayments and Other Current Assets 4,769 2,133
TOTAL CURRENT ASSETS 475,135 455,873

REGULATORY ASSETS 570,058 458,552

REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION
321,156 336,444

NUCLEAR DECOMMISSIONING TRUST FUND 97,128 98,474

DEFERRED CHARGES 88,896 43,891

TOTAL ASSETS $5,647,708 $5,356,438

See Notes to Financial Statements beginning on page L-1.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, December 31,
2003 2002
(in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 12,000,000 Shares
Outstanding - 2,211,678 Shares $ 55,292 $ 55,292
Paid-in Capital 132,606 132,606
Accumulated Other Comprehensive Income (Loss) (74,178) (73,160)
Retained Earnings 1,020,694 986,396
Total Common Shareholder's Equity 1,134,414 1,101,134
Preferred Stock 5,942 5,942
CPL - Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely
Junior Subordinated Debentures of TCC 136,250 136,250

Long-term Debt 1,980,640 1,209,434
TOTAL CAPITALIZATION 3,257,246 2,452,760

OTHER NONCURRENT LIABILITIES 309,028 74,572

CURRENT LIABILITIES:
Short-term Debt - Affiliates - 650,000
Long-term Debt Due Within One Year 209,705 229,131
Advances from Affiliates (net) - 126,711
Accounts Payable - General 81,997 72,199
Accounts Payable - Affiliated Companies 65,725 36,242
Customer Deposits 1,803 666
Taxes Accrued 94,315 24,791
Interest Accrued 24,920 51,205
Risk Management Liabilities 28,334 19,811
Other 18,142 36,698

TOTAL CURRENT LIABILITIES 524,941 1,247,454

DEFERRED INCOME TAXES 1,239,961 1,261,252

DEFERRED INVESTMENT TAX CREDITS 116,384 117,686

LONG-TERM RISK MANAGEMENT LIABILITIES 5,824 1,713

REGULATORY LIABILITIES AND DEFERRED CREDITS 194,324 201,001

COMMITMENTS AND CONTINGENCIES (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES $5,647,708 $5,356,438

See Notes to Financial Statements beginning on page L-1.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING ACTIVITIES:

Net Income $ 64,559 $ 24,445
Adjustments to Reconcile Net Income to Net Cash Flows
From (Used For) Operating Activities:
Depreciation and Amortization 44,073 41,847
Deferred Income Taxes (2,260) (8,083)
Deferred Investment Tax Credits (1,302) (1,302)
Cumulative Effect of Accounting Change (122) -
Mark-to-Market of Risk Management Contracts 5,197 6,466
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (66,445) (69,400)
Fuel, Materials and Supplies 14,833 (1,359)
Interest Accrued (26,285) 8,942
Accrued Utility Revenue (390) (4,458)
Accounts Payable 39,281 (28,577)
Taxes Accrued 69,524 17,767
Deferred Property Tax (31,590) (32,899)
Change in Other Assets (51,108) (20,966)
Change in Other Liabilities (15,185) (19,726)
Net Cash Flows From (Used For) Operating Activities 42,780 (87,303)

INVESTING ACTIVITIES:
Construction Expenditures (21,851) (21,002)
Other - -
Net Cash Flows Used For Investing Activities (21,851) (21,002)

FINANCING ACTIVITIES:
Change in Short-term Debt Affiliated (Net) (650,000) -
Issuance of Long-term Debt 800,000 796,613
Retirement of Long-term Debt (48,235) (149,998)
Change in Advances to/from Affiliates (Net) (145,057) (115,447)
Retirement of Common Stock - (386,004)
Dividends Paid on Common Stock (30,201) (38,502)
Dividends Paid on Cumulative Preferred Stock (60) (60)
Net Cash Flows From (Used For) Financing Activities (73,553) 106,602

Net Decrease in Cash and Cash Equivalents (52,624) (1,703)
Cash and Cash Equivalents at Beginning of Period 85,420 10,909
Cash and Cash Equivalents at End of Period $ 32,796 $ 9,206

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $55,483,000 and
$18,505,000 and for income taxes was $(22,959,000) and $18,482,000 in 2003 and
2002, respectively.

See Notes to Financial Statements beginning on page L-1.

AEP TEXAS NORTH COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2003 vs. FIRST QUARTER 2002

AEP Texas North Company (TNC), formerly known as West Texas Utilities Company
(WTU), is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power in west and central Texas. TNC
sells electric power to utilities, municipalities, rural electric cooperatives
and beginning in 2002 to retail electric providers (REPs) in Texas.

Wholesale risk management activities are conducted on TNC's behalf by AEPSC.
TNC, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.

On January 1, 2002, customer choice of electricity supplier began in the
Electric Reliability Council of Texas (ERCOT) area of Texas. TNC operates in
both the ERCOT and Southwest Power Pool (SPP) regions of Texas, with the
majority of its operations being in the ERCOT territory.

Under the Texas Restructuring Legislation, each electric utility was required to
submit a plan to structurally unbundle its business into an affiliated REP, a
power generator, and a transmission and distribution utility. During the year
2000, TNC submitted a plan for separation that was subsequently approved by the
PUCT. TNC functionally separated its generation from its transmission and
distribution operations and AEP formed separate affiliated REPs, Mutual Energy
WTU and AEP Texas Commercial & Industrial Retail Limited Partnership. Mutual
Energy WTU provides default electric service to residential and small commercial
customers (customers eligible for price-to-beat rates). AEP Texas Commercial &
Industrial Retail Limited Partnership provides default electric service to large
commercial and industrial customers not eligible for price- to-beat-rates.
Mutual Energy WTU, a separate legal entity that was an AEP subsidiary (not owned
by or consolidated with TNC), was sold in December 2002.

Since REPs are the electricity suppliers to retail customers in the ERCOT area,
TNC sells its generation to the REPs and other market participants and provides
transmission and distribution services to retail customers of the REPs in the
TNC service territory. As a result of the provision of retail electric service
by REPs effective January 1, 2002, TNC no longer supplies electricity directly
to retail customers. The implementation of REPs as suppliers to retail customers
has caused a significant shift in TNC's sales as further described below under
"Results of Operations."

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 with Mutual Energy WTU
are classified as Electric Generation and delivery charges as Electric
Transmission and Distribution.

Results of Operations
In 2003, Net Income increased $5.8 million or 146% primarily due to the
cumulative effect of accounting changes and increased nonoperating results,
offset by lower Operating Income.

Changes in Operating Revenues
Increase (Decrease)

(in millions) %

Electric Generation $ 41.9 109
Electric Transmission and
Distribution 18.5 126
Sales to AEP Affiliates (47.8) (95)
Total Operating Revenues $ 12.6 12

In 2003, Electric Generation revenues increased due to the reclassification of
energy revenues as a result of the sale of Mutual Energy WTU in December 2002,
discussed above, decreased MWH sales at higher prices and increased revenues
from ERCOT of $17 million. These revenues were offset in part by a decrease in
average electric rates, as 2002 included a transition period which included fuel
revenue collections from retail customers; and a reduction of $13 million
resulting from a provision for rate refund (see Note 5).

The increase in Electric Transmission and Distribution is primarily due to
delivery charges classified as Electric Transmission and Distribution in 2003,
whereas in 2002 they were classified as Sales to AEP Affiliates. In addition,
TNC had increased MWHs delivered in 2003 and increased revenues from ERCOT for
system management services.

In 2003, Sales to AEP Affiliates decreased primarily due to the reclassification
of energy revenues as a result of the sale of Mutual Energy WTU in December
2002, discussed above.

Changes in Operating Expenses
Increase (Decrease)

(in millions) %

Fuel for Electric Generation $ 2.7 32
Fuel from Affiliates for Electric Generation
(10.1) (63)
Purchased Electricity for Resale 18.3 280
Purchased Electricity from AEP Affiliates
7.7 66
Other Operation (3.6) (15)
Maintenance (0.2) (5)
Depreciation and Amortization (2.1) (18)
Taxes Other Than Income Taxes (0.3) (4)
Income Taxes 1.5 50
Total Operating Expenses $ 13.9 15

Net fuel for electric generation decreased due to lower MWHs generated, offset
in part by an increase in the average per unit fuel cost. TNC used coal for 91%
of its generation in 2003 since many of its gas plants were mothballed in late
2002. This higher use of coal helped lower the fuel costs in 2003.

The increase in total Purchased Electricity expense in 2003 was mainly due to
both increased MWHs purchased as a result of the mothballed plants and higher
open market purchase prices.

Other Operation expense decreased in 2003 due to lower uncollectible account
expenses and lower administrative and general expenses.

Depreciation and Amortization expense decreased due to the absence in 2003 of
excess earnings expense adjustments under Texas Restructuring Legislation and
the decrease in depreciation due to the mothballing of several power plants in
late 2002.

The increase in Income Tax Expense is primarily a result of an increase in
pre-tax income.

Other Changes

Nonoperating Income and Nonoperating Expenses increased significantly as a
result of increased non-utility revenue and expenses associated with energy
related construction projects for third parties. Additionally, Nonoperating
Income increased due to increased earnings on derivative contracts.

Interest Charges declined primarily due to lower average borrowings in 2003
versus 2002.

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes is due to a one time after-tax
impact of adopting SFAS 143 (see Notes 2 and 3).

AEP TEXAS NORTH COMPANY
STATEMENTS OF INCOME
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:

Electric Generation $ 80,369 $ 38,437
Electric Transmission and Distribution 33,124 14,672
Sales to AEP Affiliates 2,769 50,517
TOTAL OPERATING REVENUES 116,262 103,626

OPERATING EXPENSES:
Fuel for Electric Generation 11,461 8,714
Fuel from Affiliates for Electric Generation 6,085 16,266
Purchased Electricity for Resale 24,778 6,513
Purchased Electricity from AEP Affiliates 19,345 11,650
Other Operation 20,619 24,170
Maintenance 4,141 4,356
Depreciation and Amortization 9,532 11,569
Taxes Other Than Income Taxes 6,033 6,300
Income Tax Expense 4,403 2,943
TOTAL OPERATING EXPENSES 106,397 92,481

OPERATING INCOME 9,865 11,145

NONOPERATING INCOME (LOSS) 13,463 (1,488)

NONOPERATING EXPENSES 11,559 1,372

NONOPERATING INCOME TAX EXPENSE (CREDIT) 339 (989)

INTEREST CHARGES 4,665 5,282

NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 6,765 3,992

CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 3,071 -

NET INCOME 9,836 3,992

PREFERRED STOCK DIVIDEND REQUIREMENTS 26 26

EARNINGS APPLICABLE TO COMMON STOCK $ 9,810 $ 3,966

The common stock of TNC is wholly owned by AEP.

See Note to Financial Statements beginning on Page L-1.

AEP TEXAS NORTH COMPANY
STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)

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

JANUARY 1, 2002 $137,214 $2,351 $105,970 $ - $245,535
Common Stock Dividends (6,749) (6,749)
Preferred Stock Dividends (26) (26)
238,760
Comprehensive Income:
Other Comprehensive Income - -
Net Income 3,992 3,992
Total Comprehensive Income 3,992

MARCH 31, 2002 $137,214 $2,351 $103,187 $ - $242,752

JANUARY 1, 2003 $137,214 $2,351 $71,942 $(30,763) $180,744
Common Stock Dividends (4,970) (4,970)
Preferred Stock Dividends (26) (26)
175,748
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (421) (421)
Unrealized Loss on Minimum
Pension Liability (7) (7)
Net Income 9,836 9,836
Total Comprehensive Income 9,408

MARCH 31, 2003 $137,214 $2,351 $ 76,782 $(31,191) $185,156

See Notes to Financial Statements beginning on page L-1.

AEP TEXAS NORTH COMPANY
BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)

ASSETS

ELECTRIC UTILITY PLANT:

Production $ 354,117 $ 353,087
Transmission 255,343 254,483
Distribution 446,150 445,486
General 109,200 111,679
Construction Work in Progress 39,991 37,012
Total Electric Utility Plant 1,204,801 1,201,747
Accumulated Depreciation and Amortization 518,631 521,792
NET ELECTRIC UTILITY PLANT 686,170 679,955

OTHER PROPERTY AND INVESTMENTS 1,065 1,213

LONG-TERM RISK MANAGEMENT ASSETS 4,433 2,248

CURRENT ASSETS:
Cash and Cash Equivalents 4,681 1,219
Advances to Affiliates 8,460 -
Accounts Receivable:
Customers 32,776 62,660
Affiliated Companies 37,796 43,632
Allowance for Uncollectible Accounts (4,728) (5,041)
Fuel Inventory 8,916 12,677
Materials and Supplies 10,029 9,574
Accrued Utility Revenues 5,591 6,829
Risk Management Assets 3,411 4,130
Prepayments and Other 1,198 1,070
TOTAL CURRENT ASSETS 108,130 136,750

REGULATORY ASSETS 44,165 45,097

DEFERRED CHARGES 27,481 11,912

TOTAL ASSETS $ 871,444 $ 877,175

See Notes to Financial Statements beginning on page L-1.

AEP TEXAS NORTH COMPANY
BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:

Common Stock - $25 Par Value:
Authorized - 7,800,000 Shares
Outstanding - 5,488,560 Shares $137,214 $137,214
Paid-in Capital 2,351 2,351
Accumulated Other Comprehensive Income (Loss) (31,191) (30,763)
Retained Earnings 76,782 71,942
Total Common Shareholder's Equity 185,156 180,744
Cumulative Preferred Stock Not Subject to
Mandatory Redemption 2,367 2,367
Long-term Debt 333,473 132,500

TOTAL CAPITZALIZATION 520,996 315,611

OTHER NONCURRENT LIABILITIES 41,859 28,861

CURRENT LIABILITIES:
Short-term Debt - Affiliates - 125,000
Long-term Debt Due Within One Year 24,036 -
Advances from Affiliates - 80,407
Accounts Payable - General 17,297 32,714
Accounts Payable - Affiliated Companies 37,152 76,217
Customer Deposits 320 117
Taxes Accrued 25,425 3,697
Interest Accrued 4,847 2,776
Risk Management Liabilities 4,761 3,801
Other 8,237 17,414

TOTAL CURRENT LIABILITIES 122,075 342,143

DEFERRED INCOME TAXES 113,465 117,521

DEFERRED INVESTMENT TAX CREDITS 21,130 21,510

LONG-TERM RISK MANAGEMENT LIABILITIES 2,300 557

REGULATORY LIABILITIES AND DEFERRED CREDITS 49,619 50,972

COMMITMENTS AND CONTINGENCIES (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES $871,444 $877,175

See Notes to Financial Statements beginning on page L-1.

AEP TEXAS NORTH COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING ACTIVITIES:

Net Income $ 9,836 $ 3,992
Adjustments to Reconcile Net Income to Net Cash Flows
From (Used For) Operating Activities:
Depreciation and Amortization 9,532 11,569
Deferred Income Taxes (5,666) (226)
Deferred Investment Tax Credits (380) (318)
Cumulative Effect of Accounting Changes (3,071) -
Mark-to-Market of Risk Management Contracts 608 (213)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) 35,407 (28,456)
Fuel, Materials and Supplies 3,306 (906)
Accrued Utility Revenues 1,238 474
Accounts Payable (54,482) (1,423)
Taxes Accrued 21,728 4,205
Fuel Recovery - (1,384)
Deferred Property Taxes (10,868) (9,525)
Change in Other Assets (4,593) (3,068)
Change in Other Liabilities 4,927 (1,033)
Net Cash Flows From (Used For) Operating Activities 7,522 (26,312)

INVESTING ACTIVITIES:
Construction Expenditures (10,197) (7,531)
Other - -
Net Cash Flows Used For Investing Activities (10,197) (7,531)

FINANCING ACTIVITIES:
Change in Short-term Debt (net) (125,000) -
Issuance of Long-term Debt 225,000 -
Change in Advances to/from Affiliates (net) (88,867) 38,720
Dividends Paid on Common Stock (4,970) (6,749)
Dividends Paid on Cumulative Preferred Stock (26) (26)
Net Cash Flows From Financing Activities 6,137 31,945

Net Increase (Decrease) in Cash and Cash Equivalents 3,462 (1,898)
Cash and Cash Equivalents at Beginning of Period 1,219 2,454
Cash and Cash Equivalents at End of Period $ 4,681 $ 556

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $2,021,000 and
$2,097,000 and for income taxes was $(8,873,000) and $(1,575,000) in 2003 and
2002, respectively.

See Notes to Financial Statements beginning on page L-1.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2003 vs. FIRST QUARTER 2002

APCo is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power to 925,000 retail customers in southwestern
Virginia and southern West Virginia. APCo, as a member of the AEP Power Pool,
shares in the revenues and cost of the AEP Power Pool's wholesale sales to
neighboring utility systems and power marketing transactions. APCo also sells
wholesale power to municipalities.

The cost of the AEP Power Pool's generating capacity is allocated among the Pool
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 their 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 company's prior twelve month peak demand
relative to the total peak demand of all member companies as a basis for sharing
revenues and costs. The result of this calculation is the member load ratio
(MLR) which determines each company's percentage share of revenues and costs.

Results of Operations
Net Income of $156.4 million in the first quarter of 2003 included income from
the Cumulative Effect of Accounting Changes of $77.3 million (see Note 3).
Income Before Cumulative Effect of Accounting Changes increased $23.8 million or
43% primarily due to an improvement in earnings from retail and AEP Power Pool
sales resulting from the interaction of plant availability, the colder winter
weather and higher margins. APCo, as a member of the AEP Power Pool, shares in
the revenues and costs of marketing and activities conducted on its behalf by
the AEP Power Pool. This increase was partially offset by a decline in
Nonoperating Income.

Changes in Operating Revenues

The following analyzes the changes in operating revenues:

(in millions) %

Electric Generation $56.0 21
Electric Transmission and
Distribution 3.5 2
Sales to AEP Affiliates 14.1 33
Total Operating Revenues $73.6 16

The increase in Operating Revenues was due primarily to higher Electric
Generation sales and Sales to AEP Affiliates reflecting the more severe winter
weather of 2003 and an increase in the volume of AEP Power Pool transactions.
Heating degree days were up 18% over the prior year which resulted in an
increase in Residential KWH sales of 16% as well as a 10% increase in total
Retail sales. Additionally, APCo's relative share of the AEP Power Pool revenues
(as well as expenses) for February and March, 2003 increased over the prior
period as a result of APCo reaching a new peak demand in January 2003.

Changes in Operating Expenses

Operating expenses increased 11% in the first quarter of 2003 over the prior
year. The changes in the components of operating expenses were:
Increase (Decrease)
(in millions) %

Fuel for Electric Generation $12.4 12
Purchased Electricity for Resale 3.6 27
Purchased Electricity from AEP
Affiliates 19.9 33
Other Operation (4.8) (7)
Maintenance 6.9 27
Depreciation and Amortization (10.8) (23)
Taxes Other Than Income Taxes 0.1 -
Income Taxes 15.2 44
Total Operating Expenses $42.5 11

Fuel for Electric Generation increased in the first quarter of 2003 to meet the
demand of the higher Electric Generation sales as KWH generated increased 7%.
Purchased Electricity for Resale increased in the first quarter of 2003 as
Retail KWH sales outpaced net generation. Purchased Electricity from AEP
Affiliates increased due to higher charges resulting from the increased of all
volume and the increase in APCo's share of the AEP Power Pool.

The decline in Other Operation expense was primarily due to decreased
employee-related expenses in the first quarter of 2003 reflecting the
cost-saving effects of the Sustained Earnings Improvement Initiative (see Note
9).

The increase in Maintenance expense is due to increased distribution line
maintenance caused by severe winter storm damage in 2003 and increased plant
maintenance primarily at the Sporn plant.

Depreciation and Amortization expense decreased primarily due to reduced expense
attributable to the adoption of SFAS 143. Effective January 1, 2003 the
generation depreciation rate for APCo's non-regulated operations was reduced to
exclude the non-ARO removal cost portion that was included in the depreciation
rate. Additionally, APCo had reduced Depreciation and Amortization expense
related to the amortization of generation related regulatory assets over the
transition period due to the return to SFAS 71 accounting for the West Virginia
jurisdiction (see Note 6 for further discussion of the return to SFAS 71
accounting). Amortization costs of transition regulatory assets had been
accelerated since July 2000 in connection with the discontinuance of SFAS 71 in
APCo's West Virginia jurisdiction. At that time net generation-related
regulatory assets were transferred to the distribution portion of the business
commensurate with their recovery through regulated rates.

The increase in operating Income Taxes is due to an increase in pre-tax
operating book income.

Other Changes

The decrease in Nonoperating Income is due to lower margins for power sold
outside of AEP's traditional marketing area reflecting reduced demand and AEP's
plan to reduce those types of transactions.

The Nonoperating Income Tax Credit in 2003 reflects the tax benefits associated
with the reduction in Nonoperating Income.

Cumulative Effect of Accounting 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 of 02-3
(see Notes 2 and 3).

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:

Electric Generation $323,484 $267,475
Electric Transmission and Distribution 155,849 152,324
Sales to AEP Affiliates 56,895 42,806
TOTAL OPERATING REVENUES 536,228 462,605

OPERATING EXPENSES:
Fuel for Electric Generation 119,865 107,490
Purchased Electricity for Resale 17,118 13,516
Purchased Electricity from AEP Affiliates 80,720 60,780
Other Operation 62,115 66,959
Maintenance 32,738 25,851
Depreciation and Amortization 36,008 46,772
Taxes Other Than Income Taxes 25,079 24,995
Income Taxes 49,901 34,688
TOTAL OPERATING EXPENSES 423,544 381,051

OPERATING INCOME 112,684 81,554

NONOPERATING INCOME (LOSS) (4,484) 5,084

NONOPERATING EXPENSES 3,674 3,645

NONOPERATING INCOME TAX EXPENSE (CREDIT) (3,733) 264

INTEREST CHARGES 29,106 27,388

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 79,153 55,341

CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 77,257 -

NET INCOME 156,410 55,341

PREFERRED STOCK DIVIDEND REQUIREMENTS 984 503

EARNINGS APPLICABLE TO COMMON STOCK $155,426 $ 54,838

The common stock of APCo is wholly owned by AEP. See Notes to Financial
Statements beginning on page L-1.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)

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

JANUARY 1, 2002 $260,458 $715,786 $150,797 $ (340) $1,126,701
Common Stock Dividends (30,984) (30,984)
Preferred Stock Dividends (361) (361)
Capital Stock Expense 142 (142) -
1,095,356
Comprehensive Income:
Other Comprehensive Income, Net of Taxes:
Unrealized Gain on Cash Flow Power Hedges
143 143
Net Income 55,341 55,341
Total Comprehensive Income 55,484

MARCH 31, 2002 $260,458 $715,928 $174,651 $ (197) $1,150,840

JANUARY 1, 2003 $260,458 $717,242 $260,439 $(72,082) $1,166,057
Common Stock Dividends (32,066) (32,066)
Preferred Stock Dividends (361) (361)
Capital Stock Expense 623 (623) -
SFAS 71 Reapplication 162 162
1,133,792
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (12,518) (12,518)
Net Income 156,410 156,410
Total Comprehensive Income 143,892

MARCH 31, 2003 $260,458 $718,027 $383,799 $(84,600) $1,277,684

See Notes to Financial Statements beginning on page L-1.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)
ASSETS

ELECTRIC UTILITY PLANT:

Production $2,256,941 $2,245,945
Transmission 1,218,056 1,218,108
Distribution 1,964,405 1,951,804
General 275,416 272,901
Construction Work in Progress 234,995 206,545
Total Electric Utility Plant 5,949,813 5,895,303
Accumulated Depreciation and Amortization 2,317,009 2,424,607
NET ELECTRIC UTILITY PLANT 3,632,804 3,470,696

OTHER PROPERTY AND INVESTMENTS 53,149 54,653

LONG-TERM RISK MANAGEMENT ASSETS 130,451 115,748

CURRENT ASSETS:
Cash and Cash Equivalents 10,449 4,285
Advances to Affiliates 87,859 -
Accounts Receivable:
Customers 164,050 132,266
Affiliated Companies 88,948 122,665
Miscellaneous 29,217 28,629
Allowance for Uncollectible Accounts (2,596) (13,439)
Fuel Inventory 39,817 53,646
Materials and Supplies 61,697 59,886
Accrued Utility Revenues 7,620 30,948
Risk Management Assets 135,545 94,238
Prepayments and Other 13,716 13,396
TOTAL CURRENT ASSETS 636,322 526,520

REGULATORY ASSETS 407,687 395,553

DEFERRED CHARGES 67,273 64,677

TOTAL ASSETS $4,927,686 $4,627,847

See Notes to Financial Statements beginning on page L-1.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares $ 260,458 $ 260,458
Paid-in Capital 718,027 717,242
Accumulated Other Comprehensive Income (Loss) (84,600) (72,082)
Retained Earnings 383,799 260,439
Total Common Shareowner's Equity 1,277,684 1,166,057
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 17,790 17,790
Subject to Mandatory Redemption 10,860 10,860
Long-term Debt 1,739,210 1,738,854

TOTAL CAPITALIZATION 3,045,544 2,933,561

OTHER NONCURRENT LIABILITIES 191,764 173,438

CURRENT LIABILITIES:
Long-term Debt Due Within One Year 155,007 155,007
Advances from Affiliates - 39,205
Accounts Payable - General 153,667 141,546
Accounts Payable - Affiliated Companies 72,179 98,374
Taxes Accrued 88,442 29,181
Customer Deposits 35,245 26,186
Interest Accrued 39,222 22,437
Risk Management Liabilities 118,979 69,001
Other 63,607 79,832

TOTAL CURRENT LIABILITIES 726,348 660,769

DEFERRED INCOME TAXES 749,572 701,801

DEFERRED INVESTMENT TAX CREDITS 33,936 33,691

LONG-TERM RISK MANAGEMENT LIABILITIES 79,901 44,517

REGULATORY LIABILITIES AND DEFERRED CREDITS 100,621 80,070

COMMITMENTS AND CONTINGENCIES (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES $4,927,686 $4,627,847

See Notes to Financial Statements beginning on page L-1.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING ACTIVITIES:

Net Income $156,410 $ 55,341
Adjustments for Noncash Items:
Cumulative Effect of Accounting Changes (77,257) -
Depreciation and Amortization 36,008 46,800
Deferred Income Taxes 1,005 (3,644)
Deferred Investment Tax Credits 245 (1,098)
Deferred Power Supply Costs (net) 63,837 352
Mark to Market of Risk Management Contracts 5,383 (6,653)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (9,498) (51,419)
Fuel, Materials and Supplies 12,018 12,659
Accrued Utility Revenues 23,328 7,013
Accounts Payable (14,074) 11,456
Taxes Accrued 59,261 29,129
Interest Accrued 16,785 17,516
Incentive Plan Accrued (9,595) (9,362)
Change in Operating Reserves 20,095 1,541
Rate Stabilization Deferral (75,601) -
Change in Other Assets (14,446) (7,043)
Change in Other Liabilities 26,114 9,187
Net Cash Flows From Operating Activities 220,018 111,775

INVESTING ACTIVITIES:
Construction Expenditures (56,627) (62,685)
Proceeds from Sale of Property and Other 2,264 583
Net Cash Flows Used For Investing Activities (54,363) (62,102)

FINANCING ACTIVITIES:
Change in Advances From Affiliates (127,064) (31,991)
Dividends Paid on Common Stock (32,066) (30,984)
Dividends Paid on Cumulative Preferred Stock (361) (361)
Net Cash Flows Used For Financing Activities (159,491) (63,336)

Net Increase (Decrease) in Cash and Cash Equivalents 6,164 (13,663)
Cash and Cash Equivalents at Beginning of Period 4,285 13,663
Cash and Cash Equivalents at End of Period $ 10,449 $ -

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $11,191,000 and
$9,222,000 and for income taxes was $(11,498,000) and $9,593,000 in 2003 and
2002, respectively.

See Notes to Financial Statements beginning on page L-1.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

FIRST QUARTER 2003 vs. FIRST QUARTER 2002

Columbus Southern Power Company (CSPCo) is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electric power to
approximately 689,000 retail customers in central and southern Ohio. CSPCo, as a
member of the AEP Power Pool, shares in the revenues and costs of the AEP Power
Pool's wholesale sales to neighboring utilities and power marketing
transactions. CSPCo also sells wholesale power to municipalities.

The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivery to
the AEP Power Pool and charged for energy received from the AEP Power Pool. The
AEP Power Pool calculates each company's prior twelve month peak demand relative
to the total peak demand of all member companies as a basis for sharing AEP
Power Pool revenues and costs. The result of this calculation is the member load
ratio (MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.

Results of Operations

Net Income increased $32 million or 94% including a $27 million Cumulative
Effect of Accounting Changes in the first quarter of 2003 (see Note 3). Net
Income Before Cumulative Effect increased $5 million or 13% due to an
improvement in earnings from retail and AEP Power Pool sales resulting from the
interactions of plant availability, colder winter weather and higher margins.
CSPCo, as a member of the AEP Power Pool, shares in the revenues and costs of
marketing and activities conducted on its behalf by the AEP Power Pool.

Changes in Operating Revenues

The following analyzes the increase in operating revenue components:

(in millions) %

Electric Generation $20.0 10
Electric Transmission and
Distribution 11.3 10
Sales to AEP Affiliates 13.1 170
Total Operating Revenues $44.4 14

The increase in Electric Generation was driven largely by a rise in demand due
to more severe winter weather in 2003 versus 2002. Heating degree days for the
first quarter of 2003 were up 24% from the same quarter last year which resulted
in 14% higher Residential KWH sales as well as a 5% increase in Commercial KWH
Sales.

CSPCo's share of AEP Power Pool revenues and expenses for 2003 increased over
the prior year as a result of an increase in the volume of the AEP Power Pool
sales. CSPCo's share of AEP Power Pool sales increased 5%.

Changes in Operating Expenses

Operating Expenses increased 13% in 2003. The increases in the components of
Operating Expenses were:

(in millions) %

Fuel for Electric Generation $ 6.4 14
Purchased Electricity for Resale 0.5 13
Purchased Electricity from AEP Affiliates
10.6 15
Other Operation 2.5 5
Maintenance 0.4 3
Depreciation and Amortization 1.0 3
Taxes Other Than Income Taxes 5.3 18
Income Taxes 8.1 47
Total Operating Expenses $34.8 13

Fuel for Electric Generation increased in the first quarter of 2003 to meet the
demand of the higher Electric Generation sales as net KWH generation increased
13%.

Purchased Electricity from AEP Affiliates was higher due to increases in energy
purchased from the AEP Power Pool resulting from a high volume of AEP Power Pool
sales and greater capacity charges.

The increase in Taxes Other Than Income Taxes was a result of increases in
property taxes and state excise taxes.

An increase in operating Income Taxes is due to an increase in pre-tax operating
book income.

Other Changes

The decrease in Nonoperating Income is due to lower margins for power sold
outside of AEP's traditional marketing area reflecting reduced demand and AEP's
plan to reduce those types of transactions.

Cumulative Effect of Accounting 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
Notes 2 and 3).

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:

Electric Generation $214,821 $194,824
Electric Transmission and Distribution 123,616 112,324
Sales to AEP Affiliates 20,768 7,678
TOTAL OPERATING REVENUES 359,205 314,826

OPERATING EXPENSES:
Fuel for Electric Generation 52,043 45,650
Purchased Electricity for Resale 4,198 3,729
Purchased Electricity from AEP Affiliates 82,149 71,582
Other Operation 56,385 53,861
Maintenance 14,559 14,140
Depreciation and Amortization 33,737 32,736
Taxes Other Than Income Taxes 35,608 30,276
Income Taxes 25,375 17,304
TOTAL OPERATING EXPENSES 304,054 269,278

OPERATING INCOME 55,151 45,548

NONOPERATING INCOME (LOSS) (7,015) 5,074
NONOPERATING EXPENSES 1,862 1,624
NONOPERATING INCOME TAX EXPENSE (CREDIT) (5,547) 1,347
INTEREST CHARGES 13,462 13,793
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 38,359 33,858
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 27,283 -
NET INCOME 65,642 33,858

PREFERRED STOCK DIVIDEND REQUIREMENTS 254 181

EARNINGS APPLICABLE TO COMMON STOCK $ 65,388 $ 33,677

The common stock of CSPCo is wholly owned by AEP.

See Notes to Financial Statements beginning on Page L-1

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)

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

JANUARY 1, 2002 $41,026 $574,369 $176,103 $ - $791,498
Common Stock Dividends Declared (21,766) (21,766)
Preferred Stock Dividends Declared (175) (175)
Capital Stock Expense 253 (254) (1)
769,556
Comprehensive Income:
Other Comprehensive Income - -
Net Income 33,858 33,858
Total Comprehensive Income 33,858

MARCH 31, 2002 $41,026 $574,622 $187,766 $ - $803,414

JANUARY 1, 2003 $41,026 $575,384 $290,611 $(59,357) $847,664
Common Stock Dividends Declared (38,311) (38,311)
Capital Stock Expense 254 (254) -
809,353
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (7,343) (7,343)
Net Income 65,642 65,642
Total Comprehensive Income 58,299

MARCH 31, 2003 $41,026 $575,638 $317,688 $(66,700) $867,652

See Notes to Financial Statements beginning on page L-1.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)

ASSETS

ELECTRIC UTILITY PLANT:

Production $1,591,772 $1,582,627
Transmission 413,327 413,286
Distribution 1,214,588 1,208,255
General 155,854 165,025
Construction Work in Progress 106,447 98,433
Total Electric Utility Plant 3,481,988 3,467,626
Accumulated Depreciation and Amortization 1,428,761 1,465,174
NET ELECTRIC UTILITY PLANT 2,053,227 2,002,452

OTHER PROPERTY AND INVESTMENTS 34,589 35,759

LONG-TERM RISK MANAGEMENT ASSETS 76,680 77,810

CURRENT ASSETS:
Cash and Cash Equivalents 7,968 1,479
Advances to Affiliates 87,460 31,257
Accounts Receivable:
Customers 55,642 49,566
Affiliated Companies 39,880 54,518
Miscellaneous 19,546 22,005
Allowance for Uncollectible Accounts (579) (634)
Fuel 15,757 24,844
Materials and Supplies 40,928 40,339
Accrued Utility Revenues 6,964 12,671
Risk Management Assets 79,692 63,348
Prepayments and Other 9,221 7,308
TOTAL CURRENT ASSETS 362,479 306,701

REGULATORY ASSETS 252,940 257,682

DEFERRED CHARGES 77,510 72,836

TOTAL ASSETS $2,857,425 $2,753,240

See Notes to Financial Statements beginning on page L-1.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares

Outstanding - 16,410,426 Shares $ 41,026 $ 41,026
Paid-in Capital 575,638 575,384
Accumulated Other Comprehensive Loss (66,700) (59,357)
Retained Earnings 317,688 290,611
Total Common Shareholder's Equity 867,652 847,664
Long-term Debt - General 747,264 418,626
Long-term Debt - Affiliated Companies - 160,000

TOTAL CAPITALIZATION 1,614,916 1,426,290

OTHER NONCURRENT LIABILITIES 92,207 95,460

CURRENT LIABILITIES:
Long-term Debt Due Within One Year 168,500 43,000
Short-term Debt - Affiliated Companies 40,000 290,000
Accounts Payable - General 86,989 89,736
Accounts Payable - Affiliated Companies 45,099 81,599
Taxes Accrued 123,989 112,172
Interest Accrued 13,692 9,798
Risk Management Liabilities 69,939 46,375
Other 51,934 36,790

TOTAL CURRENT LIABILITIES 600,142 709,470

DEFERRED INCOME TAXES 448,836 437,771

DEFERRED INVESTMENT TAX CREDITS 33,144 33,907

LONG-TERM RISK MANAGEMENT LIABILITIES 46,967 29,926

DEFERRED CREDITS AND REGULATORY LIABILITIES 21,213 20,416

COMMITMENTS AND CONTINGENCIES (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES $2,857,425 $2,753,240

See Notes to Financial Statements beginning on page L-1.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

Three Months Ended March 31,
(in thousands)
2003 2002
OPERATING ACTIVITIES:

Net Income $ 65,642 $ 33,858
Adjustments for Noncash Items:
Cumulative Effect of Accounting Changes (27,283) -
Depreciation and Amortization 33,737 32,786
Deferred Income Taxes (3,095) (313)
Deferred Investment Tax Credits (763) (778)
Mark to Market of Risk Management Contracts 10,958 (5,849)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 10,966 (42,207)
Fuel, Materials and Supplies 8,498 3,636
Accrued Utility Revenues 5,707 (5,247)
Accounts Payable (39,247) 7,349
Taxes Accrued 11,817 (19,947)
Interest Accrued 3,894 3,607
Change in Other Assets (5,740) 992
Change in Other Liabilities 6,991 3,505
Net Cash Flows From Operating Activities 82,082 11,392

INVESTING ACTIVITIES:
Construction Expenditures (27,269) (24,807)
Proceeds from Sale of Property 190 389
Net Cash Flows Used For Investing Activities (27,079) (24,418)

FINANCING ACTIVITIES:
Issuance of Long-term Debt 500,000 -
Advances from (to) Affiliates (56,203) 29,106
Retirement of Long-term Debt (204,000) -
Change in Short-term Debt (250,000) -
Dividends Paid on Common Stock (38,311) (21,766)
Dividends Paid on Cumulative Preferred Stock (175)
Net Cash Flows From (Used For) Financing Activities
(48,514) 7,165

Net Increase (Decrease) in Cash and Cash Equivalents 6,489 (5,861)
Cash and Cash Equivalents at Beginning of Period 1,479 12,358
Cash and Cash Equivalents at End of Period $ 7,968 $ 6,497

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $9,219,000 and
$9,725,000 and for income taxes was ($16,019,000) and $11,198,000 in 2003 and
2002, respectively.

See Notes to Financial Statements beginning on page L-1.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

FIRST QUARTER 2003 vs. FIRST QUARTER 2002

I&M is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power to 571,000 retail customers in its service
territory in northern and eastern Indiana and a portion of southwestern
Michigan. As a member of the AEP Power Pool, I&M shares the revenues and the
costs of the AEP Power Pool's wholesale sales to neighboring utilities and power
marketers. I&M also sells wholesale power to municipalities and electric
cooperatives.

The cost of the AEP Power Pool's generating capacity is allocated among the AEP
Power Pool 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 company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing revenues and costs. The result of this calculation is each company's
member load ratio (MLR) which determines each company's percentage share of
revenues and costs.

Under the terms of unit power agreements, I&M purchases AEGCo's 50% share of the
2,600 MW Rockport Plant capacity unless it is sold to other utilities. AEGCo is
an affiliate that is not a member of the AEP Power Pool. An agreement between
AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant
capacity to KPCo through 2004. Therefore, I&M purchases 910 MW of AEGCo's 50%
share of Rockport Plant capacity. If AEP's restructuring settlement agreement
filed with the FERC becomes operative, the KPCo agreement extends until December
31, 2009 for Rockport Plant Unit 1 and until December 7, 2022 for Rockport Plant
Unit 2.

Results of Operations
Net Income Before Cumulative Effect of Accounting Change increased $20 million
or 178% due primarily to increased sales as a result of higher availability of
I&M's Cook Plant and Rockport Plant in 2003 as compared to 2002. In addition, an
improvement in earnings from retail and AEP Power Pool sales resulted from the
interaction of plant availability, the more severe winter conditions and higher
margins. I&M, as a member of the AEP Power Pool, shares in the revenues and
costs of the marketing activities conducted on its behalf by the AEP Power Pool.

Changes in Operating Revenues
Operating Revenues increased 19% due primarily to higher Electric Generation
sales and Sales to AEP Affiliates reflecting the colder winter weather of 2003,
an increase in AEP Power Pool transactions shared with I&M and an increase in
sales to the AEP Power Pool. The following analyzes the increases in Operating
Revenues:
(in millions) %

Electric Generation $38.6 16
Electric Transmission and
Distribution 6.2 9
Sales to AEP Affiliates 21.6 46
Total Operating Revenues $66.4 19

The increase in Electric Generation revenues was due to an increase in sales
reflecting a colder winter. Heating degree days were up 28% over the prior year
which resulted in an increase in Residential KWH sales of 13% as well as a 5%
increase in total retail sales. I&M's share of the AEP Power Pool revenues (as
well as expenses) during 2003 increased over the prior year as a result of an
increase in the volume of the AEP Power Pool.

Revenues from Sales to AEP Affiliates increased significantly reflecting more
power being available for sale in 2003 as one unit of the Cook Nuclear Plant was
shutdown for refueling and both units of Rockport Plant were scheduled for
planned boiler maintenance in 2002. AEP Power Pool members are 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. With the outages in 2002, I&M's
available generation increased in 2003 resulting in more power being delivered
to the AEP Power Pool.

Changes in Operating Expenses
Operating Expenses increased 12% in 2003. The changes in the components of
Operating Expenses were:

Increase (Decrease)
(in millions) %

Fuel for Electric Generation $18.9 35
Purchased Electricity for Resale 1.0 19
Purchased Electricity from AEP Affiliates
12.4 23
Other Operation (10.4) (9)
Maintenance 0.3 1
Depreciation and Amortization 1.9 4
Taxes Other Than Income Taxes (1.4) (8)
Income Taxes 15.0 250
Total Operating Expenses $37.7 12

Fuel for Electric Generation increased primarily due to an increase in
generation reflecting the plant outages in 2002.

Purchased Electricity from AEP Affiliates increased due to higher availability
of the Rockport Plant in 2002, as I&M is required to purchase a portion of
AEGCo's Rockport Plant generation under their unit power agreement. AEGCo's
share of generation at the Rockport Plant increased 50% in 2003.

Other Operation expense decreased due to cost reduction efforts instituted in
the fourth quarter of 2002 and costs incurred during the outages occurring
during the first quarter of 2002.

The decrease in Taxes Other Than Income Taxes reflects a favorable tax law
change in Indiana effective March 2002 and a lower estimate for Cook Plant's
assessed value which reduced real and personal property tax estimates on which
2003 accruals are based.

Income Taxes attributable to operations increased significantly due to an
increase in pre-tax operating income.

Other Changes

The decrease in Nonoperating Income is due to lower margins for power sold
outside of AEP's traditional marketing area reflecting reduced demand and AEP's
plan to exit those risk management activities in areas outside of its
traditional market area.

The decrease in Nonoperating Income Tax Expense is a result of the decline in
pre-tax nonoperating income.

Cumulative Effect of Accounting Change

The Cumulative Effect of Accounting Change is due to the implementation of the
requirements of EITF 02-3 (see Notes 2 and 3).

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:

Electric Generation $273,008 $234,446
Electric Transmission and Distribution 76,779 70,580
Sales to AEP Affiliates 68,811 47,209

TOTAL OPERATING REVENUES 418,598 352,235

OPERATING EXPENSES:
Fuel for Electric Generation 73,094 54,156
Purchased Electricity for Resale 6,282 5,282
Purchased Electricity from AEP Affiliates 65,898 53,507
Other Operation 101,381 111,766
Maintenance 31,367 31,043
Depreciation and Amortization 43,726 41,866
Taxes Other Than Income Taxes 16,821 18,241
Income Taxes 21,039 6,011

TOTAL OPERATING EXPENSES 359,608 321,872

OPERATING INCOME 58,990 30,363

NONOPERATING INCOME 3,619 17,004

NONOPERATING EXPENSES 12,935 13,310

NONOPERATING INCOME TAX EXPENSE (CREDIT) (4,451) (425)

INTEREST CHARGES 23,438 23,424

NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 30,687 11,058

CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) (3,160) -

NET INCOME 27,527 11,058

PREFERRED STOCK DIVIDEND REQUIREMENTS 1,149 1,155

EARNINGS APPLICABLE TO COMMON STOCK $ 26,378 $ 9,903

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

See Notes to Financial Statements beginning on page L-1.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)

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

JANUARY 1, 2002 $56,584 $733,216 $ 74,605 $(3,835) $ 860,570
Preferred Stock Dividends (1,122) (1,122)
Capital Stock Expense 33 (33) -
859,448
Comprehensive Income:
Other Comprehensive Income, Net of Taxes:
Cash Flow Interest Rate Hedge 1,259 1,259
Net Income 11,058 11,058
Total Comprehensive Income 12,317

MARCH 31, 2002 $56,584 $733,249 $ 84,508 $(2,576) $ 871,765

JANUARY 1, 2003 $56,584 $858,560 $143,996 $(40,487) $1,018,653
Common Stock Dividends (10,000) (10,000)
Preferred Stock Dividends (1,115) (1,115)
Capital Stock Expense 34 (34) -
1,007,538
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (7,857) (7,857)
Net Income 27,527 27,527
Total Comprehensive Income 19,670

MARCH 31, 2003 $56,584 $858,594 $160,374 $(48,344) $1,027,208

See Notes to Financial Statements beginning on page L-1.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)
ASSETS

ELECTRIC UTILITY PLANT:

Production $2,858,230 $2,768,463
Transmission 979,559 971,599
Distribution 928,699 921,835
General (including nuclear fuel) 208,856 220,137
Construction Work in Progress 148,218 147,924
Total Electric Utility Plant 5,123,562 5,029,958
Accumulated Depreciation and Amortization 2,645,331 2,568,604
NET ELECTRIC UTILITY PLANT 2,478,231 2,461,354

NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
DISPOSAL TRUST FUNDS 870,689 870,754

LONG-TERM RISK MANAGEMENT ASSETS 80,073 83,265

OTHER PROPERTY AND INVESTMENTS 115,837 120,941

CURRENT ASSETS:
Cash and Cash Equivalents 6,520 3,237
Advances to Affiliates 228,775 191,226
Accounts Receivable:
Customers 77,278 67,333
Affiliated Companies 131,332 122,489
Miscellaneous 18,401 30,468
Allowance for Uncollectible Accounts (574) (578)
Fuel 30,586 32,731
Materials and Supplies 96,875 95,552
Risk Management Assets 85,221 68,148
Prepayments and Other 16,213 18,410
TOTAL CURRENT ASSETS 690,627 629,016

REGULATORY ASSETS 304,988 348,212

DEFERRED CHARGES 85,494 73,649

TOTAL ASSETS $4,625,939 $4,587,191

See Notes to Financial Statements beginning on page L-1.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares $ 56,584 $ 56,584
Paid-in Capital 858,594 858,560
Accumulated Other Comprehensive Income (Loss) (48,344) (40,487)
Retained Earnings 160,374 143,996
Total Common Shareowner's Equity 1,027,208 1,018,653
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,101 8,101
Subject to Mandatory Redemption 64,945 64,945
Long-term Debt 1,333,013 1,587,062

TOTAL CAPITALIZATION 2,433,267 2,678,761

OTHER NONCURRENT LIABILITIES:
Asset Retirement Obligations 525,116 -
Nuclear Decommissioning - 620,672
Other 131,140 138,965

TOTAL OTHER NONCURRENT LIABILITIES 656,256 759,637

CURRENT LIABILITIES:
Long-term Debt Due Within One Year 285,000 30,000
Accounts Payable:
General 108,331 125,048
Affiliated Companies 60,845 93,608
Taxes Accrued 90,725 71,559
Interest Accrued 25,786 21,481
Obligations Under Capital Leases 6,258 8,229
Risk Management Liabilities 73,799 48,568
Other 95,692 92,822

TOTAL CURRENT LIABILITIES 746,436 491,315

DEFERRED INCOME TAXES 326,438 356,197

DEFERRED INVESTMENT TAX CREDITS 95,874 97,709

DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 72,958 73,885

LONG-TERM RISK MANAGEMENT LIABILITIES 48,402 32,261

DEFERRED CREDITS AND REGULATORY LIABILITIES 246,308 97,426

CONTINGENCIES (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES $4,625,939 $4,587,191

See Notes to Financial Statements beginning on page L-1.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING ACTIVITIES:

Net Income $ 27,527 $ 11,058
Adjustments for Noncash Items:
Cumulative Effect of Accounting Change 3,160 -
Depreciation and Amortization 43,726 42,184
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net)
9,410 (24,130)
Unrecovered Fuel and Purchased Power Costs 9,375 9,375
Amortization of Nuclear Outage Costs 10,000 10,000
Deferred Income Taxes (12,367) (7,132)
Deferred Investment Tax Credits (1,835) (1,845)
Mark-to-Market of Risk Management Contracts 10,543 (3,708)
Deferred Property Taxes (9,116) (8,409)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (6,725) (58,316)
Fuel, Materials and Supplies 822 5,522
Accounts Payable (49,480) (10,779)
Taxes Accrued 19,166 21,391
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Change in Other Assets 21,178 8,328
Change in Other Liabilities (13,679) 675
Net Cash Flows From Operating Activities 80,169 12,678

INVESTING ACTIVITIES:
Construction Expenditures (28,234) (26,398)
Other 12 -
Net Cash Flows Used For Investing Activities (28,222) (26,398)

FINANCING ACTIVITIES:
Change in Advances from (to) Affiliates (net) (37,549) 8,887
Dividends Paid on Common Stock (10,000) -
Dividends Paid on Cumulative Preferred Stock (1,115) (1,122)
Net Cash Flows From (Used For) Financing Activities (48,664) 7,765

Net Increase (Decrease) in Cash and Cash Equivalents 3,283 (5,955)
Cash and Cash Equivalents at Beginning of Period 3,237 16,804
Cash and Cash Equivalents at End of Period $ 6,520 $ 10,849

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $18,211,000 and
$15,090,000 and for income taxes was $20,011,000 and $(470,000) in 2003 and
2002, respectively.

See Notes to Financial Statements beginning on page L-1.

KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

FIRST QUARTER 2003 vs. FIRST QUARTER 2002

KPCo is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power serving 174,000 retail customers in eastern
Kentucky. KPCo as a member of the AEP Power Pool shares in the revenues and
costs of the AEP Power Pool's wholesale sales to neighboring utility systems and
power marketing transactions. KPCo also sells wholesale power to municipalities.
The cost of the AEP Power Pool's generating capacity is allocated among the Pool
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 their 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 company's prior twelve-month peak demand
relative to the total peak demand of all member companies as a basis for sharing
revenues and costs. The result of this calculation is the member load ratio
(MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.

KPCo has a unit power agreement with AEGCo, an affiliated company, which expires
in 2004. The agreement provides for KPCo to purchase 15% of the total output of
the two unit 2,600-mw capacity Rockport Plant. Under the unit power agreement,
there is a demand charge for the right to receive the power, which is payable
even if the power is not taken. The amount of the demand charge is such that
when added to other amounts received by AEGCo, it will enable AEGCo to recover
all its fixed expenses including a FERC-approved rate of return on common
equity.

Results of Operations
Net Income of $9.9 million in the first quarter of 2003 included a loss from the
Cumulative Effect of Accounting Change of $1.1 million due to the adoption of
EITF 02-3. Income Before Cumulative Effect of Accounting Change increased $0.8
million or 8% primarily due to an improvement in earnings from retail and AEP
Power Pool sales resulting from the interaction of plant availability, the more
severe winter weather and higher margins in 2003 versus 2002. KPCo, a member of
the Power Pool, shares in the revenues and costs of marketing and activities
conducted on its behalf by the AEP Power Pool.
Changes in Operating Revenues

The following analyzes the increase in operating revenues:

(in millions) %

Electric Generation $10.3 17
Electric Transmission and Distribution 0.5 2
Sales to AEP Affiliates 2.1 35
Total Operating Revenues $12.9 13
The increase in Operating Revenues is due to an increase in residential sales
reflecting increased demand due to the more severe weather in 2003 versus 2002
and higher volume in the AEP Power Pool of transactions. Heating degree days
were up approximately 18% resulting in a 12% increase in Residential KWH sold.
This increase was partially offset by reduced industrial sales reflecting the
slowdown in the economy. Overall retail sales were up 3% over 2002.

Changes in Operating Expenses

Changes in the components of Operating Expenses were:

Increase (Decrease)
(in millions) %

Fuel for Electric Generation $(3.8) (18)
Purchased Electricity from AEP Affiliates 8.5 29
Other Operation (0.2) (2)
Maintenance 2.2 49
Depreciation and Amortization 0.5 6
Taxes Other Than Income Taxes 0.2 11
Income Taxes 1.2 22
Total Operating Expenses $ 8.6 10

Fuel for Electric Generation decreased due to unplanned outages in 2003 at
KPCo's Big Sandy Plant resulting in a 26% decline in net generation. Purchased
Electricity from AEP Affiliates increased primarily to support Electric
Generation sales. Increased purchases of electricity from the Rockport Plant,
which had been in an outage during the first quarter of 2002, also contributed
to the increased expense.

Maintenance expense increased primarily due to distribution line maintenance
resulting from a major ice storm in February 2003. A three week outage at the
Big Sandy plant also contributed to increased Maintenance expenses.

The increase in operating Income Taxes is due to an increase in pre-tax
Operating Income.

Other Changes

The decrease in Nonoperating Income is due to lower margins for power sold
outside of AEP's traditional marketing area reflecting reduced demand and AEP's
plan to reduce those types of transactions.

The increase in Nonoperating Income Tax Credits reflects the tax benefits
associated with the reduction in Nonoperating Income.

Cumulative Effect of Accounting Change

The Cumulative Effect of Accounting Change is due to the implementation of the
requirements of EITF 02-3 (see Notes 2 and 3).

KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)

OPERATING REVENUES:

Electric Generation $ 69,165 $ 58,887
Electric Transmission and Distribution 34,794 34,276
Sales to AEP Affiliates 8,135 6,022

TOTAL OPERATING REVENUES 112,094 99,185

OPERATING EXPENSES:
Fuel for Electric Generation 17,947 21,767
Purchased Electricity from AEP Affiliates 37,395 28,941
Other Operation 12,137 12,351
Maintenance 6,765 4,549
Depreciation and Amortization 8,712 8,257
Taxes Other Than Income Taxes 2,365 2,135
Income Taxes 6,939 5,701

TOTAL OPERATING EXPENSES 92,260 83,701

OPERATING INCOME 19,834 15,484

NONOPERATING INCOME (LOSS) (2,415) 1,642

NONOPERATING EXPENSES 232 570

NONOPERATING INCOME TAX CREDIT 558 190

INTEREST CHARGES 6,724 6,500

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 11,021 10,246

CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) (1,134) -

NET INCOME $ 9,887 $ 10,246

The common stock of KPCo is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.

KENTUCKY POWER COMPANY
STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (UNAUDITED)

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

JANUARY 1, 2002 $50,450 $158,750 $48,833 $(1,903) $256,130
Common Stock Dividends (7,044) (7,044)
249,086
Comprehensive Income:
Other Comprehensive Income, Net of Taxes:
Unrealized Gain on Cash Flow Power
Hedges 516 516
Net Income 10,246 10,246
Total Comprehensive Income 10,762

MARCH 31, 2002 $50,450 $158,750 $52,035 $(1,387) $259,848

JANUARY 1, 2003 $50,450 $208,750 $48,269 $(9,451) $298,018
Common Stock Dividends (5,482) (5,482)
292,536
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (2,865) (2,865)
Net Income 9,887 9,887
Total Comprehensive Income 7,022

MARCH 31, 2003 $50,450 $208,750 $52,674 $(12,316) $299,558

See Notes to Financial Statements beginning on page L-1.

KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)

ASSETS

ELECTRIC UTILITY PLANT:

Production $ 284,401 $ 275,121
Transmission 374,120 373,639
Distribution 415,725 414,281
General 67,296 67,449
Construction Work in Progress 179,635 165,129
Total Electric Utility Plant 1,321,177 1,295,619
Accumulated Depreciation and Amortization 396,014 397,304
NET ELECTRIC UTILITY PLANT 925,163 898,315

OTHER PROPERTY AND INVESTMENTS 6,585 6,904

LONG-TERM RISK MANAGEMENT ASSETS 29,686 29,871

CURRENT ASSETS:
Cash and Cash Equivalents 1,465 2,304
Accounts Receivable:
Customers 25,156 22,044
Affiliated Companies 13,692 23,802
Miscellaneous 3,254 2,889
Allowance for Uncollectible Accounts (563) (192)
Fuel 12,158 10,817
Materials and Supplies 16,125 16,127
Accrued Utility Revenues 6,529 5,301
Accrued Tax Benefit - 1,253
Risk Management Assets 30,853 24,320
Prepayments and Other 2,110 2,127
TOTAL CURRENT ASSETS 110,779 110,792

REGULATORY ASSETS 102,689 101,976

DEFERRED CHARGES 16,084 16,818

TOTAL ASSETS $1,190,986 $1,164,676

See Notes to Financial Statements beginning on page L-1.

KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares $ 50,450 $ 50,450
Paid-in Capital 208,750 208,750
Accumulated Other Comprehensive Income (Loss) (12,316) (9,451)
Retained Earnings 52,674 48,269
Total Common Shareowner's Equity 299,558 298,018
Long-term Debt 391,665 391,632
Long-term Debt - Affiliated Companies 60,000 60,000

TOTAL CAPITALIZATION 751,223 749,650

OTHER NONCURRENT LIABILITIES 27,220 27,319

CURRENT LIABILITIES:
Long-term Debt Due Within One Year
- Affiliated Companies 15,000 15,000
Advances from Affiliates 46,071 23,386
Accounts Payable:
General 40,294 46,515
Affiliated Companies 25,052 44,035
Customer Deposits 10,345 8,048
Interest Accrued 7,987 6,471
Accrued Taxes 8,679 -
Risk Management Liabilities 27,076 17,803
Other 10,351 14,322

TOTAL CURRENT LIABILITIES 190,855 175,580

DEFERRED INCOME TAXES 179,059 178,313

DEFERRED INVESTMENT TAX CREDITS 8,871 9,165

LONG-TERM RISK MANAGEMENT LIABILITIES 18,183 11,488

REGULATORY LIABILITIES AND DEFERRED CREDITS 15,575 13,161

COMMITMENTS AND CONTINGENCIES (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES $1,190,986 $1,164,676

See Notes to Financial Statements beginning on page L-1.

KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)

OPERATING ACTIVITIES:

Net Income $ 9,887 $ 10,246
Adjustments for Noncash Items:
Cumulative Effect of Accounting Change 1,134 -
Depreciation and Amortization 8,712 8,257
Deferred Income Taxes 2,766 (556)
Deferred Investment Tax Credits (294) (295)
Deferred Fuel Costs (net) (388) 1,542
Mark-to-Market of Risk Management Contracts 3,500 (1,858)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 7,004 (14,598)
Fuel, Materials and Supplies (1,339) (1,759)
Accrued Utility Revenues (1,228) (2,921)
Accounts Payable (25,204) 5,618
Taxes Accrued 9,932 1,710
Change in Other Assets (474) 4,997
Change in Other Liabilities 2,765 435
Net Cash Flows From Operating Activities 16,773 10,818

INVESTING ACTIVITIES:
Construction Expenditures (35,025) (15,898)
Proceeds from Sales of Property and Other 210 -
Net Cash Flow Used for Investing Activities (34,815) (15,898)

FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 22,685 10,594
Dividends Paid (5,482) (7,044)
Net Cash Flows From Financing Activities 17,203 3,550

Net Decrease in Cash and Cash Equivalents (839) (1,530)
Cash and Cash Equivalents at Beginning of Period 2,304 1,947
Cash and Cash Equivalents at End of Period $ 1,465 $ 417

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $7,975,000 and $6,328,000
in 2003 and 2002, respectively. Cash paid (received) for income taxes was
$(6,435,000) and $3,053,000 in 2003 and 2002, respectively. Noncash acquisitions
under capital leases were $22,000 in 2002.

See Notes to Financial Statements beginning on page L-1.

OHIO POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

FIRST QUARTER 2003 vs. FIRST QUARTER 2002

Ohio Power Company (OPCo) is a public utility engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
702,000 customers in the northwestern, east central, eastern and southern
sections of Ohio. As a member of the AEP Power Pool, OPCo shares in the revenues
and the costs of the AEP Power Pool's wholesale sales to neighboring utilities
and power marketing transactions. OPCo also sells wholesale power to Wheeling
Power Company, municipalities and electric cooperatives.

The cost of the AEP Power Pool's generating capacity is allocated among the Pool
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 company's prior twelve month peak demand relative
to the total peak demand of all member companies as a basis for sharing revenues
and costs. The result of this calculation is the member load ratio (MLR) which
determines each company's percentage share of AEP Power Pool revenues and costs.

Results of Operations
Net Income for the first quarter of 2003 increased $129 million or 201% compared
to the same quarter last year. This increase was due primarily to a $125 million
Cumulative Effect of Accounting Changes in the first quarter of 2003 (see Note
3). Net Income Before Cumulative Effect of Accounting Changes increased $4
million or 7% primarily due to an improvement in earnings from retail and AEP
Power Pool sales resulting from the interactions of plant availability, the
colder weather and higher margins. OPCo, as a member of the Power Pool, shares
in the revenues and costs of marketing and activities conducted on its behalf by
the AEP Power Pool.

Changes in Operating Revenues

The following analyzes the increases in operating revenue components:
(in millions) %

Electric Generation $35.1 13
Electric Transmission and Distribution
4.8 3
Sales to AEP Affiliates 30.1 27
Total Operating Revenues $70.0 13

The increase in Operating Revenues is due to a rise in revenue from Electric
Generation and Sales to AEP Affiliates. The increase was driven largely by an
increased demand due to more severe winter conditions in 2003 as compared to
2002, and an increase in the volume of AEP Power Pool transactions. Heating
degree days were up 25% over the prior year which resulted in 13% higher
residential KWH sales. OPCo's share of the AEP Power Pool revenues and expenses
for first quarter 2003 increased over the prior year as a result of an increase
in the overall volume of the AEP Power Pool. OPCo's share of AEP Power Pool
sales increased 19%.

Changes in Operating Expenses

Operating Expenses increased 13% in 2003. The changes in the components of
Operating Expenses were:

Increase (Decrease)
(in millions) %

Fuel for Electric Generation $11.3 8
Purchased Electricity for Resale 1.8 10
Purchased Electricity from AEP Affiliates
8.5 60
Other Operation 2.9 3
Maintenance 6.5 22
Depreciation and Amortization (1.1) (2)
Taxes Other Than Income Taxes 1.3 3
Income Taxes 23.6 67
Total Operating Expenses $54.8 13

Fuel for Electric Generation increased in the first quarter of 2003 to meet the
demand of the higher Electric Generation sales as net KWH generation increased
30%. Purchased Electricity for Resale increased due to the 4% increase in KWH
purchased to meet demand. Purchased Electricity from AEP Affiliates increased as
a result of additional MWH purchases and increased prices.

Maintenance expense increased primarily due to an increase in boiler plant
maintenance and distribution line maintenance caused by severe storm damage in
2003.

The increase in operating Income Taxes is due to an increase in pre-tax
operating book income and federal income tax adjustments.

Other Changes

The decrease in Nonoperating Income (Loss) is due to lower margins for power
sold outside of AEP's traditional marketing area reflecting reduced demand and
AEP's plan to reduce those types of transactions.

Nonoperating Expenses increased predominately as a result of costs incurred
related to the sale of our Switch Water Heater program. The decrease in
Nonoperating Income Tax Expense (Credit) is due to a decrease in pre-tax
nonoperating book income.

Cumulative Effect of Accounting 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
Notes 2 and 3).

OHIO POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:

Electric Generation $305,035 $269,978
Electric Transmission and Distribution 145,852 141,040
Sales to AEP Affiliates 139,744 109,634
TOTAL OPERATING REVENUES 590,631 520,652

OPERATING EXPENSES:
Fuel for Electric Generation 153,648 142,336
Purchased Electricity for Resale 19,392 17,629
Purchased Electricity from AEP Affiliates 22,783 14,227
Other Operation 92,981 90,114
Maintenance 35,457 28,988
Depreciation and Amortization 61,551 62,621
Taxes Other Than Income Taxes 47,155 45,839
Income Taxes 58,794 35,182
TOTAL OPERATING EXPENSES 491,761 436,936

OPERATING INCOME 98,870 83,716

NONOPERATING INCOME (LOSS) (3,811) 12,925
NONOPERATING EXPENSES 10,623 7,407
NONOPERATING INCOME TAX EXPENSE (CREDIT) (4,656) 3,722
INTEREST CHARGES 20,742 21,461
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 68,350 64,051
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 124,632 -
NET INCOME 192,982 64,051

PREFERRED STOCK DIVIDEND REQUIREMENTS 314 314

EARNINGS APPLICABLE TO COMMON STOCK $192,668 $ 63,737

The common stock of OPCo is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.

OHIO POWER COMPANY
STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)

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

JANUARY 1, 2002 $321,201 $462,483 $401,297 $ (196) $1,184,785
Common Stock Dividends (32,582) (32,582)
Preferred Stock Dividends (314) (314)
1,151,889
Comprehensive Income:
Other Comprehensive Income (Loss) (201) (201)
Net Income 64,051 64,051
Total Comprehensive Income 63,850

MARCH 31, 2002 $321,201 $462,483 $432,452 $ (397) $1,215,739

JANUARY 1, 2003 $321,201 $462,483 $522,316 $(72,886) $1,233,114
Common Stock Dividends (41,934) (41,934)
Preferred Stock Dividends (314) (314)
1,190,866
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (4,115) (4,115)
Net Income 192,982 192,982
Total Comprehensive Income 188,867

MARCH 31, 2003 $321,201 $462,483 $673,050 $(77,001) $1,379,733

See Notes to Financial Statements beginning on page L-1.

OHIO POWER COMPANY
BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)

ASSETS

ELECTRIC UTILITY PLANT:

Production $3,135,098 $3,116,825
Transmission 907,021 905,829
Distribution 1,122,732 1,114,600
General 227,014 260,153
Construction Work in Progress 307,842 288,419
Total Electric Utility Plant 5,699,707 5,685,826
Accumulated Depreciation and Amortization 2,331,793 2,566,828
NET ELECTRIC UTILITY PLANT 3,367,914 3,118,998

OTHER PROPERTY AND INVESTMENTS 58,084 61,686

LONG-TERM RISK MANAGEMENT ASSETS 101,736 103,230

CURRENT ASSETS:
Cash and Cash Equivalents 32,412 5,285
Accounts Receivable:
Customers 112,495 95,100
Affiliated Companies 98,926 124,244
Miscellaneous 25,567 19,281
Allowance for Uncollectible Accounts (898) (909)
Fuel 75,920 87,409
Materials and Supplies 83,327 85,379
Risk Management Assets 114,581 92,108
Prepayments and Other 36,370 12,083
TOTAL CURRENT ASSETS 578,700 519,980

REGULATORY ASSETS 549,421 568,641

DEFERRED CHARGES AND OTHER ASSETS 126,564 84,497

TOTAL ASSETS $4,782,419 $4,457,032

See Notes to Financial Statements beginning on page L-1.

OHIO POWER COMPANY
BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares $ 321,201 $ 321,201
Paid-in Capital 462,483 462,483
Accumulated Other Comprehensive Income (Loss) (77,001) (72,886)
Retained Earnings 673,050 522,316
Total Common Shareholder's Equity 1,379,733 1,233,114
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 16,648 16,648
Subject to Mandatory Redemption 8,850 8,850
Long-term Debt 1,175,676 917,649

TOTAL CAPITALIZATION 2,580,907 2,176,261

OTHER NONCURRENT LIABILITIES 237,011 227,689

CURRENT LIABILITIES:
Long-term Debt Due Within One Year - General 89,665 89,665
Long-term Debt Due Within One Year - Affiliated Companies
60,000 60,000
Short-term Debt - Affiliated Companies - 275,000
Advances from Affiliates 239,328 129,979
Accounts Payable - General 139,007 170,563
Accounts Payable - Affiliated Companies 68,551 145,718
Customer Deposits 19,994 12,969
Taxes Accrued 165,222 111,778
Interest Accrued 24,644 18,809
Obligations Under Capital Leases 10,348 14,360
Risk Management Liabilities 93,511 61,839
Other 54,233 80,608

TOTAL CURRENT LIABILITIES 964,503 1,171,288

DEFERRED INCOME TAXES 875,344 794,387

DEFERRED INVESTMENT TAX CREDITS 17,986 18,748

LONG-TERM RISK MANAGEMENT LIABILITIES 62,313 39,702

DEFERRED CREDITS 44,355 28,957

COMMITMENTS AND CONTINGENCIES (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES $4,782,419 $4,457,032

See Notes to Financial Statements beginning on page L-1.

OHIO POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)

OPERATING ACTIVITIES:

Net Income $192,982 $ 64,051
Adjustments for Noncash Items:
Cumulative Effect of Accounting Changes (124,632) -
Depreciation and Amortization 61,551 62,621
Deferred Income Taxes (1,563) (4,649)
Deferred Property Taxes 14,878 14,717
Mark to Market of Risk Management Contracts 14,156 (16,055)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 1,626 (2,618)
Fuel, Materials and Supplies 13,541 (6,416)
Accrued Utility Revenues 4,429 (5,368)
Prepayments and Other (24,288) (11,822)
Accounts Payable (108,723) (75,824)
Customer Deposits 7,025 509
Taxes Accrued 53,444 21,498
Interest Accrued 5,835 7,171
Other Operating Assets (54,220) 1,388
Other Operating Liabilities (26,276) (8,819)
Net Cash Flows From Operating Activities 29,765 40,384

INVESTING ACTIVITIES:
Construction Expenditures (56,372) (66,312)
Proceeds from Sale of Property and Other 1,633 154
Net Cash Flows Used For Investing Activities (54,739) (66,158)

FINANCING ACTIVITIES:
Issuance of Long-term Debt 500,000 -
Change in Advances to Affiliates (net) 109,349 89,173
Retirement of Long-term Debt (240,000) -
Changes in Short-term Debt (net) (275,000) -
Dividends Paid on Common Stock (41,934) (32,582)
Dividends Paid on Cumulative Preferred Stock (314) (314)
Net Cash Flows From Financing Activities 52,101 56,277

Net Increase in Cash and Cash Equivalents 27,127 30,503
Cash and Cash Equivalents at Beginning of Period 5,285 8,848
Cash and Cash Equivalents at End of Period $ 32,412 $ 39,351

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $14,551,000 and
$13,900,000 and for income taxes was $(22,475,000) and $(5,574,000) in 2003 and
2002, respectively. Noncash acquisitions under capital leases were $98,000 in
2002.

See Notes to Financial Statements beginning on page L-1.

PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

FIRST QUARTER 2003 vs. FIRST QUARTER 2002

Public Service Company of Oklahoma (PSO) is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electricity to
approximately 505,000 retail customers in eastern and southwestern Oklahoma. PSO
sells electric power to other utilities, municipalities and rural electric
cooperatives.

Wholesale power marketing activities are conducted on PSO's behalf by AEPSC.
PSO, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.

Results of Operations

In 2003, Net Income increased by $2.3 million primarily resulting from increased
wholesale margins and increased transmission revenues, partially offset by
higher Interest Charges.

Changes in Operating Revenues

Increase (Decrease)
(in millions) %

Electric Generation 85.8 92
Electric Transmission and Distribution
5.6 10
Sales to AEP Affiliates 2.3 110
Total Operating Revenues $93.7 63

Electric Generation revenues increased in 2003 as a result of increased fuel
related revenues and retained wholesale margins.

The increase in Electric Transmission & Distribution revenues is due to
increased transmission revenues, as distribution revenues were virtually flat.

Sales to AEP Affiliates increased primarily due to higher prices.

Changes in Operating Expenses

Increase (Decrease)
(in millions) %

Fuel for Electric Generation $45.1 78
Purchased Electricity for Resale
14.8 N.M.
Purchased Electricity from AEP Affiliates
25.2 150
Other Operation 5.0 19
Maintenance (4.8) (34)
Depreciation and Amortization 0.6 3
Taxes Other Than Income Taxes 1.8 23
Income Taxes (Credits) 1.2 74
Total Operating Expenses $88.9 63

N.M. = Not Meaningful

The increase in Fuel for Electric Generation in 2003 was primarily due to higher
market prices for natural gas and increased MWH generation.

The increase in purchased electricity expenses was due to higher prices offset
in part by reduced MWH purchases.

Other Operation expense increased in 2003 primarily due to increased customer
related expenses and a credit posted in 2002 related to a true-up of rents
received from affiliates.

Maintenance expense decreased in 2003 largely as a result of the absence of
expenses to repair damage to overhead lines caused by a winter storm in 2002.

Taxes Other Than Income Taxes increased in 2003 primarily due to an increase in
ad valorem taxes.

Income Taxes increased in 2003 primarily due to an increase in pre-tax income.

Other Changes

Interest Charges increased due to increases in average long-term debt balances
and higher average interest rates.

PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:

Electric Generation $179,149 $ 93,337
Electric Transmission and Distribution 59,118 53,555
Sales to AEP Affiliates 4,395 2,094
TOTAL OPERATING REVENUES 242,662 148,986

OPERATING EXPENSES:
Fuel for Electric Generation 103,174 58,097
Purchased Electricity for Resale 12,491 (2,344)
Purchased Electricity from AEP Affiliates 42,107 16,845
Other Operation 31,618 26,639
Maintenance 9,394 14,169
Depreciation and Amortization 21,494 20,916
Taxes Other Than Income Taxes 9,646 7,848
Income Taxes (Credits) (408) (1,594)
TOTAL OPERATING EXPENSES 229,516 140,576

OPERATING INCOME 13,146 8,410

NONOPERATING INCOME 650 106

NONOPERATING EXPENSES 439 595

NONOPERATING INCOME TAX CREDIT 200 141

INTEREST CHARGES 12,866 9,710

NET INCOME (LOSS) 691 (1,648)

LESS: PREFERRED STOCK DIVIDEND REQUIREMENTS 53 53

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 638 $ (1,701)

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

See Notes to Financial Statements beginning on page L-1.

PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)

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

JANUARY 1, 2002 $157,230 $180,016 $142,994 $ - $480,240
Common Stock Dividends (22,455) (22,455)
Preferred Stock Dividends (53) (53)
457,732
Comprehensive Income (Loss):
Other Comprehensive Income - -
Net Income (Loss) (1,648) (1,648)
Total Comprehensive Income (Loss) (1,648)

MARCH 31, 2002 $157,230 $180,016 $118,838 $ - $456,084

JANUARY 1, 2003 $157,230 $180,016 $116,474 $(54,473) $399,247
Common Stock Dividends (7,500) (7,500)
Preferred Stock Dividends (53) (53)
Distribution of Investment in AEMT, Inc.
Preferred Shares to Parent (548) (548)
391,146

Comprehensive Income (Loss):
Other Comprehensive Income (Loss),
Net of Taxes:
Minimum Pension Liability (58) (58)
Unrealized Loss on Cash Flow
Power Hedges (1,197) (1,197)
Net Income 691 691
Total Comprehensive Income (Loss) (564)

MARCH 31, 2003 $157,230 $180,016 $109,064 $(55,728) $390,582

See Notes to Financial Statements beginning on page L-1.

PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)
ASSETS

ELECTRIC UTILITY PLANT:

Production $1,040,642 $1,040,520
Transmission 431,553 432,846
Distribution 991,688 990,947
General 200,630 206,747
Construction Work in Progress 95,186 88,444
Total Electric Utility Plant 2,759,699 2,759,504
Accumulated Depreciation and Amortization 1,241,480 1,239,855
NET ELECTRIC UTILITY PLANT 1,518,219 1,519,649

OTHER PROPERTY AND INVESTMENTS 4,931 5,383

LONG-TERM RISK MANAGEMENT ASSETS 7,484 4,481

CURRENT ASSETS:
Cash and Cash Equivalents 15,975 16,774
Accounts Receivable:
Customers 30,626 31,687
Affiliated Companies 15,939 14,139
Allowance for Uncollectible Accounts (54) (84)
Fuel Inventory 18,941 19,973
Materials and Supplies 38,178 37,375
Under-recovered Fuel Costs 77,701 76,470
Risk Management Assets 7,100 3,841
Prepayments and Other 3,643 2,735
TOTAL CURRENT ASSETS 208,049 202,910

REGULATORY ASSETS 25,417 26,150

DEFERRED CHARGES 45,755 18,117

TOTAL ASSETS $1,809,855 $1,776,690

See Notes to Financial Statements beginning on page L-1.

PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
Common Stock - $15 Par Value:
Authorized Shares: 11,000,000
Issued Shares: 10,482,000
Outstanding Shares: 9,013,000 $ 157,230 $ 157,230
Paid-in Capital 180,016 180,016
Accumulated Other Comprehensive Income (Loss) (55,728) (54,473)
Retained Earnings 109,064 116,474
Total Common Shareholder's Equity 390,582 399,247

Cumulative Preferred Stock Not Subject
to Mandatory Redemption 5,267 5,267
PSO-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely Junior
Subordinated Debentures of PSO 75,000 75,000
Long-term Debt 445,514 445,437

TOTAL CAPITALIZATION 916,363 924,951

OTHER NONCURRENT LIABILITIES 54,853 54,761

CURRENT LIABILITIES:
Long-term Debt Due Within One Year 100,000 100,000
Advances from Affiliates 119,820 86,105
Accounts Payable - General 74,807 61,169
Accounts Payable - Affiliated Companies 59,616 78,076
Customer Deposits 23,863 21,789
Taxes Accrued 22,732 6,854
Interest Accrued 9,384 6,979
Risk Management Liabilities 6,658 3,260
Other 15,210 24,957

TOTAL CURRENT LIABILITIES 432,090 389,189

DEFERRED INCOME TAXES 342,529 341,396

DEFERRED INVESTMENT TAX CREDITS 31,754 32,201

REGULATORY LIABILITIES AND DEFERRED CREDITS 27,392 32,611

LONG-TERM RISK MANAGEMENT LIABILITIES 4,874 1,581

COMMITMENTS AND CONTINGENCIES (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES $1,809,855 $1,776,690

See Notes to Financial Statements beginning on page L-1.

PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)

OPERATING ACTIVITIES:

Net Income (Loss) $ 691 $ (1,648)
Adjustments to Reconcile Net Income (Loss) to Net Cash
Flows Used For Operating Activities:
Depreciation and Amortization 21,494 20,916
Deferred Income Taxes 1,309 1,886
Deferred Investment Tax Credits (447) (448)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (769) (3,733)
Fuel, Materials and Supplies 229 (1,346)
Accounts Payable (4,822) (31,427)
Taxes Accrued 15,878 9,407
Deferred Property Taxes (24,413) (21,210)
Fuel Recovery (1,231) 2,380
Changes in Other Assets (11,662) (7,606)
Changes in Other Liabilities (5,606) 4,032
Net Cash Flows Used For Operating Activities (9,349) (28,797)

INVESTING ACTIVITIES:
Construction Expenditures (17,612) (10,559)
Net Cash Flows Used For Investing Activities (17,612) (10,559)

FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 33,715 63,910
Dividends Paid on Common Stock (7,500) (22,455)
Dividends Paid on Cumulative Preferred Stock (53) (53)
Net Cash Flows From Financing Activities 26,162 41,402

Net Increase (Decrease) in Cash and Cash Equivalents (799) 2,046
Cash and Cash Equivalents at Beginning of Period 16,774 5,795
Cash and Cash Equivalents at End of Period $ 15,975 $ 7,841

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $9,653,000 and
$5,157,000 and for income taxes was $(959,000) and $1,783,000 in 2003 and 2002,
respectively.

There was a non-cash distribution of $548,000 in preferred shares in AEMT, Inc. to PSO's Parent Company.

See Notes to Financial Statements beginning on page L-1.

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

FIRST QUARTER 2003 vs. FIRST QUARTER 2002

Southwestern Electric Power Company (SWEPCo) is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electric power to
approximately 437,000 retail customers in northeastern Texas, northwestern
Louisiana and western Arkansas. SWEPCo sells electric power to other utilities,
municipalities and rural electric cooperatives.

Wholesale power marketing activities are conducted on SWEPCo's behalf by AEPSC.
SWEPCo, along with the other AEP electric operating subsidiaries, shares in
AEP's electric power transactions with other utility systems and power
marketers.

Results of Operations
Net Income increased $10.8 million or 133% for the quarter. The increase
resulted primarily from the cumulative effect of accounting changes due to the
adoption of SFAS 143.

Changes in Operating Revenues

Increase (Decrease)
(in millions) %

Electric Generation $24.9 19
Electric Transmission and Distribution
(1.3) (2)
Sales to AEP Affiliates 9.4 41
Total Operating Revenues $33.0 15

Electric Generation revenues increased in 2003 due to higher
wholesale revenues, a slight increase in customers, coupled with a more
profitable mix of sales in higher rate categories.

Sales to AEP Affiliates increased primarily due to higher prices.

Changes in Operating Expenses

Increase
(Decrease)
(in
millions) %

Fuel for Electric Generation $14.1 16
Purchased Electricity for Resale 8.5 209
Purchased Electricity from AEP Affiliates
5.3 97
Other Operation (1.3) (3)
Maintenance 1.0 8
Depreciation and Amortization (2.1) (7)
Taxes Other Than Income Taxes 1.4 10
Income Taxes 2.5 91
Total Operating Expenses $29.4 15

Fuel for Electric Generation increased in 2003 due to both increased generation
and higher fuel costs.

In 2003, Purchased Electricity increased overall due to higher costs for
purchased power offset in part by reduced MWHs purchased.

Maintenance expense increased in 2003 as a result of scheduled maintenance at
several power plants.

The decrease in Depreciation and Amortization expense was due primarily to the
restoration of a regulatory asset for recovery of a fuel related cost allowed in
a fuel proceeding for the Arkansas portion of SWEPCo's operations.

In 2003, Taxes Other Than Income Taxes increased due to increased payroll and
state gross receipts taxes.

Income Taxes attributable to operations increased in 2003 due to increased
pre-tax income.

Other Changes
Nonoperating Income increased in 2003 due primarily to increased interest income
and AFUDC.

In 2003, Interest Charges increased due to increased levels of debt outstanding
and higher average interest rates.

Cumulative Effect of Accounting 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
Notes 2 and 3).

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)
OPERATING REVENUES:

Electric Generation $156,681 $131,761
Electric Transmission and Distribution 66,242 67,539
Sales to AEP Affiliates 32,355 22,959
TOTAL OPERATING REVENUES 255,278 222,259

OPERATING EXPENSES:
Fuel for Electric Generation 103,010 88,883
Purchased Electricity for Resale 12,567 4,070
Purchased Electricity from AEP Affiliates 10,810 5,485
Other Operation 40,857 42,151
Maintenance 12,817 11,838
Depreciation and Amortization 28,035 30,140
Taxes Other Than Income Taxes 15,873 14,466
Income Taxes 5,265 2,757
TOTAL OPERATING EXPENSES 229,234 199,790

OPERATING INCOME 26,044 22,469

NONOPERATING INCOME 872 102

NONOPERATING EXPENSES 521 566

NONOPERATING INCOME TAX EXPENSE 50 28

INTEREST CHARGES 15,854 13,818

NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 10,491 8,159

CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 8,517 -

NET INCOME 19,008 8,159

PREFERRED STOCK DIVIDEND REQUIREMENTS 57 57

EARNINGS APPLICABLE TO COMMON STOCK $ 18,951 $ 8,102

The common stock of SWEPCo is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
(UNAUDITED)

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

JANUARY 1, 2002 $135,660 $245,003 $308,915 $ - $689,578
Common Stock Dividends (18,964) (18,964)
Preferred Stock Dividends (57) (57)
670,557
Comprehensive Income:
Other Comprehensive Income - -
Net Income 8,159 8,159
Total Comprehensive Income 8,159

MARCH 31, 2002 $135,660 $245,003 $298,053 $ - $678,716

JANUARY 1, 2003 $135,660 $245,003 $334,789 $(53,683) $661,769
Common Stock Dividends (18,199) (18,199)
Preferred Stock Dividends (57) (57)
643,513
Comprehensive Income:
Other Comprehensive Income (Loss),
Net of Taxes:
Unrealized Loss on Cash Flow
Power Hedges (1,367) (1,367)
Net Income 19,008 19,008
Total Comprehensive Income 17,641

MARCH 31, 2003 $135,660 $245,003 $335,541 $(55,050) $661,154

See Notes to Financial Statements beginning on page L-1.

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)

ASSETS

ELECTRIC UTILITY PLANT:

Production $1,503,521 $1,503,722
Transmission 575,856 575,003
Distribution 1,040,007 1,063,564
General 402,229 378,130
Construction Work in Progress 85,836 75,755
Total Electric Utility Plant 3,607,449 3,596,174
Accumulated Depreciation and Amortization 1,702,196 1,697,338
NET ELECTRIC UTILITY PLANT 1,905,253 1,898,836

OTHER PROPERTY AND INVESTMENTS 5,793 5,978

LONG-TERM RISK MANAGEMENT ASSETS 8,549 5,119

CURRENT ASSETS:
Cash and Cash Equivalents 7,163 2,069
Accounts Receivable:
Customers 62,237 62,359
Affiliated Companies 20,651 19,253
Allowance for Uncollectible Accounts (2,116) (2,128)
Fuel Inventory 58,814 61,741
Materials and Supplies 33,806 33,539
Under-recovered Fuel Costs - 2,865
Risk Management Assets 8,110 4,388
Prepayments and Other 18,565 17,851
TOTAL CURRENT ASSETS 207,230 201,937

REGULATORY ASSETS 52,645 49,233

DEFERRED CHARGES 74,034 47,572

TOTAL ASSETS $2,253,504 $2,208,675

See Notes to Financial Statements beginning on page L-1.

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, 2003 December 31, 2002
(in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
Common Stock - $18 Par Value:
Authorized - 7,600,000 Shares
Outstanding - 7,536,640 Shares $ 135,660 $ 135,660
Paid-in Capital 245,003 245,003
Accumulated Other Comprehensive Income (Loss) (55,050) (53,683)
Retained Earnings 335,541 334,789
Total Common Shareholder's Equity 661,154 661,769
Preferred Stock 4,700 4,701
SWEPCo-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely Junior
Subordinated Debentures of SWEPCo 110,000 110,000
Long-term Debt 637,496 637,853
TOTAL CAPITALIZATION 1,413,350 1,414,323

OTHER NONCURRENT LIABILITIES 80,142 78,494

CURRENT LIABILITIES:
Long-term Debt Due Within One Year 595 55,595
Advances from Affiliates, net 103,123 23,239
Accounts Payable - General 56,856 62,139
Accounts Payable - Affiliated Companies 46,762 58,773
Customer Deposits 22,220 20,110
Taxes Accrued 60,263 19,081
Interest Accrued 12,367 17,051
Risk Management Liabilities 7,606 3,724
Over-recovered Fuel 17,090 17,226
Other 19,781 34,565
TOTAL CURRENT LIABILITIES 346,663 311,503

DEFERRED INCOME TAXES 341,398 341,064

DEFERRED INVESTMENT TAX CREDITS 43,109 44,190

REGULATORY LIABILITIES AND DEFERRED CREDITS 23,274 17,295

LONG-TERM RISK MANAGEMENT LIABILITIES 5,568 1,806

COMMITMENTS AND CONTINGENCIES (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES $2,253,504 $2,208,675

See Notes to Financial Statements beginning on page L-1.

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

Three Months Ended March 31,
2003 2002
(in thousands)

OPERATING ACTIVITIES:

Net Income $19,008 $8,159
Adjustments to Reconcile Net Income to
Net Cash Flows From Operating Activities:
Depreciation and Amortization 28,035 30,140
Deferred Income Taxes (4,034) (3,930)
Deferred Investment Tax Credits (1,081) (1,131)
Cumulative Effect of Accounting Changes (8,517) -
Mark-to-Market of Risk Management Contracts (1,462) 7,695
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (1,288) (9,762)
Fuel, Materials and Supplies 2,660 (18,504)
Accounts Payable (17,294) (2,646)
Taxes Accrued 41,182 27,254
Deferred Property Taxes (27,945) (27,217)
Fuel Recovery 2,729 10,391
Change in Other Assets 1,461 9,511
Change in Other Liabilities (9,120) (7,260)
Net Cash Flows From Operating Activities 24,334 22,700

INVESTING ACTIVITIES:
Construction Expenditures (25,702) (11,715)
Proceeds from Sale of Assets and Other 284 -
Net Cash Flows Used For Investing Activities (25,418) (11,715)

FINANCING ACTIVITIES:
Retirement of Long-term Debt (55,450) (150,450)
Change in Advances from Affiliates (net) 79,884 154,959
Dividends Paid on Common Stock (18,199) (18,964)
Dividends Paid on Cumulative Preferred Stock (57) (57)
Net Cash Flows From (Used For) Financing Activities 6,178 (14,512)

Net Increase (Decrease) in Cash and Cash Equivalents 5,094 (3,527)
Cash and Cash Equivalents at Beginning of Period 2,069 5,415
Cash and Cash Equivalents at End of Period $ 7,163 $ 1,888

Supplemental Disclosure:
Cash (received) paid for interest net of capitalized amounts was $17,963,000 and
$10,203,000 and for income taxes was ($755,000) and $8,581,000 in 2003 and 2002,
respectively.

See Notes to Financial Statements beginning on page L-1.

COMBINED NOTES TO FINANCIAL STATEMENTS
MARCH 31, 2003
(UNAUDITED)

The notes to financial statements that follow are a combined presentation for
AEP and its subsidiary registrants. The following list indicates the registrants
to which the footnotes apply:

1. General AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

2. Significant
Accounting
Policies and New
Accounting
Pronouncements AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

3. Extraordinary Items and
Cumulative Effect AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

4. Goodwill and
Other Intangible Assets AEP, SWEPCo

5. Rate Matters AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

6. Customer Choice
and Industry Restructuring AEP, APCo, CSPCo, I&M, OPCo, SWEPCo, TCC, TNC

7. Commitments and
Contingencies AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

8. Guarantees AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO,

9. Sustained Earnings
Improvement
Initiative AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

10. Dispositions,
Discontinued
Operations and
Assets Held for Sale AEP, APCo, CSPCo, I&M, KPCo, OPCo

11. Business Segments AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

12. Leases AEP, OPCo

13. Minority Interest
in Finance Subsidiary AEP

14. Financing and Related
Activities AEP, CSPCo, I&M, OPCo, SWEPCo, TCC, TNC

1. GENERAL

The accompanying unaudited interim financial statements should be read
in conjunction with the 2002 Annual Report as incorporated in and filed
with the Form 10-K.

Certain prior period financial statement items have been reclassified to
conform to current period presentation. These items include the effects
of discontinued operations, gains and losses associated with derivative
trading contracts presented on a net basis in accordance with EITF 02-3,
and counterparty netting in accordance with FASB Interpretation No. 39,
"Offsetting of Amounts Related to Certain Contracts" and EITF Topic
D-43, "Assurance That a Right of Setoff is Enforceable in a Bankruptcy
under FASB Interpretation No. 39". Such reclassifications had no effect
of previously reported Net Income. In addition, management determined
that certain amounts were misclassified in AEP's 2002 Consolidated
Statement of Operations resulting from errors in the coding of certain
intercompany transactions and transactions associated with our UK
operations. As a result, in the first quarter of 2002 Gas Pipeline and
Storage revenues decreased by $47 million, Investments revenue decreased
by $10 million, Fuel for Electric Generation decreased by $27 million,
and Purchased Gas for Resale decreased by $58 million. Expenses for
Maintenance and Other Operation increased by $21 million and Taxes Other
Than Income Taxes increased by $7 million. These revisions had no effect
on Operating Income or Net Loss.

In the opinion of management, the unaudited interim financial statements
reflect all normal recurring accruals and adjustments which are
necessary for a fair presentation of the results of operations for
interim periods.

2. SIGNIFICANT ACCOUNTING POLICIES AND NEW ACCOUNTING PRONOUNCEMENTS

Significant Accounting Policies

Components of Accumulated Other Comprehensive Income (Loss) - Other
comprehensive income (loss) is included on the balance sheet in the
equity section. The following table provides the components that
comprise the balance sheet amount in Accumulated Other Comprehensive
Income (Loss) for AEP:

March 31, December 31,
2003 2002
Components (in millions)

Foreign Currency Translation Adjustments $ 17 $ 4
Unrealized Losses on Securities (1) (2)
Unrealized Losses on Cash Flow Hedges (38) (16)
Minimum Pension Liability (580) (595)
$(602) $(609)

Accumulated Other Comprehensive Income (Loss) for AEP registrant
subsidiaries as of March 31, 2003, and December 31, 2002 is shown in the
following table.

March 31, December 31,
2003 2002
Components (in thousands)

Unrealized Losses
on Cash Flow Hedges:
APCo $ (14,438) $ (1,920)
CSPCo (7,610) (267)
I&M (8,143) (286)
KPCo (2,543) 322
OPCo (10,477) (738)
PSO (1,239) (42)
SWEPCo (1,415) (48)
TCC (1,054) (36)
TNC (436) (15)
Non-Registrants 9,220 (13,368)
$ (38,135) $(16,398)

Minimum Pension Liability:
APCo $(70,162) $(70,162)
CSPCo (59,090) (59,090)
I&M (40,201) (40,201)
KPCo (9,773) (9,773)
OPCo (66,524) (72,148)
PSO (54,489) (54,431)
SWEPCo (53,635) (53,635)
TCC (73,124) (73,124)
TNC (30,755) (30,748)
Non-Registrants (121,879) (131,898)
$(579,632) $(595,210)

The following tables represent the activity in Other Comprehensive
Income (Loss) related to the effect of adopting SFAS 133 for derivative
contracts that qualify as cash flow hedges at March 31, 2003:

Domestic Domestic Foreign AEP
Power Gas Currency Interest Rate Consolidated
(in millions)

Accumulated OCI, December 31, 2002 $ (1) $ - $(3) $(12) $(16)
Changes in Fair Value (a) (65) 8 5 6 (46)
Reclassifications from OCI to Net
Income (b) 23 - - 1 24
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $(43) $ 8 $ 2 $ (5) $(38)

APCo Domestic Foreign APCo
Power Currency Interest Rate Consolidated
(in thousands)

Accumulated OCI, December 31, 2002 $ (394) $(190) $(1,336) $(1,920)
Changes in Fair Value (a) (19,201) - (104) (19,305)
Reclassifications from OCI to Net
Income (b) 6,649 2 136 6,787
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $(12,946) $(188) $(1,304) $(14,438)

CSPCo Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (267)
Changes in Fair Value (a) (11,251)
Reclassifications from OCI to Net
Income (b) 3,908
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $(7,610)

I&M Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (286)
Changes in Fair Value (a) (12,039)
Reclassifications from OCI to Net
Income (b) 4,182
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $(8,143)

KPCo Domestic KPCo
Power Interest Rate Consolidated
(in thousands)

Accumulated OCI, December 31, 2002 $ (103) $425 $ 322
Changes in Fair Value (a) (4,357) (43) (4,400)
Reclassifications from OCI to Net
Income (b) 1,513 22 1,535
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $(2,947) $404 $(2,543)

OPCo Domestic Foreign OPCo
Power Currency Consolidated
(in thousands)

Accumulated OCI, December 31, 2002 $ (354) $(384) $ (738)
Changes in Fair Value (a) (14,928) - (14,928)
Reclassifications from OCI to Net
Income (b) 5,186 3 5,189
Accumulate OCI Derivative Gain (Loss)
March 31, 2003 (c) $(10,096) $(381) $(10,477)

PSO Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (42)
Changes in Fair Value (a) (1,833)
Reclassifications from OCI to Net
Income (b) 636
Accumulated OCI Derivative Gain (Loss) March
31, 2003 (c) $(1,239)

SWEPCo Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (48)
Changes in Fair Value (a) (2,094)
Reclassifications from OCI to Net
Income (b) 727
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $(1,415)

TCC Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (36)
Changes in Fair Value (a) (1,559)
Reclassifications from OCI to Net
Income (b) 541
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $(1,054)

TNC Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (15)
Changes in Fair Value (a) (645)
Reclassifications from OCI to Net
Income (b) 224
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 (c) $ (436)

(a) Changes in fair value - 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 - 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.
(c) Accumulated OCI Derivative Gain (Loss) March 31, 2003 - 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.

Approximately $31 million of net losses from cash flow hedges in
Accumulated Other Comprehensive Income (Loss) at March 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
Accumulated Other Comprehensive Income to Net Income can differ as a
result of market price changes. The maximum term for which the exposure
to the variability of future cash flows is being hedged is five years.

Common Stock Options and Restricted Shares - AEP has two stock-based
employee compensation plans with outstanding stock options. AEP accounts
for these plans under the recognition and measurement principles of APB
Opinion No. 25, Accounting for Stock Issued to Employees (APB 25) and
related Interpretations. No stock-based employee compensation expense is
reflected in AEP's 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.

AEP awarded 102,513 restricted stock units to certain AEP employees in
March 2003. The units vest in equal one-third increments in January
2004, 2005 and 2006. At each vesting date, shares will be issued at no
cost to the employee. In accordance with APB 25, the compensation
expense of approximately $2.3 million will be expensed over the vesting
period of the units. The value of the units was based on a $21.95 per
share value at the grant date. The amount of compensation expense
recognized during the first quarter of 2003 in AEP's Consolidated
Statements of Operations was $463 thousand, pre-tax.

The following table illustrates the effect on AEP's Net Income (Loss)
and earnings (loss) per share as if AEP had applied the fair value
recognition provisions of FASB Statement No. 123, "Accounting for
Stock-Based Compensation", to stock-based employee compensation awards:

Three Months Ended
March 31,
2003 2002
(in millions, except per share data)

Net Income (loss), as reported $ 440 $(169)
Add: Stock-based compensation expense included in
reported net income, net of related tax effects - (a) -
Deduct: Stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects (1) (2)
Pro Forma Net Income (Loss) $ 439 $ (171)

Earnings (Loss) per Share:
Basic - as Reported $1.24 $(0.52)
Basic - Pro Forma 1.23 (0.53)

Diluted - as Reported $1.24 $(0.52)
Diluted - Pro Forma 1.23 (0.53)

(a) Compensation expense related to restricted units during the first
quarter of 2003 was $301 thousand, net of tax.

New Accounting Pronouncements

AEP 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 will 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 that had previously been recorded for
generation that does not qualify as a legal obligation which was
collected in depreciation rates by certain formerly regulated
subsidiaries.

AEP has completed a review of its asset retirement obligations and
concluded that at present, it has related legal liabilities for nuclear
decommissioning costs for its Cook Plant and its 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 AEP presently recovers its nuclear decommissioning
costs in its regulated cash flow and thus had existing balances recorded
for such nuclear retirement obligations, it recognized the cumulative
difference in the amount already provided through rates versus the new
methodology of 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 AEP's regulated operations.
AEP recorded an unfavorable cumulative effect of $45.4 million after tax
for the non-regulated operations ($38.0 million related to Ash Ponds and
$7.4 million related to U.K. Plants, Wind Mills and Coal Operations).

Certain of AEP's operating companies have recorded in Accumulated
Depreciation and Amortization, removal costs collected from rate payers
for certain assets that do not have associated legal asset retirement
obligations. To the extent that such operating companies have now been
deregulated, AEP reversed the balance of such removal costs, totaling
$287.2 million after tax, from accumulated depreciation which resulted
in a net favorable cumulative effect. However, AEP did not adjust the
balance of such removal costs for its regulated operations, and in
accordance with the present method of recovery, will continue to record
such amounts through depreciation expense and accumulated depreciation.
AEP estimates that it has approximately $1.2 billion of such regulatory
liabilities recorded in Accumulated Depreciation and Amortization as of
both March 31, 2003 and December 31, 2002.

The following is a summary by registrant of the regulatory liabilities
for removal costs included in Accumulated Depreciation and Amortization:

March 31, 2003 December 31,2002
(in millions)
AEGCo $ 28.4 $ 28.0
APCo 94.5 94.6
CSPCo 96.7 96.0
I&M 252.7 250.5
KPCo 21.9 23.7
OPCo 96.2 97.0
PSO 198.9 202.6
SWEPCo 220.7 219.5
TCC 97.7 97.5
TNC 74.7 75.0
Non-Registrants 0.5 0.5
$1,182.9 $1,184.9

The net favorable cumulative effect of the change in accounting
principle consists of the following:

Pre-tax After-tax
Income (Loss) Income (Loss)
(in millions)

Ash Ponds $ (62.8) $ (38.0)
UK Plants, Wind Mills and Coal
Operations (11.3) (7.4)
Reversal of Cost of Removal
472.6 287.2
Total $ 398.5 $ 241.8

The following is a summary by registrant of the cumulative effect of
changes in accounting principles:

Pre-tax Income (Loss) After-tax Income(Loss)

U. K. Plants, U. K. Plants,
Wind Mills Reversal of Wind Mills Reversal of
and Coal Cost of and Coal Cost of Removal
Ash Ponds Operations Removal Ash Ponds Operations
(in millions)

AEGCo $ - $ - $ - $ - $ - $ -
APCo (18.2) - 146.5 (11.4) - 91.7
CSPCo (7.8) - 56.8 (4.7) - 33.9
I&M - - - - - -
KPCo - - - - - -
OPCo (36.8) - 250.4 (21.9) - 149.3
SWEPCo - - 13.0 - - 8.4
TCC - - - - - -
TNC - - 4.7 - - 3.1
Other - (11.3) 1.2 - (7.4) 0.8
$(62.8) $(11.3) $ 472.6 $(38.0) $(7.4) $287.2

AEP has identified, but not recognized, asset retirement obligation
liabilities related to electric transmission and distribution and gas
distribution assets, as a result of certain easements on property on
which AEP has assets. Generally, such easements are perpetual and
require only the retirement and removal of AEP's assets upon the
cessation of the property's use. The retirement obligation is not
estimable for such easements since AEP plans to use its properties
indefinitely. The retirement obligation would only be recognized if and
when AEP abandons or ceases the use of specific easements.

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 12.7 1.4 0.4 14.5

Asset Retirement Obligation
Liability
at March 31, 2003 $731.0 $71.2 $37.6 $839.8

The following is a reconciliation of beginning and ending aggregate
carrying amounts of asset retirement obligations by registrant following
the adoption of SFAS 143:

Balance At Balance at
January 1, 2003 Accretion March 31, 2003
(in millions)

AEGCo (a) $ 1.1 $ - $ 1.1
APCo (a) 20.1 0.4 20.5
CSPCo (a) 8.1 0.2
I&M (b) 516.1 9.0 525.1
OPCo (a) 39.5 0.8 40.3
TCC (c) 203.2 3.8 207.0
Other (d) 37.2 0.3 37.5
$825.3 $14.5 $839.8

(a) Consists of asset retirement obligations related to ash ponds.
(b) Consists of asset retirement obligations related to ash ponds ($1.1
million at March 31, 2003) and nuclear decommissioning costs for the Cook
Plant ($524 million at March 31, 2003). (c) Consists of asset retirement
obligations related to nuclear decommissioning costs for STP. (d)
Consists of asset retirement obligations related to wind farms, the U.K.
plants and certain coal mining facilities.

Accretion expense is included in Maintenance and Other Operation in
AEP's accompanying Consolidated Statements of Operations and in Other
Operation expense in the Income Statements of the other individual
registrants.

As of March 31, 2003 and December 31, 2002, the fair value of assets
that are legally restricted for purposes of settling the nuclear
decommissioning liabilities totaled $706 million and $716 million,
respectively, recorded in Other Assets on AEP's Consolidated Balance
Sheets.

Pro forma net income and earnings per share have not been presented for
the quarter ended March 31, 2002 or the years ended December 31, 2002,
2001 and 2000 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 for those periods.

The following is a summary by registrant of the pro forma liability for
asset retirement obligations which has been calculated as if SFAS 143
had been adopted as of the beginning of each period presented:

December 31, 2002 December 31,2001
(in millions)
AEGCo $ 1.0 $ 1.0
APCo 20.2 18.7
CSPCo 8.1 7.5
I&M 516.1 481.4
KPCo - -
OPCo 39.5 36.5
PSO - -
SWEPCo - -
TCC 203.2 188.8
TNC - -
Non-Registrants 37.2 35.3
$825.3 $769.2

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, "Recognition and
Reporting of Gains and Losses on Energy Contracts under Issue
No. 98-10 and 00-17" (EITF 02-3). See Note 3.

FASB Stock-based Compensation Project

In March 2003, the FASB added a project to address issues related to
share-based payments. In April 2003, the FASB decided that goods and
services, including employee stock options, received in exchange for
stock-based compensation should be recognized in the income statement as
an expense, with the cost measured at fair value. An exposure draft is
expected by the end of this year and a final statement could be
effective in 2004.

SFAS 149 "Amendment of Statement 133 on Derivative Instruments
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 SFAS 133 for derivative instruments, including
certain derivative instruments embedded in other contracts and for
hedging activities. SFAS 149 also amends certain other existing
pronouncements. SFAS 149 is effective for AEP for contracts entered into
or modified after June 30, 2003. AEP and its subsidiaries are evaluating
the impact of adopting the requirements of SFAS 149.

3. EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT

Cumulative Effect of Accounting Changes - 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 resulted in a $350 million after tax net transitional loss in
2002 for the U.K. and Australian operations and is reported in AEP's
Consolidated Statements of Operations as a cumulative effect of
accounting change.

SFAS 143, "Accounting for Asset Retirement Obligations", (see Note 2) is
effective for AEP on January 1, 2003. SFAS 143 generally applies to
legal obligations associated with the retirement of long-lived assets. A
company is required to recognize an estimated liability for any legal
obligations associated with the future retirement of its long-lived
assets. The liability is measured at fair value and is capitalized as
part of the related asset's capitalized cost. The increase in the
capitalized cost is included in determining depreciation expense over
the expected useful life of the asset. The catch-up effect of adopting
SFAS 143 will be recorded as a cumulative effect of an accounting
change. Additionally, because the asset retirement obligation is
recorded initially at fair value, accretion expense (similar to
interest) will be recognized each period as an operating expense in the
statement of operations. AEP has recorded $242 million in after tax
income related to the recording of Asset Retirement Obligations in AEP's
Consolidated Statements of Operations as a cumulative effect of
accounting change.

EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. Under
EITF 02-3, mark-to-market accounting is precluded for energy trading
contracts that are not derivatives pursuant to SFAS 133. The consensus
to rescind EITF 98-10 will also eliminate any basis for recognizing
physical inventories at fair value other than as provided by GAAP. The
consensus to rescind EITF 98-10 is effective for all new contracts
entered into (and physical inventory purchased) after October 25, 2002.
The consensus is effective for fiscal periods beginning after December
15, 2002, and applies to all energy trading contracts that existed on or
before October 25, 2002 that remain in effect as of the date of
implementation, January 1, 2003. Effective January 2003, nonderivative
energy contracts entered into prior to October 25, 2002 are required to
be accounted for on a settlement basis and inventory is required to be
presented at the lower of cost or market. The effect of implementing
this consensus is reported as a cumulative effect of an accounting
change. Such contracts and inventory are accounted for at fair value
through December 31, 2002. Energy contracts that qualify as derivatives
were accounted for at fair value under SFAS 133. AEP has recorded a $49
million after tax charge against net income as Accounting for Risk
Management Contracts in AEP's Consolidated Statements of Operations in
Cumulative Effect of Accounting Changes. This amount will be recognized
when the positions settle.

See table below for details of the Cumulative Effect of Accounting
Changes.

Three Months Ended March 31,
Description 2003 2002
(in millions)

Accounting for Risk Management Contracts (EITF 02-3) $(49) $ -
Asset Retirement Obligations (SFAS 143) 242 -
Goodwill and Other
Intangible Assets - (350)
Total $193 $(350)

The following is a summary by registrant of the cumulative effect of
changes in accounting principles for the adoptions of SFAS 143 and EITF
02-3:

SFAS 143 Cumulative Effect EITF 02-3 Cumulative Effect
Pre-tax After-tax After-tax
Income Income Income
(Loss) (Loss) Pre-tax (Loss)
Income
(Loss)
(in millions) (in millions)

APCo $128.3 $ 80.3 $ (4.7) $ (3.0)
CSPCo 49.0 29.3 (3.1) (2.0)
I&M - - (4.9) (3.2)
KPCo - - (1.7) (1.1)
OPCo 213.6 127.3 (4.2) (2.7)
SWEPCo 13.0 8.4 0.2 0.1
TCC - - 0.2 0.1
TNC 4.7 3.1 - -
Other (10.1) (6.6) (49.5) (37.3)
$398.5 $241.8 $(67.7) $(49.1)

4. GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

The changes in the carrying amount of goodwill for the three months
ended March 31, 2003 by operating segment are:

Investments
Utility Gas U.K. AEP
Operations Operations Operations Other Consolidated
(in millions)

Balance January 1, 2003 $37.1 $306.3 $11.1 $41.5 $396.0
Foreign currency
exchange rate changes - - (0.3) - (0.3)
Balance March 31, 2003 $37.1 $306.3 $10.8 $41.5 $395.7

Acquired Intangible Assets

The gross carrying amount, accumulated amortization and amortization
life by major asset class are shown in the following table:

March 31, 2003 December 31, 2002

Gross Carrying Gross
Amortization Amount Accumulated Carrying Accumulated
Life Amortization Amount Amortization
(in millions)
Software and customer list
2 $ 0.5 $0.3 $ 0.5 $0.2
Software acquired 3 0.4 - 0.5 -
Patent 5 0.1 - 0.1 -
administration of contracts
7 2.4 0.6 2.4 0.6
Purchased technology 10 10.3 1.3 10.3 1.0
Advanced royalties 10 29.4 5.4 29.4 4.7

Total $43.1 $7.6 $43.2 $6.5

Amortization of intangible assets was $1.2 million ($1.1 million net of
foreign currency translation) and $1.0 million (no foreign currency
translation) for the three months ended March 31, 2003 and March 31,
2002.

Estimated aggregate amortization expense is $4.4 million for each year
2004 through 2006, $4.3 million in 2007, $4.1 million in 2008 and $4.0
million in 2009.

Fluctuations in the gross carrying values since December 31, 2002
represent changes in the foreign currency exchange rate.

Intangible assets subject to amortization are recorded in Other Assets in
the AEP Consolidated Balance Sheets.

5. RATE MATTERS

Fuel in SPP - Affecting AEP, SWEPCo and TNC

As discussed in Note 6 of the 2002 Annual Report, in 2001, the PUCT
delayed the start of customer choice in the SPP area of Texas. In May
2003, the PUCT approved a stipulation that delays competition in the SPP
areas of Texas until no sooner than January 1, 2007. All of SWEPCo's
Texas service territory and a small portion of TNC's service territory
are in the SPP. SWEPCo's existing Texas fuel cost recovery procedures
will continue until competition begins. SWEPCo will continue to set fuel
factors and determine final fuel costs in fuel reconciliation proceedings
during the SPP delay period. The PUCT has ruled that TNC fuel factors in
the SPP area will be based upon the price-to-beat fuel factors offered by
the retail electric provider (REP) in the ERCOT portion of TNC's service
territory. 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, should be used to reconcile fuel costs in its
SPP area. The adjustments removed $3.71 per MWH from reconcilable fuel
expense. This adjustment will reduce revenues received from TNC's SPP
customers by approximately $400,000 annually. These customers are now
served by SWEPCo's REP.

TNC Fuel Reconciliation - Affecting AEP and TNC

In June 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 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 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. TNC's SPP customers will continue to be
subject to fuel reconciliations until competition begins in SPP. The
under-recovery balance at December 31, 2001 for TNC's service within SPP
was $0.7 million including interest.

In March 2003, the Administrative Law Judges (ALJ) in this proceeding
filed their Proposal for Decision (PFD). The PFD recommends that TNC's
under-recovered retail fuel balance be reduced by approximately $12.5
million. In March 2003, TNC established a reserve of $13 million,
including interest, based on the PFD's recommendations. On April 22,
2003, TNC and intervenors in this proceeding filed exceptions to the PFD.
The PUCT is scheduled to consider the PFD on May 22, 2003 and is expected
to issue a final order by mid 2003. Any further adverse ruling from the
PUCT could have a material impact on future results of operations, cash
flows and financial condition.

TCC Fuel Reconciliation - Affecting AEP and TCC

In December 2002, TCC filed with the PUCT to reconcile fuel costs and to
defer its over-recovery of fuel for inclusion in the 2004 true-up
proceeding. This reconciliation for the period of July 1998 through
December 2001 will be the final fuel reconciliation. 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. Recommendations from intervening
parties were received in April 2003 with hearings scheduled in May 2003.
Intervening parties have recommended disallowances totaling $170 million.

In March 2003, the ALJ hearing the TNC final fuel reconciliation,
discussed above, issued a PFD in the TNC proceeding. Various issues
addressed in TNC's proceeding may also be applicable to TCC's proceeding.
Consequently, TCC established a reserve for potential adverse rulings of
$27 million during the first quarter of 2003. A final order is expected
in late 2003. An adverse ruling from the PUCT in excess of the 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".

FERC Wholesale Fuel Complaints - Affecting AEP and TNC

As discussed in the 2002 Annual Report, 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 have
resulted in new contracts. Consequently, an offer of settlement will be
filed at FERC regarding the fuel complaint. Management is unable to
predict whether FERC will approve this offer of settlement which is not
expected to have a significant impact on TNC's financial condition. In
March 2002, TNC recorded a provision for refund of $2.2 million before
income taxes. The actual refund and final resolution of this matter could
differ materially from this estimate and may have a negative impact on
future results of operations, cash flow and financial condition.

Environmental Surcharge Filing - Affecting AEP and KPCo

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 Big
Sandy Plant. See NOx Reductions in Note 7.

In March 2003, the KPSC granted approximately $18 million of the request.
Rate relief of $1.7 million annually will be effective in May 2003. In
July 2003, additional annual rate relief of $16.2 million will become
effective. The recovery of such amounts is intended to offset KPCo's cost
of compliance with the Clean Air Act.

PSO Rate Review - Affecting AEP and PSO

In February 2003, the Director of the OCC filed an application requiring
PSO to file all documents necessary for a general rate review before
August 1, 2003. Management is unable to predict the ultimate effect of
this review on PSO's rates.

FERC Long-term Contracts - Affecting AEP and AEP East and
AEP West companies

In September 2002, the FERC voted to hold hearings to consider requests
from certain wholesale customers located in Nevada and Washington to
break long-term contracts which they allege are "high-priced". At issue
are long-term contracts entered during the California energy price spike
in 2000 and 2001. The complaints allege that AEP sold power at unjust and
unreasonable prices. The FERC delayed hearings to allow the parties to
hold settlement discussions. In January 2003, the FERC settlement judge
assigned to the case indicated that the parties' settlement efforts were
not progressing and he recommended that the complaint be placed back on
the schedule for a hearing. 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 a similar complaint, a FERC administrative law judge (ALJ) ruled in
favor of AEP and dismissed, in December 2002, a complaint filed by two
Nevada utilities. In 2000 and 2001, AEP agreed to sell power to the
utilities for future delivery. In late 2001, the utilities filed
complaints 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 consummated. 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. The ALJ's order is preliminary and is subject to review by the
FERC. At a hearing held in April 2003, the utilities asked FERC to void
the long-term contracts. The FERC will likely rule on the ALJ's order in
2003. Management is unable to predict the outcome of these proceedings or
their impact on future results of operations.

6. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING

As discussed in the 2002 Annual Report, 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 occurring in 2003
related to customer choice and industry restructuring.

Ohio Restructuring - Affecting AEP, CSPCo and OPCo

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 other
applicable law by failing to participate in an RTO.

The complaintants seek, among other relief, an order from the PUCO:
o suspending collection of transition charges by CSPCo and OPCo until
transfer of control of their transmission assets has occurred
o pricing 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
o 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 the FERC's reversal of its previous approval of our RTO filings
and 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 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 unable to predict the timing of the AEP's
East companies' participation in PJM, or the outcome of these
proceedings before the PUCO.

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. Management is unable to
predict the timing or the outcome of this proceeding.

Texas Restructuring - Affecting AEP, SWEPCo, TCC and TNC

As discussed in the 2002 Annual Report, on January 1, 2002, customer
choice of electricity supplier began in the ERCOT area of Texas.
Customer choice has been delayed in other areas of Texas including the
SPP area in which SWEPCo operates. In May 2003, the PUCT approved a
stipulation that delays competition in the SPP area until at least
January 1, 2007.

A 2004 true-up proceeding will determine the amount of stranded costs,
final fuel balance, net regulatory assets, certain environmental costs,
accumulated excess earnings, excess of price-to-beat revenues over
market prices subject to certain conditions and limitations (Retail
clawback), and the difference between the price of power obtained
through the legislatively-mandated capacity auctions and the power costs
used in the PUCT's ECOM model for 2002 and 2003 (Wholesale clawback) and
other restructuring issues.

The Texas Legislation allows for several alternative methods to be used
to value stranded costs in the final 2004 true-up proceeding including
the sale or exchange of generation assets, stock valuation or the use of
an ECOM model. Only TCC has stranded costs under the Texas Legislation.

In late 2002, TCC decided to obtain a market value of generating assets
for purposes of determining stranded costs for the 2004 true-up
proceeding and filed a plan of divestiture with the PUCT seeking
approval of a sales process for all of its generating facilities. Such
sales would quantify the actual stranded costs. The amount of stranded
costs under this market valuation methodology will be the amount by
which net 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. The filing included a request for the PUCT to issue a
declaratory order that TCC's 25.2% ownership interest in its nuclear
plant, STP, can be sold to value stranded costs. Intervenors to this
proceeding, including the PUCT Staff, made filings to dismiss TCC's
filing claiming that the PUCT does not have the authority to issue a
declaratory order. The intervenors also argued that the proper time to
address the sales process is after the plants are sold during the 2004
true-up proceeding. Since the bidding process is not expected to be
completed before mid-2004, TCC requested that the 2004 true-up
proceeding be scheduled after completion of the divestiture of the
generating assets.

In March 2003, the PUCT dismissed TCC's divestiture filing, determining
that it was more appropriate to address the nuclear asset stranded costs
valuation in a rulemaking proceeding. The PUCT approved a rule, in May
2003, that allows the value obtained by selling nuclear assets to be
used in determining stranded costs. Since the PUCT also dismissed the
request to certify the proposed divestiture plan, the divestiture plan
utilized by TCC will still be subject to a prudency review in the 2004
true-up proceedings. The PUCT also initiated a rulemaking regarding the
timing of the 2004 true-up proceedings scheduling TNC's filing in May
2004 and TCC's filing in September 2004.

Texas Legislation also requires that electric utilities and their
affiliated power generation companies (PGC) sell at auction in 2002 and
2003 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 and liquidity. Actual
market power prices received in the state mandated auctions will replace
the PUCT's earlier estimates of those market prices used in the ECOM
model to calculate the stranded cost for TCC for the 2004 true-up
proceeding.

The decision to determine stranded costs using market prices, instead of
using the PUCT's ECOM model estimates, enabled TCC to record a $262
million regulatory asset and related revenues which represents the
quantifiable amount of stranded costs for the year 2002 related to the
wholesale prices. In the first quarter of 2003, TCC recorded an
additional $56 million regulatory asset and related revenues for
stranded costs. Prior to the decision to pursue a sale of TCC's
generating assets, the PUCT's ECOM estimate prohibited the recognition
of the regulatory assets and revenues as there was no way to quantify
stranded costs. As discussed above, a defined process is required in
order to determine the amount of stranded costs related to generation
facility for the 2004 true-up proceedings. TCC's plan of divestiture
filed with the PUCT during 2002 provided such a process.

When the divestiture and the 2004 true-up proceeding are completed, TCC
can securitize stranded costs that are in excess of current securitized
amounts. The annual costs of securitization will be recovered through a
non-bypassable rate surcharge by the regulated transmission and
distribution (T&D) utility over the life of the securitization bonds.
Any stranded costs and other true-up amounts not recovered through the
sale of securitization bonds may be recovered through a separate
non-bypassable competitive transition charge to T&D utility customers.

In the event TCC and TNC are unable after the 2004 true-up proceeding to
recover all or a portion of their generation-related regulatory assets,
unrecovered fuel balances, stranded costs and other restructuring
related costs, it could have a material adverse effect on results of
operations, cash flows and possibly financial condition.

Arkansas Restructuring - Affecting AEP and SWEPCo

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 for the first quarter of 2003. As a result of
reapplying SFAS 71, derivative contract gains/losses for transactions
within AEP's traditional marketing area 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.

West Virginia Restructuring - Affecting AEP and APCo

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 deregulation becoming effective.

In 2000, the WVPSC issued an order approving an electricity
restructuring plan, which the WV Legislature approved by joint
resolution. The joint resolution provided that the WVPSC could not
implement the plan until the WV legislature made tax law changes
necessary to preserve the revenues of state and local governments.

In the 2001 and 2002 legislative sessions, the WV 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
WVPSC closed two proceedings related to electricity restructuring during
the summer of 2002.

475 In the 2003 legislative session, the WV Legislature failed to enact the
required tax legislation. Also, a March 2003 WV Legislative Bill
clarified the jurisdiction of the WVPSC over electric generation
facilities in WV. In March 2003, APCo's outside counsel advised us that
deregulation in West Virginia was no longer probable and confirmed facts
relating to the WVPSC'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 WV meet the
requirements to apply SFAS 71.

The result of reapplying SFAS 71 in WV had an insignificant effect on
results of operations for the first quarter of 2003. 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
market-to-market.

7. COMMITMENTS AND CONTINGENCIES

Power Generation Facility - Affecting AEP

AEP has entered into agreements with Katco Funding L.P. (Katco), an
unrelated unconsolidated special purpose entity. Katco has an aggregate
financing commitment of $525 million and 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 a syndicate of banks. Katco was formed
to develop, construct, finance and lease a power generation facility to
AEP. Katco will own the power generation facility and lease it to AEP
after construction is completed. The lease was originally intended to be
accounted for as an operating lease, therefore neither the facility nor
the related obligations would be reported on AEP's balance sheet (see
discussion of potential consolidation issues later in this note).
Payments under the operating lease are expected to commence in the first
quarter of 2004. AEP will in turn sublease the facility to Dow Chemical
Company (DOW). The use of Katco allows AEP to limit its risk associated
with the power generation facility once the construction phase has been
completed.

AEP is the construction agent for Katco. Construction is currently
scheduled to be completed by the first quarter of 2004, subject to
unforeseen events beyond AEP's control.

In the event the project is terminated before completion of
construction, AEP has the option to either purchase the facility for
100% of project costs or terminate the project and make a payment to
Katco for 89.9% of project costs.

DOW will use a portion of the energy produced by the facility and sell
the excess energy. AEP has agreed to purchase approximately 800 MW of
such excess energy from DOW. AEP will resell that energy to Tractebel
Energy Marketing, Inc. (TEM) for a period of 20 years. Beginning May 1,
2003, AEP has certain contractual rights and obligations in connection
with providing replacement energy and other products to TEM. If the
project is not completed by April 30, 2004, TEM may claim that it can
terminate the purchase agreement and is owed liquidating damages of
approximately $17.5 million.

The operating lease between Katco and AEP commences on the commercial
operation date of the facility and continues until November 2006. The
lease contains extension options subject to the approval of Katco, and
if all extension options were exercised, the total term of the lease
would be 30 years. AEP's lease payments to Katco are sufficient for
Katco to make required debt payments and provide a return to the
investors of Katco. At the end of each lease term, AEP may renew the
lease at fair market value subject to Katco's approval, purchase the
facility at its original construction cost, or sell the facility, on
behalf of Katco, to an independent third party. If the facility is sold
and the proceeds from the sale are insufficient to repay Katco, AEP may
be required to make a payment to Katco for the difference between the
proceeds from the sale and the obligations of Katco, up to 82% of the
project's cost. AEP has guaranteed a portion of the obligations of its
subsidiaries to Katco during the construction and post-construction
periods.

As of March 31, 2003, project costs subject to these agreements totaled
$403 million, and total costs for the completed facility are expected to
be approximately $510 million. For the 30-year extended lease term, the
lease rental is a variable rate obligation indexed to three-month LIBOR.
Consequently as market interest rates increase, the payments under this
operating lease will also increase. Annual payments of approximately $12
million represent future minimum payments during the initial term
calculated using the indexed LIBOR rate (1.38% at December 31, 2002).
The Power Generation Facility collateralizes the debt obligation of
Katco. AEP's maximum exposure to loss as a result of its involvement
with Katco is 100% during the construction phase and up to 82% once the
construction is completed. Maximum loss is deemed to be remote due to
the collateralization.

It is reasonably possible that under this operating lease structure AEP
will consolidate Katco in the third quarter of 2003, as a result of the
issuance of FASB Interpretation No. 46 "Consolidation of Variable
Interest Entities" (FIN 46). Upon consolidation, AEP would record the
assets, liabilities, depreciation expense, minority interest and debt
interest expense. AEP would eliminate operating lease expense. The
sublease to DOW would not be affected by this consolidation.

AEP is currently in the process of reviewing restructuring options for
this operating lease, which could replace Katco with a new lease
facility. Under these new leasing options, in accordance with FIN 46,
AEP would not consolidate the assets or debt of the Power Generation
Facility.

Nuclear Plant Outages - Affecting AEP, I&M and TCC

In April 2003, engineers at STP found a small quantity of powdery
residue during inspections conducted regularly as part of refueling
outages. STP officials are working closely with the NRC to safely return
the unit to service. The NRC will review any corrective action prior to
its implementation and restart of the unit.

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.

Management is unable to predict the length of time that the STP and Cook
Plant units may be unavailable or the costs of corrective actions at
this time. Cook Unit 2 was already planned for a refueling outage
starting May 5. We have commitments to provide power to customers during
the outages. Therefore, we will be subject to fluctuations in the market
prices of electricity and purchased replacement energy could be a
significant cost.

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

As discussed in Note 9 of the Combined Notes to Financial Statements in
the 2002 Annual Report, AEPSC, APCo, CSPCo, I&M, and OPCo have been
involved in litigation regarding generating plant emissions under the
Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo,
I&M, OPCo and eleven unaffiliated utilities modified certain units at
coal-fired generating plants in violation of the Clean Air Act. Federal
EPA filed complaints against AEP subsidiaries in U.S. District Court for
the Southern District of Ohio. A separate lawsuit initiated by certain
special interest groups was consolidated with the Federal EPA case. The
alleged modification of the generating units occurred 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.

Management believes its maintenance, repair and replacement activities
were in conformity with the Clean Air Act and intends to vigorously
pursue its defense.

Management is unable to estimate the loss or range of loss related to
the contingent liability for civil penalties under the Clear Air Act
proceedings and 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. In the event the AEP
System companies 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.

In December 2000, Cinergy Corp., an unaffiliated utility, which operates
certain plants jointly owned by CSPCo, reached a tentative agreement
with 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.

NOx Reductions - Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo,
SWEPCo and TCC

Federal EPA issued a NOx Rule requiring substantial reductions in NOx
emissions in a number of eastern states, including certain states in
which the AEP System's generating plants are located. The NOx Rule has
been upheld on appeal. The compliance date for the NOx Rule is May 31,
2004.

In 2000, Federal EPA also adopted a revised rule (the Section 126 Rule)
granting petitions filed by certain northeastern states under the Clean
Air Act. The rule imposes emissions reduction requirements comparable to
the NOx Rule beginning May 1, 2003, for most of AEP's coal-fired
generating units. Affected utilities, including certain AEP operating
companies, petitioned the D.C. Circuit Court to review the Section 126
Rule.

After review, the D.C. Circuit Court instructed Federal EPA to justify
the methods it used to allocate allowances and project growth for both
the NOx Rule and the Section 126 Rule. AEP subsidiaries and other
utilities requested that the D.C. Circuit Court vacate the Section 126
Rule or suspend its May 2003 compliance date. In 2001, the D.C. Circuit
Court issued an order tolling the compliance schedule until Federal EPA
responds to the Court's remand. On April 30, 2002, Federal EPA announced
that May 31, 2004 is the compliance date for the Section 126 Rule.
Federal EPA published a notice in the Federal Register on May 1, 2002
advising that no changes in the growth factors used to set the NOx
budgets were warranted. In June 2002, AEP subsidiaries joined other
utilities and industrial organizations in seeking a review of Federal
EPA's actions in the D.C. Circuit Court. This action is pending.

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 date is May 2003 for TCC and
May 2005 for SWEPCo.

AEP is installing a variety of emission control technologies to reduce
NOx emissions to comply with the applicable state and Federal NOx
requirements. This includes selective catalytic reduction (SCR)
technology on certain units and non-SCR technologies on a larger number
of units. During 2001 SCR technology commenced operations on OPCo's
Gavin Plant. Installation of SCR technology on Amos and Mountaineer
plants was completed and commenced operation in May 2002. Construction
of SCR technology at certain other AEP generating units continues.
Non-SCR technologies have been installed and commenced operation on a
number of units across the AEP System and additional units will be
equipped with these technologies.

The AEP NOx compliance plan is a dynamic plan that is continually
reviewed and revised as new information becomes available on the
performance of installed technologies and the cost of planned
technologies. Certain compliance steps may or may not be necessary as a
result of this new information. Consequently, the plan has a range of
possible outcomes. Our current estimates indicate that AEP's compliance
with the NOx Rule, the Texas Commission on Environmental Quality rule
and the Section 126 Rule could result in required capital expenditures
in the range of $1.3 billion to $1.7 billion, of which $918 million has
been spent through March 31, 2003. Estimated compliance cost ranges and
amounts spent by registrant subsidiaries are as follows:

Estimated Amount
Compliance Costs Spent
(in millions)
AEGCo $ 24 $ 5
APCo 463 250
CSPCo 87 54
I&M 34 8
KPCo 176 164
OPCo 495-824 404
SWEPCo 37 23
TCC 5 5

Since compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the estimates
depending upon the compliance alternatives selected to achieve
reductions in NOx emissions. Unless any capital and operating costs for
additional pollution control equipment are recovered from customers,
they will have an adverse effect on future results of operations, cash
flows and possibly financial condition.

Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo

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 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 preliminary 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 are unable to
predict whether these discussions will lead to an agreement on these
subjects. If these discussions do not lead to an agreement, there may be
a dispute with Enron concerning our ability to continue utilization of
the Bammel storage facility and certain appurtenant pipelines under the
existing agreements.

We also entered into an agreement with BAM Lease Company which grants
HPL the right to use approximately 65 billion cubic feet of cushion gas
(or pad gas) required for the normal operation of the Bammel gas storage
facility. The Bammel Gas Trust, which purportedly owned approximately 55
billion cubic feet of the gas, had entered into a financing arrangement
in 1997 with Enron and a group of banks. These banks purported to have
certain rights to the gas in certain events of default. In connection
with AEP's acquisition of HPL, the banks entered into an agreement
granting HPL's exclusive use of the cushion gas and released HPL from
liabilities and obligations under the financing arrangement. HPL was
thereafter informed by the banks of a purported default by Enron under
the terms of the referenced financing arrangement. In July 2002, the
banks filed a lawsuit against HPL seeking a declaratory judgment that
they have a valid and enforceable security interest in this cushion gas
which would permit them to cause the withdrawal of this gas from the
storage facility. In September 2002, HPL filed a general denial and
certain counterclaims against the banks. HPL also filed a motion to
dismiss. Management is unable to predict the outcome of this lawsuit or
its impact on AEP's financial position, results of operations and cash
flows.

During 2002 and 2001, AEP 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.

Enron has recently instituted proceedings against other energy trading
counterparties challenging the practice of utilizing offsetting
receivables and payables and related collateral across various Enron
entities. We believe that we have the right to utilize similar
procedures in dealing with payables, receivables and collateral with
Enron entities by offsetting trading payables owed to various Enron
entities against trading receivables due to several AEP subsidiaries. An
additional expense of up to $110 million may be incurred without such
offsets. We believe we have legal defenses to any challenge that may be
made to the utilization of such offsets but at this time are unable to
predict the ultimate resolution of this issue.

Shareholder Lawsuits - Affecting AEP

In the fourth quarter of 2002 and the first quarter of 2003, lawsuits
alleging securities law violations and seeking class action
certification were 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 AEP failed to disclose that alleged
"round trip" trades resulted in an overstatement of revenues, that AEP
failed to disclose that AEP traders falsely reported energy prices to
trade publications that published gas price indices and that AEP failed
to disclose that it 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. 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 AEP executives,
members of the AEP Board of Directors and AEP's independent auditor. AEP
intends to vigorously defend against these actions. Also in the fourth
quarter of 2002, two 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 AEP's gas trading operations; and, in
the fourth quarter of 2002 and the first quarter of 2003, three lawsuits
were filed against AEP, certain AEP 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. The
derivative actions and the ERISA actions are in the initial pleading
stage. AEP intends to vigorously defend against these actions.

California Lawsuit -Affecting AEP

In November 2002, Cruz Bustamante, 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 market price of natural gas and electricity. This
case is in the initial pleading stage. AEP has filed a motion to
dismiss. AEP intends to vigorously defend against this action.

Bank of Montreal Claim - Affecting AEP

In March 2003, Bank of Montreal (BOM) terminated all natural gas
trading deals and has claimed approximately $25 million is owed to BOM
by AEP which BOM subsequently has changed to approximately $34 million.
In April 2003, AEP filed a lawsuit against BOM claiming BOM had acted
contrary to industry practice in calculating termination and
liquidation amounts and that BOM had acknowledged in March 2003 that it
owed AEP approximately $68 million. Alternatively, AEP is claiming that
BOM owes approximately $45 million to AEP. 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 Williams Claim - Affecting AEP

In October 2002, AEP filed its 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 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 AEP owes approximately $130 million in connection
with the termination and liquidation of all trading deals. AEP believes
it has valid claims arising from Williams' actions and is seeking, in
part, a determination that either no amount is due or that a lesser
amount is due from AEP to Williams (which lesser amount is fully
reserved by AEP) and the extent of any other damages and legal or
equitable relief available. 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 PG&E Energy Trading, LLC Claim - Affecting AEP

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. 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 conditions.

Energy Market Investigation - Affecting AEP

As discussed in the 2002 Annual Report, 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, the U.S. Department of Justice and the California
attorney general during 2002. AEP's management responded to the
inquiries and provided the requested information.

In March 2003, AEP received a subpoena from the SEC as part of the SEC's
ongoing investigation of energy trading activities. In August 2002, AEP
had received an informal data request from the SEC seeking that AEP
voluntarily provide information. The subpoena seeks additional
information and is part of the SEC's formal investigation. AEP will
continue to cooperate with the SEC.

Other

AEP and its subsidiary registrants continue to be involved in certain
other matters discussed in the 2002 Annual Report.

8. GUARANTEES

In November 2002, the FASB issued FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others" (FIN 45) which
clarifies the accounting to recognize a liability related to issuing a
guarantee, as well as additional disclosures of guarantees. This new
guidance is an interpretation of SFAS 5, 57, and 107 and a rescission of
FIN 34. The initial recognition and initial measurement provisions of
FIN 45 is effective on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure requirements of FIN 45
were effective for financial statements of interim or annual periods
ending after December 15, 2002.

There are no liabilities recorded for all of the guarantees described
below in accordance with FIN 45 as these guarantees were entered into
prior to December 31, 2002 or have immaterial values which were not
recorded. There is no collateral held in relation to these guarantees
and there is no recourse to third parties in the event these guarantees
are drawn.

Certain AEP subsidiaries have entered into standby letters of credit
(LOC) with third parties. These LOCs cover gas and electricity trading
contracts, construction contracts, insurance programs, security
deposits, debt service reserves, drilling funds and credit enhancements
for issued bonds. All of these LOCs were issued at a subsidiary level of
AEP in the subsidiaries' ordinary course of business. TCC issued one of
the LOCs for credit enhancement of issued bonds. At March 31, 2003, the
maximum future payments of all the LOCs are approximately $158 million
with maturities ranging from April 2003 to January 2011. TCC's LOC was
for approximately $40.9 million with a maturity date of November 2003.
I&M's LOC was approximately $2 million with a maturity date of March
2003. Since AEP is the parent to all these subsidiaries, it holds all
assets of the subsidiaries as collateral. There is no recourse to third
parties in the event these letters of credit are drawn.

The following AEP subsidiaries have entered into guarantees of third
parties obligations:

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 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
$3.7 million, which expires June 2020.

Additionally, CSW guaranteed 50% of the required debt service reserve
for Polk Power Partners, another IPP of which CSW Energy owns 50%. In
the event that Polk Power does not make the required debt payments, CSW
has a maximum future payment exposure of approximately $4.7 million,
which expires July 2010.

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 revolving credit agreement, capital lease
obligations, and term loan payments of the mining contractor. In the
event the mining contractor defaults under any of these agreements,
SWEPCo's total future maximum payment exposure is approximately $73
million with maturity dates ranging from April 2003 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 March 31,
2003, the cost to reclaim the mine is estimated to be approximately $36
million. This guarantee ends upon depletion of reserves estimated at
2035 plus 6 years to complete reclamation.

See Note 13 "Minority Interest in Finance Subsidiary" for disclosure for
the guaranteed support of AEP for Caddis Partners, LLC.

AEP and its subsidiaries enter 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,
AEP's exposure generally does not exceed the sale price. AEP cannot
estimate the maximum potential exposure for any of these
indemnifications entered prior to December 31, 2002 due to the
uncertainty of future events. In the first quarter of 2003, AEP entered
into several sale agreements as discussed in Note 10. These sale
agreements include indemnifications with a maximum exposure of
approximately $60 million. There are no liabilities recorded for any
indemnifications due to the insignificant fair value of the
indemnification or due to the fact that they were entered prior to
December 31, 2002.

AEP and its subsidiaries lease certain equipment under a master
operating lease. Under the lease agreement, the lessor is guaranteed to
receive up to 87% of the unamortized balance of the equipment at the end
of the lease term. If the fair market value of the leased equipment is
below the unamortized balance at the end of the lease term, 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 March 31, 2003, the maximum potential loss for
these lease agreements was approximately $25 million assuming the fair
market value of the equipment is zero at the end of the lease term. The
maximum potential loss by registrant is as follows:

Maximum Potential Loss
Subsidiary (in millions)

APCo $ 0.7
CSPCo 0.5
I&M 3.3
KPCo 0.7
OPCo 2.7
PSO 2.9
SWEPCo 3.1
TCC 5.8
TNC 2.2
Other AEP Subsidiaries 3.5

Total $25.4

9. SUSTAINED EARNINGS IMPROVEMENT INITIATIVE

In response to difficult conditions in AEP's 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. 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, AEP paid $9.5
million and $51.2 million to these terminated employees in the fourth
quarter of 2002 and the first quarter of 2003, respectively. The
termination benefits expense was classified as Maintenance and Other
Operation expense on AEP's Consolidated Statements of Operations and as
Other Operation expense on the other registrants' statements of
operations. No additional termination benefits expense related to the
SEI initiative was recorded during the first quarter of 2003.

The following table shows the beginning and ending termination benefits
accrual amounts and the total termination related payments made during
the first quarter 2003.

Total Termination Total Termination
Payments Made During Benefits
Total Termination the Accrued at 3/31/03
Benefits Three Months (in millions)
Subsidiary Accrued at 12/31/02 Ended 3/31/03
Company (in millions) (in millions)

AEGCo $ 0.3 $ 0.3 $ -
APCo 12.2 9.3 2.9
CSPCo 4.5 3.8 0.7
I&M 13.1 9.3 3.8
KPCo 2.5 1.8 0.7
OPCo 7.1 5.4 1.7
PSO 3.0 2.4 0.6
SWEPCo 3.1 2.8 0.3
TCC 5.5 5.5 -
TNC 1.6 1.6 -
Other Subsidiaries
13.0 9.0 4.0
Totals $65.9 $51.2 $14.7

10. DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

DISPOSITIONS

In the first quarter of 2003, AEP completed a number of asset
dispositions determined not to be part of its core Utility Operations:

Disposition of Assets of C3 Communications

On February 28, 2003, C3 Communications sold the majority of its assets
for a sales price of $7.25 million. C3 received $7 million in cash and a
one-year non-interest bearing note receivable of $250,000 from the
purchaser. AEP provided for an $82 million pre-tax asset impairment in
the fourth quarter 2002, and the effect of the sale on first quarter
2003 results of operations was not significant.

Disposition of Mutual Energy Companies

On December 23, 2002, AEP received PUCT regulatory approval on a sale of
two of its Texas retail energy providers (REP's). As part of the REP
sale, MESC received a prepayment of approximately $30 million from the
purchaser. The prepaid service revenue was deferred on the books of MESC
to be amortized over the two-year term of the back office service
agreement.

On February 28, 2003, AEP completed the sale of Mutual Energy Service
Company, LLC (MESC) for $30.4 million dollars and realized a pre-tax
gain of approximately $12.2 million dollars. In addition, the $27.2
million pre-tax gain which was previously deferred and was being
recognized over the two-year term of a back office service agreement was
recognized as part of the gain calculation in the first quarter of 2003
as no further service obligations existed for MESC.

Disposition of Water Heater Assets

AEP sold its water 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. AEP 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). AEP, APCo, CSPCo, I&M, KPCo, and OPCo 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 table below
for detail of charges by Company:

Asset Impairment Lease Prepayment Loss on Sale
Charge Recorded Penalty Recorded Recorded in First Quarter
Subsidiary in Fourth Quarter in Fourth Quarter 2003 (Pre-tax)
Company 2002 (Pre-tax) 2002 (Pre-tax)
(in millions)

APCo $0.050 $0.062 $0.056
CSPCo 0.615 0.758 0.740
I&M 0.643 0.792 0.787
KPCo 0.011 0.011 0.011
OPCo 1.757 2.163 2.165
Other Non- Registrant
Subsidiaries
0.126 0.156 0.161
Total $3.202 $3.942 $3.920

Disposition of AEP Gas Power Systems

In 2001, AEP 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 (Gas Power) sold
its assets. AEP recognized a goodwill impairment loss of $12.2 million
in the first quarter of 2002, and the effect of the asset sale on the
first quarter 2003 results of operations was not significant.

DISCONTINUED OPERATIONS

The results of operations of the entities shown below, affecting AEP,
have been classified as Discontinued Operations for all periods
presented. The assets and liabilities of Pushan Power Plant and Eastex
were aggregated on AEP's Consolidated Balance Sheets as Assets Held for
Sale and Liabilities Held for Sale (see table at the end of the Assets
Held For Sale section below for more detailed information):

Pushan Power
SEEBOARD CitiPower Plant Total
Eastex
(in millions)

2003 Revenue $ - $ - $15 $31 $ 46
2002 Revenue 383 97 15 12 507

2003 Earnings
(Loss) After Tax $ - $ - $ - $(9) $(9)
2002 Earnings
(Loss) After Tax 33 (11) 2 (2) 22

ASSETS HELD FOR SALE

As discussed in the 2002 Annual Report, during 2002, AEP (and its
registrant subsidiaries, as applicable) recorded an estimated loss on
disposal of assets held for sale.

Eastex
In 1998, CSW began construction of a natural gas-fired cogeneration
facility (Eastex) located near Longview, Texas and commercial operations
commenced in December 2001. In June 2002, AEP requested that the FERC
allow it 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, AEP solicited bids
for the sale of Eastex and several interested buyers were identified by
December 2002. We still anticipate that the sale of assets will be
completed by the end of 2003. The estimated pre-tax loss on sale of
$218.7 million, which was based on the estimated fair value of the
facility and indicative bids by interested buyers, was recorded in
Discontinued Operations in AEP's Consolidated Statements of Operations
during the fourth quarter 2002.

Results of operations of Eastex have been reclassified as Discontinued
Operations in accordance with SFAS 144. The assets and liabilities of
Eastex have been included on AEP's Consolidated Balance Sheets as held
for sale. See the tables at the end of this section for more detailed
information.

Pushan Power Plant
In the fourth quarter of 2002, AEP began active negotiations to sell its
interest in the Pushan Power Plant (Pushan) in Nanyang, China to one of
the minority interest partners. We currently anticipate negotiations to
be completed by the end of 2003 with an estimated pre-tax loss on
disposal of $20.0 million, based on an indicative price expression. This
estimated loss was recorded in Discontinued Operations in AEP's
Consolidated Statements of Operations during the fourth quarter of 2002.

Results of operations of Pushan have been reclassified as Discontinued
Operations in accordance with SFAS 144. The assets and liabilities of
Pushan have been classified on AEP's Consolidated Balance Sheets as held
for sale. See the tables at the end of this section for more detailed
information.

Telecommunications
AEP had developed businesses to provide telecommunication services to
businesses and to other telecommunication companies through broadband
fiber optic networks operated in conjunction with AEP's electric
transmission and distribution lines. The businesses included AEP
Communications, LLC (AEPC), C3 Communications, Inc. (C3), and a 50%
share of AFN Networks, LLC (AFN), a joint venture. Due to the difficult
economic conditions in these businesses and the overall
telecommunications industry, and other operating problems, the AEP Board
approved in December 2002 a plan to cease operations of these
businesses. AEP initiated steps to market the assets of the businesses
to potential interested buyers in the fourth quarter of 2002. As a
result, the assets of C3 were sold in February 2003. See "Disposition of
Assets of AEP Communications" earlier in this note for further
information.

The sale of all telecommunication assets is expected by the end of 2003
with an estimated pre-tax impairment loss of $76 million related to AEPC
and an estimated pre-tax loss in value of the investment in AFN of $13.8
million. The estimated losses are based on indicative bids by potential
buyers. The estimated losses were recorded in Investment Value and Other
Impairment Losses in AEP's Consolidated Statements of Operations during
the fourth quarter 2002.

Newgulf Facility
In 1995, CSW purchased an 85 MW gas-fired peaking electrical generation
facility located near Newgulf, Texas (Newgulf). In October 2002, AEP
began negotiations with a likely buyer of the facility. AEP still
expects a sale to be completed by the end of 2003 with an estimated
pre-tax loss on sale of $11.8 million based on an indicative bid by the
likely buyer. This loss was recorded as Asset Impairments on AEP's
Consolidated Statements of Operations during the fourth quarter 2002.
Newgulf's Property, Plant and Equipment, net of accumulated
depreciation, has been classified on AEP's Consolidated Balance Sheets
as held for sale. See the tables at the end of this section for more
detailed information.

Nordic Trading
In October 2002, AEP announced that its ongoing energy trading
operations would be centered around its generation assets. As a result,
AEP took steps to exit its coal, gas, and electricity trading activities
in Europe, except for those activities necessary to support the U.K.
Generation operations. The Nordic Trading business acquired earlier in
2002, was made available for sale to potential buyers. The estimated
pre-tax loss on disposal in 2002 of $5.3 million consisted of impairment
of goodwill of $4.0 million and impairment of assets of $1.3 million,
and was included in Asset Impairments on AEP's Consolidated Statements
of Operations during the fourth quarter of 2002. Management's
determination of a zero fair value at the end of 2002 was based on
discussions with a potential buyer. The assets and liabilities of Nordic
Trading have been classified on AEP's Consolidated Balance Sheets as
held for sale. 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 will not be significant.

Excess Equipment
In November 2002, as a result of a cancelled development project, AEP
obtained title to a surplus gas turbine generator. AEP has been
unsuccessful in finding potential buyers of the unit, including its own
internal generation operators, due to an over-supply of generation
equipment available for sale. Sale of the turbine is currently still
projected before the end of 2003 with an estimated 2002 pre-tax loss on
disposal of $23.9 million, based on market prices of similar equipment.
This estimated loss was recorded in Asset Impairments on AEP's
Consolidated Statements of Operations during the fourth quarter of 2002.
The Other Assets have been classified on AEP's Consolidated Balance
Sheets as held for sale. See the tables at the end of this section for
more detailed information.

Excess Real Estate
In the fourth quarter of 2002, AEP began to market an under-utilized
office building in Dallas, TX obtained through the merger with CSW. Sale
of the facility is still projected by the end of 2003 and an estimated
pre-tax loss on disposal of $15.7 million was recorded during the fourth
quarter of 2002 based on an estimated sales price. This estimated loss
was included in Asset Impairments on AEP's Consolidated Statements of
Operations. The property asset has been classified on AEP's Consolidated
Balance Sheets as held for sale. See the tables at the end of this
section for more detailed information.

The assets and liabilities of the entities held for sale at March 31,
2003 and December 31, 2002 are as follows:

Pushan Power
Plant Newgulf Nordic Excess Excess
Eastex Facility Trading Real Estate Equipment Total
At March 31, 2003 (in millions)
Assets:

Current Assets $20 $ 16 $ - $50 $ - $ - $ 86
Property, Plant and
Equipment,
Net - 149 6 - 18 - 173
Deferred Income
Taxes - - - 6 - - 6
Other Assets - - - 3 - 12 15
Total Assets
Held for Sale $20 $165 $ 6 $59 $18 $12 $280

Liabilities:
Current Liabilities
$ 6 $ 22 $ - $56 $ - $ - $ 84
Long-term Debt - 22 - - - - 22
Other Liabilities 4 49 - 2 - - 55
Total
Liabilities
Held For Sale $10 $ 93 $ - $58 $ - $ - $161

Pushan Excess Water Tele-
Power Newgulf Nordic Real Excess Heater communica-
Eastex Plant Facility Trading Estate Equipment Program tions Total
At December 31, 2002 (in millions)
Assets:

Current Assets $15 $ 19 $ - $35 $ - $ - $ 1 $ - $ 70
Property, Plant and
Equipment, Net
- 132 6 - 18 - 38 6 200
Other Assets - - - 10 - 12 - - 22
Total Assets
Held for Sale $15 $151 $ 6 $45 $18 $12 $39 $ 6 $292

Liabilities:
Current Liabilities
$ 8 $ 28 $ - $48 $ - $ - $ - $ - $ 84
Long-term Debt - 25 - - - - - - 25
Other Liabilities 4 26 - 3 - - - - 33
Total
Liabilities
Held For Sale $12 $ 79 $ - $51 $ - $ - $ - $ - $142

11. BUSINESS SEGMENTS

In October 2002, AEP announced that it was exiting wholesale markets where it
does not own assets and announced certain reassignment changes in members of the
Office of the Chairman group. A further decision was later made in 2003 by the
Board of Directors and management to focus on AEP's core electric utility
businesses. Assets outside of domestic generation, distribution and transmission
of electricity are considered to be non-core and are being evaluated and may be
sold when market conditions are more favorable. In the fourth quarter of 2002,
as more fully described in Note 13 of the 2002 Annual Report, management
recognized pre-tax impairments totaling $1.4 billion, principally related to
non-regulated assets and investments and characterized $247 million of assets
and investments as Held for Sale.

During 2001 and most of 2002, AEP was in the process of restructuring into two
main businesses, i.e. the regulated business and the non-regulated business. The
extent to which these were to be further divided into business segments was
dependent on how the businesses were to be managed and how the chief operating
decision maker of each business would monitor the performance of such
businesses. However, until deregulation developed further, regulatory hurdles
were cleared and corporate separation was achieved, management was unable to
determine precisely what segments would exist for the various businesses after
corporate separation.

As a result of the changes in AEP's business strategy noted above, management's
desire to concentrate on its core businesses, delays in corporate separation and
the repeal of and/or delay of competition and deregulation in AEP's
jurisdictions, a decision was made to realign the segments for financial
reporting purposes in the first quarter of 2003 to reflect the manner in which
AEP's chief operating decision makers (the Office of the Chairman group) now
manage the business. Assets have been identified as either being core or
non-core investments and are being managed as such and the results of operations
are reported to senior management in this format as well as to AEP's investors
in its earning releases and presentations to financial analysts.

Throughout 2002, AEP's segments for financial reporting purposes were Wholesale,
Energy Delivery and Other. The business activities were as follows:

Wholesale
- - Generation of electricity for sale to retail and wholesale customers - Gas
pipeline and storage facilities - Marketing and trading of electricity, gas,
coal and other commodities - Coal mining, bulk commodity barging operations and
other energy supply related businesses

Energy Delivery
- - Domestic electricity transmission
- - Domestic electricity distribution

Other
- - Energy services
- - Telecommunication services (reclassified as Held for
Sale as of December 31, 2002)

As a result of the Board of Director's and management's decision to concentrate
on its core asset base and exit wholesale operations where AEP does not own
assets, Wholesale will no longer be a reporting segment. AEP's core operations
are now managed as vertically integrated electricity generation and energy
delivery businesses. The operations are managed on an integrated basis because
of the substantial impact of bundled, primarily cost-based rates and regulatory
oversight on the business process, cost structure and operating results. Assets
not meeting the Board of Director's and management's core strategy are
classified into three Investments segments. AEP's current segments, for which
discrete financial information is available, engage in business activities for
which AEP earns revenues and incurs expenses. The operating results of these
segments are regularly reviewed by AEP's chief operating decision maker. The
segments and their related business activities are as follows:

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

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

Management has aggregated electricity transmission, distribution and generation
within Utility Operations because their economic characteristics are similar and
their revenue is substantially determined by regulated jurisdictions. AEP's
electricity transmission and distribution operations are entirely regulated by
FERC and state regulatory jurisdictions. Electric generation sales to retail
customers are determined by the respective state jurisdictions, even for
customers in Ohio, Texas and Virginia which are in transition to deregulation,
and whose transition rates are still determined by the respective state
jurisdictions.

With respect to Investments, management has aggregated data into three separate
reporting groupings, due to the significance of each business and the manner in
which they are operated. The Investments-Gas Operations segment includes two
intra-state gas pipeline and storage operations located in Louisiana and Texas
and also includes risk management activities around these assets. The
Investments-UK Operations segment includes the generation of electricity for
sale to wholesale customers in the UK. Investments-Other includes the coal
mining operations and commodity barging operations, all of which share similar
economic characteristics.

The tables below present the reformatted reportable segment information for the
three months ended March 31, 2003 and 2002 based on the changes in business
strategy in the first quarter of 2003. These amounts include certain estimates
and allocations where necessary.

Investments
Utility Gas UK Reconciling
Operations Operations Operations Other Adjustments Consolidated
March 31, 2003 (in millions)
Revenues from:

External Customers $ 2,773 $1,102 $ 50 $ 155 $- $ 4,080
Other Operating Segments
- 44 - 13 (57) -
Net Income (Loss) 528 (37) (55) 4 - 440
Total Assets 28,840 4,513 1,493 1,775 280 (a) 36,901

March 31, 2002
Revenues from:
External Customers $ 2,258 $433 $ 101 $ 200 $- $ 2,992
Other Operating Segments
- 44 - 33 (77) -
Net Income (Loss) 213 (48) 29 (363) - (169)
Total Assets 25,056 6,241 1,648 6,905 793 (a) 40,643

(a) Reconciling adjustments for Total Assets include Assets Held for
Sale and/or Assets of Discontinued Operations.

All of the registrant subsidiaries have one reportable segment. The one
reportable segment is a vertically integrated electricity generation,
transmission and distribution business except AEGCo, an electricity
generation business, which remains unchanged. All of the registrants'
other activities are insignificant. The registrant subsidiaries'
operations are managed on an integrated basis because of the substantial
impact of bundled cost-based rates and regulatory oversight on the
business processes, cost structures and operating results.

12. LEASES

OPCo has entered into an agreement with JMG Funding LLP (JMG), an
unrelated unconsolidated 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 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. The lease is accounted for as an operating lease.
Payments under the operating lease 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. 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. In case of a sale at less than the adjusted
acquisition cost, OPCo must pay the difference to JMG.

The use of JMG allows OPCo to enter into an operating lease while
keeping the tax benefits otherwise associated with a capital lease. As
of March 31, 2003, unless the structure of this arrangement is changed,
it is reasonably possible that OPCo will consolidate JMG in the third
quarter of 2003 as a result of the issuance of FIN 46. Upon
consolidation, OPCo would record the assets, liabilities, depreciation
expense, minority interest and debt interest expense of JMG. OPCo would
eliminate operating lease expense. OPCo's maximum exposure to loss as a
result of its involvement with JMG is approximately $460 million of
outstanding debt and equity of JMG as of March 31, 2003.

On March 31, 2003, OPCo made a prepayment of $90 million under this
operating lease structure. AEP recognizes lease expense on a
straight-line basis over the remaining lease term, in accordance with
SFAS 13 "Accounting for Leases". On March 31, 2003, due to the $90
million prepayment, the net lease liability became an asset of $67.8
million. The asset is comprised of $16.7 million included in Other
current assets and $51.1 million in Other Assets on AEP's Consolidated
Balance Sheets ($16.7 million in Prepayments and Other and $51.1 million
in Deferred Charges and Other Assets on OPCo's Balance Sheets) . The
asset will be amortized over the remaining lease term, which ends in the
first quarter of 2010.

13. MINORITY INTEREST IN FINANCE SUBSIDIARY

In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC
(SubOne) and Caddis Partners, LLC (Caddis). SubOne is a wholly owned
consolidated subsidiary of AEP that was capitalized with the assets of
Houston Pipe Line Company, Louisiana Interstate Gas Company (AEP
subsidiaries) and $321.4 million of AEP Energy Services Gas Holding
Company (AEP Gas Holding is an AEP subsidiary and parent of SubOne)
preferred stock, that is 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 and $750
million from Steelhead Investors LLC ("Steelhead" - non-controlling
preferred member interest). As managing member, SubOne consolidates
Caddis. Steelhead is an unconsolidated special purpose entity and has a
capital structure of $750 million of which 3% is equity from investors
with no relationship to AEP or any of its subsidiaries and 97% is debt
from a syndicate of banks. The use of Steelhead allows AEP to limit its
risk associated with Houston Pipe Line Company and Louisiana Intrastate
Gas Company.

Under the provisions of the Caddis formation agreements, Steelhead
receives a quarterly preferred return equal to an adjusted floating
reference rate (4.7426% and 4.4349% for the quarters ended March 31,
2003 and 2002, respectively). Caddis has the right to redeem Steelhead's
interest at any time.

The $750 million invested in Caddis by Steelhead was loaned to SubOne.
This intercompany loan to SubOne is due August 2006, and is supported by
the natural gas pipeline assets of SubOne, a cash reserve fund of SubOne
and SubOne's $321.4 million of preferred stock in AEP Gas Holding. The
preferred stock is convertible into AEP common stock upon the occurrence
of certain events including AEP's stock price closing below $18.75 for
ten consecutive trading days. AEP can elect not to have the transaction
supported by such preferred stock if SubOne were to reduce its loan with
Caddis by $225 million (see below). 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 March 31,
2003, AEP has complied with the covenants contained in the credit
agreement. In addition, a default under any other agreement or
instrument relating to AEP and certain subsidiaries' debt outstanding in
excess of $50 million is an event of default under the credit agreement.

The initial period of Steelhead's investment in Caddis is through August
2006. At the end of the initial period, Caddis will either reset
Steelhead's return rate, re-market Steelhead's interests to new
investors, redeem Steelhead's interests, in whole or in part including
accrued return, or liquidate Caddis in accordance with the provisions of
applicable agreements.

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, and requiring the conversion of the
AEP Gas Holding preferred stock into AEP common stock. If Steelhead
exercised its rights to force Caddis to liquidate under these
conditions, then AEP would evaluate whether to refinance at that time or
relinquish the assets that support the intercompany loan to Caddis.
Liquidation of Caddis could negatively impact AEP's 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 AEP. The results of operations, cash
flows and financial position of Caddis and SubOne are consolidated with
AEP for financial reporting purposes. Steelhead's investment in Caddis
and payments made to Steelhead from Caddis are currently reported on
AEP's Consolidated Statements of Operation and Consolidated Balance
Sheets as Minority Interest in Finance Subsidiary.

On May 9, 2003, SubOne borrowed $225 million from AEP and reduced the
outstanding balance of the loan from Caddis, which Caddis then used to
reduce the preferred interest held by Steelhead. This payment will allow
the convertible preferred stock of AEP Gas Holding and the stock price
trigger discussed above to be eliminated.

AEP's maximum exposure to loss as a result of its involvement with
Steelhead is a $2 million capital investment, $83 million under the
subscription agreement to Caddis for any losses incurred by Caddis and
the cash reserve fund balance of approximately $42 million (as of March
31, 2003) due Caddis for default under the intercompany loan agreement.
Of the remaining $525 million financing, the recourse to AEP for the
first quarter will increase in the second quarter 2003 by $165 million
to comply with the covenants.

As of March 31, 2003, AEP is continuing to review the application of FIN
46 as it relates to the Steelhead transaction.

14. FINANCING AND RELATED ACTIVITIES

Long-term debt and other securities issuances and retirements
during the first three months of 2003 were:

Type Principal Interest Due
Company of Debt Amount Rate Date
Issuances (in millions) (%)

AEP Senior Unsecured Notes $500 5.375 2010
CSPCo Senior Unsecured Notes 250 5.50 2013
CSPCo Senior Unsecured Notes 250 6.60 2033
OPCo Senior Unsecured Notes 250 5.50 2013
OPCo Senior Unsecured Notes 250 6.60 2033
TCC Senior Unsecured Notes 150 3.00 2005
TCC Senior Unsecured Notes 100 Variable 2005
TCC Senior Unsecured Notes 275 5.50 2013
TCC Senior Unsecured Notes 275 6.65 2033
TNC Senior Unsecured Notes 225 5.50 2013

Company
Retirements
AEP Bank Facility 1,300 Variable 2003
AEP Senior Unsecured Notes 49 6.125 2006
CSPCo First Mortgage Bonds 2 8.70 2022
CSPCo First Mortgage Bonds 15 8.55 2022
CSPCo First Mortgage Bonds 14 8.40 2022
CSPCo First Mortgage Bonds 13 8.40 2022
SWEPCo First Mortgage Bonds 55 6.625 2003
TCC First Mortgage Bonds 16 6.875 2003
TCC Securitization Bonds 32 3.54 2005

Non-Registrant:
AEP Subsidiaries Notes Payable 2 Variable 2007
AEP Subsidiaries Revolving Credit
Agreement 291 Variable 2003
AEP Subsidiaries Senior Unsecured Notes 17 6.50 2003

In addition to the transactions reported in the table above, the
following table lists intercompany retirements of debt due to AEP.

Type Principal Interest Due
Company of Debt Amount Rate Date
Retirements (in millions) (%)

CSPCo Notes Payable $160 6.501 2006
OPCo Notes Payable 240 6.501 2006

Other Matters

In April 2003, AEP announced that they will have an early redemption on
May 30, 2003 of the following:

o $125.5 million of CSPCo's First Mortgage Bonds
o $165 million of I&M's Junior Subordinated Debentures
o $90 million of I&M's First Mortgage Bonds

Consequently, the debt has been classified as Long-term Debt Due Within
One Year on their respective Balance Sheets due to the refinancing debt
having been issued prior to March 31, 2003.

Common Stock

In March 2003, AEP issued 56 million shares of common stock at $20.95
per share through an equity offering and received net proceeds of $1,141
million (net of issuance costs of $36 million). Proceeds from the sale
of common stock were used to pay down both short-term and long-term debt
with the balance being held in cash.

REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION, ACCOUNTING POLICIES AND OTHER MATTERS

This is our combined presentation of management's discussion and analysis of
financial condition, accounting policies and other matters for AEP and its
registrant subsidiaries. Management's discussion and analysis of results of
operations for AEP and each of its registrant subsidiaries for the quarter ended
March 31, 2003 is presented with their financial statements earlier in this
document.

FINANCIAL CONDITION

Credit Ratings
As discussed in the 2002 Annual Report, the rating agencies have been conducting
credit reviews of AEP and its registrant subsidiaries.

In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review were downgrades of
the following ratings for unsecured debt: AEP to Baa3 from Baa2, APCo from Baa1
to Baa2, PSO from A2 to Baa1, SWEPCo from A2 to Baa1 and TCC from Baa1 to Baa2.
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 downgraded from P-2 to P-3. The completion of this review was 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 its subsidiaries senior unsecured ratings
from BBB+ to BBB along with the first mortgage bonds of AEP subsidiaries. S&P
placed AEP on stable rating and closed their review.

In March 2003, Fitch Ratings Service downgraded the parent company (AEP) to BBB
from BBB+ with stable outlook.

Current ratings of AEP's subsidiaries' first mortgage bonds are listed in the
following table:

Company Moody's S&P Fitch

APCo Baa1 BBB A-
CSPCo A3 BBB A
I&M Baa1 BBB BBB+
KPCo Baa1 BBB BBB+
OPCo A3 BBB A-
PSO A3 BBB A
SWEPCO A3 BBB A
TCC Baa1 BBB A
TNC A3 BBB A

Current short-term ratings are as follows:

Company Moody's S&P Fitch

AEP P-3 A-2 F-2

The current ratings for senior unsecured debt are listed in the following table:

Company Moody's S&P Fitch

AEP Baa3 BBB BBB
AEP Resources* Baa3 BBB BBB+
APCo Baa2 BBB BBB+
CSPCo A3 BBB A-
I&M Baa2 BBB BBB
KPCo Baa2 BBB BBB
OPCo A3 BBB BBB+
PSO Baa1 BBB A-
SWEPCO Baa1 BBB A-
TCC Baa2 BBB A-
TNC Baa1 BBB A-

* The rating is for a series of senior notes issued with a Support Agreement
from AEP.

Liquidity

Liquidity, or access to cash, has become a more critical factor in determining
the financial stability of a company due to volatility in wholesale power
markets and the potential limitations that credit rating downgrades place on a
company's ability to raise capital. Management is committed to preserving an
adequate liquidity position and addressing AEP and its subsidiaries' financial
needs.

At March 31, 2003, we had an available liquidity position of $5.3 billion as
illustrated in the table below:

Credit Facilities
(in millions) Maturity
Commercial Paper Backup
Lines of Credit $2,500* 5/03
Commercial Paper Backup
Lines of Credit 1,000 5/05
Euro Revolving Credit
Facilities 315 10/03
Total 3,815

Cash Liquidity Reserves 300**
Additional Unrestricted
Cash including Cash
on Hand for
Operational Needs 1,464**
Total Credit Facilities
and Cash 5,579

Less: Commercial Paper
Outstanding 225
Euro Revolving
Credit Loans 16
Total Available Liquidity $5,338

* Contains one year term-out provision.
** These components comprise the Cash and Cash Equivalents balance on AEP's
Consolidated Balance Sheet at March 31, 2003.

The Ohio and Texas subsidiaries issued $2.025 billion of senior unsecured notes
in February 2003 with maturity dates ranging from 2005 to 2033. The commercial
paper balance outstanding decreased due to its repayment with proceeds from
these issuances.

At December 31, 2002, AEP also had a $1.725 billion bank facility maturing in
April 2003 that was available for debt refinancing with $1.3 billion
outstanding. With the issuance of the permanent financing for the Ohio and Texas
subsidiaries, mentioned above, this facility was repaid and cancelled in
February 2003.

AEP also maintains a minimum $300 million cash liquidity reserve fund to support
its marketing operations in the U.S. and keeps additional cash on hand as market
conditions change. At March 31, 2002, AEP had $1.8 billion of available cash.

In total, as shown in the table above, we had approximately $5.6 billion in
liquidity sources of which $5.3 billion were unused and available at March 31,
2003.

In April 2003, AEP's Board of Directors declared a common stock dividend of
$0.35 per share for the second quarter of 2003, which is a 42% decrease from the
previous quarter's dividend of $0.60 per share. This reduction will result in
annual cash savings of approximately $395 million (based on the outstanding
common shares at April 30, 2003).

Cash from operations and short-term borrowings provide working capital and meet
other short-term cash needs. We generally use short-term borrowings to fund
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. We
operate a money pool and sell accounts receivables to provide liquidity for the
domestic electric subsidiaries. Short-term borrowings are supported by a
bank-sponsored receivables purchase agreement and two revolving credit
agreements.

Cash flows from operating activities during the first quarter of 2003 were $775
million, including $335 million from depreciation, amortization, deferred income
taxes and deferred investment tax credits. This represents an increase of $795
million when compared to first quarter results of 2002, largely due to the
year-over-year increase in net income of $609 million ($440 million and $(169)
million in 2003 and 2002, respectively) and an increase in cash from working
capital items of $985 million ($376 million in 2003 and $(609) million in 2002).
The aforementioned increases were partially offset by a $(193) million
cumulative effect of accounting change in 2003 (see Note 3).

Cash flows used for investing activities during the first quarter of 2003 were
$289 million compared to $332 million during the first quarter of 2002. The
major reason for the year-over-year variance was proceeds of $35 million from
the sale of assets in 2003 (see Note 10). During the first quarter of 2003,
major construction expenditures continued for emission control technology at
several coal-fired generating plants (see Note 7).

Cash flows from financing activities in the first quarter of 2003 decreased by
$284 million when compared to the first quarter of 2002 ($65 million compared to
$349 million during 2003 and 2002, respectively), primarily as the result of
AEP's retirement and restructuring of its short-term and long-term debt during
2003. During the first quarter of 2003, AEP was able to retire $3,434 million of
debt ($2,925 million short-term and $509 million of long-term) and increase
available cash primarily through the issuance of long-term financing ($2,525
million), issuance of common stock ($1,177 million) and the generation of cash
from operating activities.

Total consolidated plant and property additions for the first quarter 2003 were
$324 million. The following table shows the plant and property additions by
certain registrant subsidiaries:

Company Amount
(in millions)
APCo $ 57
I&M 28
OPCo 56
SWEPCo 26
TCC 22

Financing Activity

Common Stock Offering
On February 27, 2003, AEP priced its offering of 50 million shares of common
stock at a public offering price of $20.95 per share. AEP granted the
underwriters an option to purchase an additional 7.5 million shares of common
stock to cover over allotments. The underwriters exercised their over allotment
option to purchase an additional 6 million shares. The net proceeds of
approximately $1.1 billion from the sale of these securities were used to reduce
debt and for other corporate purposes.

Debt
During March 2003, AEP completed an offering of 5.375% Series C Senior Notes
which have a principal amount of $500 million and a maturity date of March 15,
2010. The net proceeds of $494 million from the offering were used to repay or
redeem current maturities of long-term debt and for other corporate purposes.

In February 2003, CSPCo issued $250 million of unsecured senior notes due 2013
at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a
coupon of 6.60%. OPCo issued $250 million of unsecured senior notes due 2013 at
a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a
coupon of 6.60%. TCC issued $100 million of unsecured senior notes due 2005 at a
variable rate, $150 million of unsecured senior notes due 2005 at a coupon of
3.0%, $275 million of unsecured senior notes due 2013 at a coupon of 5.50% and
$275 million of unsecured senior notes due 2033 at a coupon of 6.65%. TNC issued
$225 million of unsecured senior notes due 2013 at a coupon of 5.50%. The
proceeds from the bond issuances were used to repay the bank facility due to
mature in April 2003, mentioned above, short-term debt and for other corporate
purposes.

During the first quarter of 2003, CSPCo retired $44 million of first mortgage
bonds due 2022 with rates ranging from 8.4% to 8.7%. SWEPCo and TCC retired $55
million and $16 million, respectively, of first mortgage bonds at maturity. TCC
also retired $32 million of securitization bonds due 2005.

In April 2003, SWEPCo issued $100 million of senior unsecured debt due 2015 at a
coupon of 5.375%.

In April 2003, certain AEP subsidiaries called the following First Mortgage
Bonds (FMB) or Junior Subordinated Debentures (JSD) for early redemption on May
30, 2003:

Coupon
Subsidiary Type of Or Stated Call Principal
Company Debt Rate Rate Due Date Amounts
% % (in millions)

APCo FMB 8.50 100 2022 $70
APCo FMB 7.15 100 2023 20
APCo FMB 7.80 103.90 2023 30
CSPCo FMB 6.55 100 2004 27
CSPCo FMB 6.75 100 2004 26
CSPCo FMB 7.75 104.27 2023 33
CSPCo FMB 7.90 103.95 2023 40
I&M FMB 8.50 100 2022 75
I&M FMB 7.35 100 2023 15
I&M JSD 8.00 100 2026 40
I&M JSD 7.60 100 2038 125
KPCo JSD 8.72 100 2025 40

In May 2003, a third party exercised its option to call $250 million of 5.50%
putable callable notes, issued by AEP in May 2001, for purchase and remarketing.
Management is evaluating alternatives and plans to exchange the notes.

During May 2003, APCo issued $200 million of unsecured senior notes due 2008 at
a coupon of 3.60% and $200 million of unsecured senior notes due 2033 at a
coupon of 5.95%. The proceeds of these bond issuance will be used to redeem the
aforementioned early redemptions for APCo, a floating rate note due in August
2003 and for other corporate purposes.

Possible Divestitures

We have a strong commitment to continually evaluate the need to reallocate
resources to areas that effectively match investments with our strategy, provide
greater potential for financial returns, and to dispose of investments that no
longer meet these principles.

Assets we are seeking to divest consist of domestic and international
unregulated generation, gas pipelines, a coal business and a communications
business.

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. If we choose to
dispose of these assets, we may realize non-recurring losses in the aggregate
that could have a material impact on our results of operations.

Corporate Separation
As discussed in the 2002 Annual Report, we have filed with the FERC and SEC
seeking approval to separate our regulated and unregulated operations. With the
changes in AEP's business strategy in response to current energy market and
business conditions, management continues to evaluate corporate separation
plans, including determining whether legal corporate separation is appropriate.

RTO Formation
As discussed in the 2002 Annual Report, 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 the
subsidiaries' transmission systems to RTOs.

In 2002, AEP announced an agreement with PJM to pursue terms for participation
in its RTO for AEP East companies with final agreements to be negotiated. AEP
subsidiaries, which 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 based on
statutory or regulatory requirements in those states. Those proceedings remain
pending.

In February 2003, the Virginia Legislature enacted legislation, which the
Governor of Virginia signed, that prohibited the transfer of transmission assets
in its jurisdiction to an RTO, until at least July 2004. In April 2003, FERC
approved AEP's transfer of functional control of the AEP East companies'
transmission system to PJM. FERC also accepted AEP's proposed rates for joining
PJM, but set a number of rate issues for resolution through settlement
proceedings or FERC hearings.

AEP West companies are members of ERCOT or the SPP. In 2002, FERC conditionally
accepted filings related to a proposed consolidation of MISO and the SPP. AEP's
SPP companies are also regulated by state public utility commissions, and 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. Regulatory activities concerning various
RTO issues are ongoing in Arkansas and Louisiana.

Management is unable to predict the outcome of these transmission regulatory
actions and proceedings or their impact on the timing and operation of RTOs, our
transmission operations or results of operations and cash flows.

ACCOUNTING POLICIES

Critical Accounting Policies - Revenue Recognition

Regulatory Accounting - The consolidated financial statements of AEP and the
financial statements of electric operating subsidiary companies with cost-based
rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, CSPCo, OPCo,
SWEPCo, TCC and TNC) 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. In accordance with SFAS 71, 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 are also recorded to provide for 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. We test for probability of recovery
whenever new events occur, for example, issuance of a regulatory commission
order or passage of new legislation. If we determine 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.

Electric Generation - We record operating revenues from electric generation
activities using accrual, hedge and mark-to-market methods of accounting.

We use accrual accounting for electricity sales to residential, industrial and
institutional customers who have not signed a contract or have entered into
long-term power sales contracts that are not subject to mark-to-market
accounting. Under accrual accounting we record revenues when energy has been
delivered. All of the registrant subsidiaries except AEGCo are allocated a
portion of the revenues and costs associated with AEP's electric generation
activities that have been recognized on an accrual basis.

Some contracts for the sale of electricity at fixed prices for future delivery
are used to mitigate the risk associated with anticipated sales of electricity
from our generation assets and have been designated and accounted for as cash
flow hedges under SFAS 133. Prior to settlement, we record changes in the fair
value of contracts designated as cash flow hedges in the Consolidated Statements
of Common Shareholders' Equity as Accumulated Other Comprehensive Income (AOCI).
When the anticipated sale of electricity occurs, the settlement amount of the
cash flow hedge is recorded in revenues. See Derivatives below.

Revenues recognized under the mark-to-market method of accounting include
realized revenue on electricity contracts, net of related costs of sales, and
unrealized gains and losses on electricity contracts accounted for as
derivatives under SFAS 133. We also recognize revenues under the mark-to-market
method of accounting for non-derivative energy trading contracts as required by
EITF Issue No. 98-10. Beginning October 25, 2002 for new contracts and January
1, 2003 for pre-existing contracts, in accordance with a new accounting
pronouncement that is discussed further in Note 2, we discontinued the
mark-to-market method of accounting for all unsettled electricity contracts that
are not considered derivatives under SFAS 133. See Derivatives below. All of the
registrant subsidiaries except AEGCo are allocated a portion of the revenues and
costs associated with AEP's electric generation activities; however, PSO,
SWEPCo, TCC and TNC are only allocated a portion of the forward transactions
that are accounted for using the mark-to-market method of accounting. We defer,
as regulatory liabilities (unrealized gains) or regulatory assets (unrealized
losses), changes in the fair value of derivative contracts for the forward sale
and purchase of electricity in AEP's traditional marketing area to the extent
that a jurisdiction is regulated. AEP's traditional marketing area is up to two
transmission systems from the AEP service territory. For contracts which are
outside of AEP's traditional marketing area, the change in fair value is
included in nonoperating income on a net basis.

Electric Transmission and Distribution - Revenues from electricity transmission
and distribution services include realized revenue for electricity and delivery
services provided to residential, industrial and institutional customers. These
revenues are recognized when delivery services are provided.

Gas Sales, Pipeline and Storage Activities - Revenue from gas sales activities
includes realized revenue on contracts for the sale of gas, and unrealized gains
and losses on gas contracts accounted for as derivatives under SFAS 133. See
Derivatives below. Revenues from gas pipeline and storage services are
recognized when gas is delivered to contractual meter points or when services
are provided. Transportation and storage revenues also include the accrual of
earned, but unbilled and/or not yet metered gas.

Substantially all of the forward gas purchase and sale contracts (excluding
wellhead purchases of natural gas), swaps and options for the pipeline
operations, qualify as derivative financial instruments as defined by SFAS 133.
Accordingly, net gains and losses resulting from revaluation of these contracts
to fair value during the period are recognized currently in results of
operations and are appropriately discounted, net of applicable credit and
liquidity adjustments.

Derivatives - We use derivative instruments such as futures, swaps, forwards and
options to manage the commodity, currency exchange and financial market risks of
our business operations. We also manage a portfolio of commodity contracts held
for trading purposes as part of our strategy to market excess generation
capacity. All derivative instruments not qualifying for the normal purchase
normal sale exemption under SFAS 133 are recorded in the Consolidated Balance
Sheets as Risk Management Assets and Liabilities. On the date a derivative
instrument is entered into, we designate the derivative as either a normal
purchase or sale contract; as held for trading purposes (trading contract);
and/or a hedge of a forecasted transaction or future cash flows (cash flow
hedge).

Derivative instruments that provide for the purchase or sale of energy
commodities that will settle physically in the normal course of business qualify
for the normal purchase and sale exemption under SFAS 133. If the exemption has
been elected, no amount associated with these contracts is included in the
Consolidated Financial Statements until the commodity is actually delivered.

Derivative instruments used to mitigate the risks of variability in expected
cash flows attributable to a forecasted transaction are designated and accounted
for as cash flow hedges under SFAS 133. Cash flow hedges are recorded at fair
value on the Consolidated Balance Sheets as either an asset or liability with
unrealized gains and losses recorded on the Consolidated Statements of Common
Shareholders' Equity as AOCI until the hedged item affects earnings. We formally
document the hedging relationship at the inception of the cash flow hedge and
assess whether the hedging relationship is highly effective in achieving
offsetting cash flows on an ongoing basis. We discontinue hedge accounting
prospectively when the cash flow hedge is determined to be ineffective in
achieving offsetting cash flows of the hedged item or it is not probable that
the hedged transaction will occur. Settled amounts and ineffective portions of
cash flow hedges are removed from AOCI and recorded in the Consolidated
Statements of Operations in the same accounts as the hedged item. When hedge
accounting is discontinued because the derivative no longer qualifies as an
effective hedge, the derivative instrument will continue to be recorded at fair
value on the Consolidated Balance Sheets as either an asset or liability with
subsequent changes in fair value recognized in the Consolidated Statements of
Operations.

Derivative instruments entered into for trading purposes are recorded at fair
value on the Consolidated Balance Sheets as either an asset or liability with
all realized and unrealized gains and losses presented on a net basis in the
Consolidated Statements of Operations.

Energy options, futures and swaps represent financial transactions with
unrealized gains and losses from changes in fair values reported net in
revenues. APCo, CSPCo, I&M, KPCo and OPCo also have financial transactions, but
record the unrealized gains and losses, as well as the net proceeds upon
settlement, in Nonoperating Income.

The fair values of derivative contracts are based on exchange prices and broker
quotes. We mark-to-market long-term derivative contracts based primarily on
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 contracts. We have
independent controls to evaluate the reasonableness of our valuation models.
However, energy markets, especially electricity markets, are imperfect and
volatile. Volatility in energy commodities markets affects the fair values of
all of our open trading and derivative contracts exposing us to market risk and
causing our results of operations to be subject to volatility. Unforeseen events
can and will cause reasonable price curves to differ from actual prices
throughout a contract's term and at the time contracts settle. Therefore, there
could be significant adverse or favorable effects on future results of
operations and cash flows if our current estimates of future market prices are
not representative of actual future market prices. Differences between actual
market prices in the future and our estimated future prices are more likely to
occur for long-term contracts.

See the "Quantitative and Qualitative Disclosures About Risk Management
Activities" section of this report for a discussion of the policies and
procedures used to manage our exposure to market and other risks from trading
activities.

New Accounting Pronouncements

See Note 2 for a discussion of significant accounting policies and new
accounting pronouncements.

OTHER MATTERS

Industry Restructuring
As discussed in the 2002 Annual Report, restructuring and customer choice were
effective in four of the eleven state retail jurisdictions in which the AEP
electric utility companies operate. Restructuring legislation provides for a
transition from cost-based rate regulation of bundled electric service to
customer choice and market pricing for the supply of electricity. The status of
our transition plans, regulatory issues and proceedings and accounting issues in
the state regulatory jurisdictions impacted by restructuring and customer choice
is presented in Note 6.

Nuclear Plant Outages - Affecting AEP, I&M and TCC

In April 2003, engineers at STP found a small quantity of powdery residue during
inspections conducted regularly as part of refueling outages. STP officials are
working closely with the NRC to safely return the unit to service. The NRC will
review any corrective action prior to its implementation and restart of the
unit.

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.

Management is unable to predict the length of time that the STP and Cook Plant
units may be unavailable or the costs of corrective actions at this time. Cook
Unit 2 was already planned for a refueling outage starting May 5. We have
commitments to provide power to customers during the outages. Therefore, we will
be subject to fluctuations in the market prices of electricity and purchased
replacement energy could be a significant cost.

Litigation
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M,
and OPCo

As discussed in the 2002 Annual Report, AEPSC, APCo, CSPCo, I&M, and OPCo have
been involved in litigation since 1999 regarding generating plant emissions
under the Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo,
I&M, OPCo and eleven unaffiliated utilities made modifications to generating
units at coal-fired generating plants in violation of the Clean Air Act. Federal
EPA filed complaints against AEP subsidiaries in U.S. District Court for the
Southern District of Ohio. A separate lawsuit initiated by certain special
interest groups was consolidated with the Federal EPA case. The alleged
modification of the generating units occurred over a 20 year period.

Management is unable to estimate the loss or range of loss related to the
contingent liability for civil penalties under the Clear Air Act proceedings and
is 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. In the event the AEP System companies 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. See Note
7 for further discussion.

NOx Reductions - Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, SWEPCo and
TCC

Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule)
under the Clean Air Act requiring substantial reductions in NOx emissions in a
number of eastern states, including certain states in which the AEP System's
generating plants are located. The compliance date for the rules is May 31,
2004.

The Texas Commission on Environmental Quality adopted rules requiring
significant reductions in NOx emissions from utility sources, including SWEPCo
and TCC. The compliance date is May 2003 for TCC and May 2005 for SWEPCo.

AEP is installing selective catalytic reduction (SCR) technology and non-SCR
technology to reduce NOx emissions on certain units to comply with these rules.

Our estimates indicate that compliance with the rules could result in required
capital expenditures in a range of approximately $1.3 billion to $1.7 billion
for the AEP System. The actual cost to comply could be significantly different
than the estimates depending upon the compliance alternatives selected to
achieve reductions in NOx emissions. Unless any capital or operating costs for
additional pollution control equipment are recovered from customers, they will
have an adverse effect on future results of operations, cash flows and possibly
financial condition. See Note 7 for further discussion.

Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo

In 2002, certain subsidiaries of AEP filed claims in the bankruptcy proceeding
of the Enron Corporation and its subsidiaries which is pending in the U.S.
Bankruptcy Court for the Southern District of New York. At the date of Enron's
bankruptcy, AEP and its subsidiaries had open trading contracts and trading
accounts receivables and payables with Enron and various HPL related
contingencies and indemnities including issues related to the underground Bammel
gas storage facility and the cushion gas (or pad gas) required for its normal
operation.

Management believes that AEP entities have the right to utilize offsetting
receivables and payables and related collateral across various Enron entities by
offsetting trading payables owed to various Enron entities against trading
receivables due to us. Management believes we have legal defenses to any
challenge that may be made to the utilization of such offsets. An additional
expense of up to $110 million may be incurred without such offsets. At this time
management is unable to predict the ultimate resolution of these issues or their
impact on results of operations and cash flows. See Note 7 for further
discussion.

Bank of Montreal Claim - Affecting AEP

In March 2003, Bank of Montreal (BOM) terminated all natural gas trading
deals and has claimed approximately $25 million is owed to BOM by AEP which
BOM subsequently has changed to approximately $34 million.In April 2003, AEP
filed a lawsuit against BOM claiming BOM had acted contrary to industry
practice in calculating termination and liquidation amounts and that
BOM had acknowledged in March 2003 that it owed AEP approximately $68 million.
Alternatively, AEP is claiming that BOM owes approximately $45 million to AEP.
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 Williams Claim - Affecting AEP

In 2002, AEP filed its 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.
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. See Note 7 for further discussion.

Arbitration of PG&E Energy Trading, LLC Claim - Affecting AEP

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.
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 conditions.

Energy Market Investigations - Affecting AEP

As discussed in the 2002 Annual Report, the FERC, the California attorney
general, the PUCT, the SEC, the Department of Justice and the U.S. Commodity
Futures Trading Commission (CFTC) initiated investigations into whether any
entity, including Enron Corporation, manipulated short-term prices in electric
energy or natural gas markets, exercised undue influence over wholesale prices
or participated in fraudulent trading practices.

In March 2003, the SEC subpoenaed information from its August 2002 request for
us to voluntarily provide certain trading information. AEP and its subsidiaries
have and will continue to provide information to the FERC, the SEC, state
officials and the CFTC as required. See Note 7 for further discussion.

Shareholders' Litigation - Affecting AEP

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 AEP, certain
AEP executives, members of the AEP Board of Directors and certain investment
banking firms. These cases are in the initial pleading stage. AEP intends to
vigorously defend against these actions. See Note 7 for further discussion.

California Lawsuit - Affecting AEP

In 2002, the Lieutenant Governor of California 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 intends to
vigorously defend against this action. See Note 7 for further discussion.

COLI Litigation

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 6th
Circuit. In April 2003, the Appeals Court ruled against AEP. Management is
reviewing this opinion and will evaluate AEP's options.

Other Litigation

AEP and its subsidiaries continue to be involved in certain other legal matters
discussed in the 2002 Annual Report.

Snohomish Settlement - Affecting AEP

In February 2003, AEP and the Public Utility District No. 1 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 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.

Other Management Matters - Affecting AEP

On April 9, 2003, Dr. E. Linn Draper Jr., AEP's chairman,
president and chief executive officer, announced that he plans to retire in
2004. AEP's board of directors will soon begin the process of identifying
Dr. Draper's successor.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

Market Risks

As a major power producer and marketer of wholesale electricity and natural gas,
AEP has 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 AEP due to changes
in the underlying market prices or rates.

Policies and procedures have been established to identify, assess, and manage
market risk exposures in AEP's day to day operations. AEP's risk policies have
been reviewed with the Board of Directors, approved by a Risk Executive
Committee and administered by a Chief Risk Officer. The Risk Executive Committee
establishes risk limits, approves risk policies, assigns responsibilities
regarding the oversight and management of risk and monitors risk levels. This
committee receives daily, weekly, and monthly reports regarding compliance with
policies, limits and procedures. The committee meets monthly and consists of the
Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior
financial and operating managers.

AEP has actively participated in the Committee of Chief Risk Officers (CCRO) to
develop standard disclosures for risk management activities around energy
trading contracts. The CCRO is composed of the chief risk officers of major
electricity and gas companies in the United States. Recently the CCRO adopted
disclosure standards for energy contracts to improve clarity, understanding and
consistency of information reported. Implementation of the new disclosures is
voluntary. AEP supports the work of the CCRO and has embraced the new
disclosures. The following tables provide information on AEP's risk management
activities.

Roll-Forward of MTM Risk Management Contract Net Assets

This table provides detail on changes in AEP's MTM net asset or
liability balance sheet position from one period to the next.

TABLE 1 Part I
Roll-Forward of MTM Risk Management Contract Net
Assets
Three Months Ended March 31, 2003

Domestic Domestic AEP
AEP Consolidated Power Gas International Consolidated
(in millions)

Beginning Balance December 31, 2002 $360 (155) 45 250
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (89) (23) (22) (134)
Fair Value of New Contracts When Entered
Into During the Period (day one gains) (b)
- - - -
Net Option Premiums Paid/(Received) (c) (2) 24 (2) 20
Change in Fair Value Due to Valuation Methodology
Changes - 1 - 1
Effect of 98-10 Rescission (19) 1 (14) (32)
Changes in Fair Value of Risk Management
Contracts (e) 27 24 (28) 23
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (d)
17 - - 17

Ending Balance March 31, 2003 $294 $(128) $(21) $145

Domestic Power APCo CSPCo I&M KPCO
(in thousands)
Beginning Balance December 31, 2002 $96,852 $65,117 $70,861 $24,998
(Gain) Loss from Contracts Realized/Settled During
the Period (a) (25,745) (17,307) (16,202) (5,691)
Fair Value of New Contracts When Entered Into
During the Period (day one
gains) (b) - - - -
Net Option Premiums Paid/(Received) (c) (466) (274) (293) (106)
Change in Fair Value Due to Valuation Methodology
Changes - - - -
Effect of 98-10 Rescission (4,664) (3,135) (4,861) (1,744)
Changes in Fair Value of Risk Management
Contracts (e) 14,451 6,623 (296) (163)
Changes in Fair Value Risk Management Contracts
Allocated to Regulated Jurisdictions (d)
6,377 - 6,249 2,459

Ending Balance March 31, 2003 $ 86,805 $51,024 $55,458 $19,753

Domestic Power OPCo PSO SWEPCo TCC
(in thousands)
Beginning Balance December 31, 2002 $ 94,106 $ 3,545 $ 4,050 $ 5,414
(Gain) Loss from Contracts Realized/Settled
During the Period (a) (24,661) 220 (18) (670)
Fair Value of New Contracts When Entered Into
During the Period (day one - - - -
gains) (b)
Net Option Premiums Paid/(Received) (c) (363) - - -
Change in Fair Value Due to Valuation Methodology
Changes - - - -
Effect of 98-10 Rescission (4,159) - 151 187
Changes in Fair Value of Risk Management
Contracts (e) 10,868 - 595 (4,527)
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (d)
- 1,192 885 -

Ending Balance March 31, 2003 $ 75,791 $ 4,957 $ 5,663 $ 404

Domestic Power TNC
(in thousands)
Beginning Balance December 31, 2002 $ 2,043
(Gain) Loss from Contracts Realized/Settled During
the Period (a) (41)
Fair Value of New Contracts When Entered Into
During the Period (day one -
gains) (b)
Net Option Premiums Paid/(Received) (c) -
Change in Fair Value Due to Valuation Methodology
Changes -
Effect of 98-10 Rescission 20
Changes in Fair Value of Risk Management
Contracts (e) (269)
Changes in Fair Value of Risk Management Contracts
Allocated to Regulated Jurisdictions (d) (298)

Ending Balance March 31, 2003 $ 1,455

(a) "(Gain) Loss from Contracts Realized/Settled During the Period"
include 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)"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.
(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.

TABLE 1 Part II
Detail on MTM Risk Management Contract
Net Assets
As of March 31, 2003

Domestic Domestic AEP
Power Gas International Consolidated
(in millions)

Current Assets $ 473 $ 465 $ 157 $ 1,095
Non Current Assets 426 285 57 768
Total MTM Energy Assets $ 899 $ 750 $ 214 $ 1,863

Current Liabilities $(367) $(688) $(183) $(1,238)
Non Current Liabilities (238) (190) (52) (480)
Total MTM Risk Management Contract Liabilities $(605) $(878) $(235) $(1,718)

Total MTM Risk Management Contract Net Assets $ 294 $(128) $ (21) 145
Assets Held for Sale (Nordic) 17
Less Non-Trading Related Derivative Liabilities
(56)
Net Fair Value of Risk Management and Derivative
Contracts $ 106

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.
o The source of fair value used in determining the carrying amount of AEP's total MTM asset
or liability (external sources or modeled internally)
o The maturity, by year, of AEP's net assets/liabilities, giving an
indication of when these MTM amounts will settle and generate cash

TABLE 2 Part I
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of March 31, 2003

Remainder After
US POWER: 2003 2004 2005 2006 2007 2007 Total
(in millions)

Prices Actively Quoted - Exchange Traded
Contracts $ (5) $(6) $ (2) $(2) $ - $ - $(15)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) 52 58 21 14 7 - 152
Prices Based on Models and Other
Valuation Methods (b) 33 19 11 20 17 57 157

Total $ 80 $71 $ 30 $32 $24 $57 $294

U.S. GAS:
Prices Actively Quoted - Exchange
Traded Contracts (a) $ (39) $101 $ (6) $(1) $ - $ - $ 55
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) 41 - - - - - 41
Prices Based on Models and Other
Valuation Methods (b) (193) (41) (4) 9 8 (3) (224)

Total $(191) $ 60 $(10) $ 8 $ 8 $(3) $(128)

International:
Prices Actively Quoted - Exchange Traded
Contracts (a) $ (14) $ (1) $ - $ - $ - $ - $(15)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) (12) 6 - (1) - - (7)
Prices Based on Models and Other
Valuation Methods (b) (1) - - - 1 1 1

Total $ (27) $ 5 $ - $(1) $ 1 $ 1 $(21)

AEP Consolidated:
Prices Actively Quoted - Exchange Traded
Contracts $ (58) $ 94 $ (8) $(3) $ - $ - $ 25
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) 81 64 21 13 7 - 186
Prices Based on Models and Other
Valuation Methods (b) (161) (22) 7 29 26 55 (66)

Total $(138) $136 $ 20 $39 $33 $55 $145

APCo Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $16,282 $16,967 $5,722 $4,278 $1,949 $ - $45,198
Prices Based on Models and Other
Valuation Methods (b) 10,597 2,984 2,203 4,988 4,581 16,254 41,607
Total
$26,879 $19,951 $7,925 $9,266 $6,530 $16,254 $86,805

CSPCo Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $ 9,569 $ 9,974 $3,364 $2,514 $1,145 $ - $26,566
Prices Based on Models and Other
Valuation Methods (b) 6,229 1,754 1,295 2,932 2,693 9,555 24,458

Total $15,798 $11,728 $4,659 $5,446 $3,838 $9,555 $51,024

I&M Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $11,490 $10,513 $3,599 $2,690 $1,226 $ - $29,518
Prices Based on Models and Other
Valuation Methods (b) 6,438 1,872 1,386 3,138 2,882 10,224 25,940

Total $17,928 $12,385 $4,985 $5,828 $4,108 $10,224 $55,458

KPCo Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $3,705 $3,860 $1,302 $ 974 $ 443 $ - $10,284
Prices Based on Models and Other
Valuation Methods (b) 2,411 679 502 1,135 1,043 3,699 9,469

Total $6,116 $4,539 $1,804 $2,109 $1,486 $3,699 $19,753

OPCo Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $19,450 $15,232 $4,462 $3,336 $1,520 $ - $44,000
Prices Based on Models and Other
Valuation Methods (b) 7,652 2,281 1,718 3,890 3,573 12,677 31,791

Total $27,102 $17,513 $6,180 $7,226 $5,093 $12,677 $75,791

PSO Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $ 943 $ 928 $330 $247 $112 $ - $2,560
Prices Based on Models and Other
Valuation Methods (b) 611 172 127 286 264 937 2,397

Total $1,554 $1,100 $457 $533 $376 $937 $4,957

SWEPCo Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $1,077 $1,060 $377 $282 $128 $ - $ 2,924
Prices Based on Models and Other
Valuation Methods (b) 698 196 145 328 302 1,070 2,739

Total $1,775 $1,256 $522 $610 $430 $1,070 $ 5,663

TCC Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $ 77 $76 $27 $20 $ 9 $ - $209
Prices Based on Models and Other
Valuation Methods (b) 50 14 10 23 22 76 195

Total $127 $90 $37 $43 $31 $76 $404

TNC Remainder After
2003 2004 2005 2006 2007 2007 Total
(in thousands)
Prices Provided by Other External Sources
- - OTC Broker Quotes (a) $277 $272 $ 97 $ 72 $ 33 $ - $ 751
Prices Based on Models and Other
Valuation Methods (b) 179 51 37 85 77 275 704

Total $456 $323 $134 $157 $ 110 $275 $1,455

(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.

The determination of the point at which a market is no longer liquid for placing
it in the Modeled category in Table 2 Part I varies by market. Table 2 Part II
reports an estimate of the maximum tenors of the liquid portion of each energy
market used to complete Table 2 Part I.

Table 2 Part II
Maximum Domestic Tenor of the Liquid Portion of Risk Management Contracts
As of March 31, 2003
TENOR

(in months)
Natural Gas Forward Purchase and Sales
NYMEX Henry Hub Gas 72
Gas East - Northeast, Mid-continent
Gulf Coast, Texas 12

Gas West - Permian Basin, San Juan,
Rocky Mtns, Kern, Cdn Border(Sumas),
Malin, PGE Citygate, AECO 12

Power (Peak) Over the Counter Options
Power East - Cinergy 33
Power East - PJM 33
Power East - First Energy 21
Power East - NEPOOL 21
Power East - ERCOT 21
Power East - TVA 9
Power East - Com Ed 9
Power East - Entergy 33
Power West - PV, NP15,SP15,MidC,Mead 57
Peak Power Volatility (Options) ECAR, MidCon, NYPP, PJM, West Ercot
NEPOOL 21
OffPeak Power Volatility All Regions 0

Natural Gas
Liquids 14

Emissions 33

Coal 33

Cash Flow Hedges Included in Accumulated Other Comprehensive
Income on the Balance Sheet

AEP employs 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. AEP does not hedge all interest rate risk.

AEP employs 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. AEP does not hedge all
foreign currency exposure.

Table 3 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 AEP has in place. (However, given that under SFAS 133 not all hedges are
recorded in AOCI, the table does not provide an all-encompassing picture of
AEP's hedges). The table further indicates what portions of these hedges are
expected to roll off into the income statement 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.
TABLE 3
Cash Flow Hedges included in Accumulated Other Comprehensive Income
On the Balance Sheet as of March 31, 2003

Portion Expected to
Accumulated Other Be Reclassified to
Comprehensive Income Earnings During the
(Loss) After Tax
(a) Next 12 Months (b)
AEP Consolidated (in millions)

Domestic Power $(43) $(31)
Domestic Gas 8 (3)
Foreign Currency 2 2
Interest Rate (5) 1

Total AEP $(38) $(31)

Total Other Comprehensive Income Activity
Three Months Ended March 31, 2003

Domestic Domestic Foreign AEP
Power Gas Currency Interest Rate Consolidated
(in millions)

Accumulated OCI, December 31, 2002 $ (1) $ - $(3) $(12) $(16)
Changes in Fair Value (c) (65) 8 5 6 (46)
Reclassifications from OCI to Net
Income (d) 23 - - 1 24
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(43) $ 8 $ 2 $ (5) $(38)

APCo Domestic Foreign AEP
Power Currency Interest Rate Consolidated
(in thousands)

Accumulated OCI, December 31, 2002 $ (394) $(190) $(1,336) $(1,920)
Changes in Fair Value (c) (19,201) - (104) (19,305)
Reclassifications from OCI to Net
Income (d) 6,649 2 136 6,787
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(12,946) $(188) $(1,304) $(14,438)

CSPCo Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (267)
Changes in Fair Value (c) (11,251)
Reclassifications from OCI to Net
Income (d) 3,908
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(7,610)

I&M Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (286)
Changes in Fair Value (c) (12,039)
Reclassifications from OCI to Net
Income (d) 4,182
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(8,143)

KPCo Domestic KPCo
Power Interest Rate Consolidated
(in thousands)
Accumulated OCI, December 31, 2002 $ (103) $425 $ 322
Changes in Fair Value (c) (4,357) (43) (4,400)
Reclassifications from OCI to Net
Income (d) 1,513 22 1,535
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(2,947) $404 $(2,543)

OPCo Domestic Foreign OPCo
Power Currency Consolidated
(in thousands)
Accumulated OCI, December 31, 2002 $ (354) $(384) $ (738)
Changes in Fair Value (c) (14,928) - (14,928)
Reclassifications from OCI to Net
Income (d) 5,185 3 5,188
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(10,097) $(381) $(10,478)

PSO Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (42)
Changes in Fair Value (c) (1,833)
Reclassifications from OCI to Net
Income (d) 636
Accumulated OCI Derivative Gain (Loss) March
31, 2003 $(1,239)

SWEPCo Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (48)
Changes in Fair Value (c) (2,094)
Reclassifications from OCI to Net
Income (d) 727
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(1,415)

TCC Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (36)
Changes in Fair Value (c) (1,559)
Reclassifications from OCI to Net
Income (d) 541
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $(1,054)

TNC Domestic
Power
(in thousands)
Accumulated OCI, December 31, 2002 $ (15)
Changes in Fair Value (c) (645)
Reclassifications from OCI to Net
Income (d) 224
Accumulated OCI Derivative Gain (Loss)
March 31, 2003 $ (436)

(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 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.
(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.

Credit Risk

AEP limits credit risk by assessing creditworthiness of potential counterparties
before entering into transactions with them and continuing to evaluate their
creditworthiness after transactions have been initiated. Only after an entity
has met AEP's internal credit rating criteria will we extend unsecured credit.
AEP uses 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. AEP's independent analysis, in conjunction with the rating
agencies information, is used to determine appropriate risk parameters. AEP also
requires cash deposits, letters of credit and parental/affiliate guarantees as
security from counterparties depending upon credit quality in our normal course
of business.

AEP has risk management contracts with numerous counterparties. Since AEP's open
risk management contracts are valued based on changes in market prices of the
related commodities, AEP's exposures change daily. AEP believes that credit and
market exposures with any one counterparty is not material to AEP's financial
condition at March 31, 2003. At March 31, 2003 approximately 6% of AEP's
exposure was below investment grade as expressed in terms of net MTM assets. Net
MTM assets represents the aggregate difference between the forward market price
for the remaining term of the contract and the contractual price per
counterparty. As of March 31, 2003 the following table approximates counterparty
credit quality and exposure for AEP based on netting across AEP entities,
commodities and instruments:

TABLE 4
Futures,
Forward and
Counterparty Swap
Credit Quality: Contracts Options Total

(in millions)
AAA/Exchanges $ 12 $33 $ 45
AA 302 19 321
A 338 17 355
BBB 515 161 676
Below
Investment
Grade 77 11 88

Total $ 1,244 $241 $1,485

The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.

Merchant Plant Owned Assets Production and Hedging Information

Table 5 provides information on the proportion of output of AEP's generation
facilities (based on economic availability projections) economically hedged.
This information is forward-looking and provided on a prospective basis through
December 31, 2005. Please note that this table is point-in time estimates,
subject to changes in market conditions and AEP decisions on how to manage
operations and risk.

TABLE 5

Merchant Plant-Owned Assets Hedging Information
Estimated Next Three Years
As of March 31, 2003

2003 2004 2005
Estimated Plant Output Hedged (a) 93% 88% 83%

(a) Estimated Plant Output Hedged - Represents the portion of
megawatt-hours of future generation production for which AEP has sales
commitments to customers.

VaR Associated with Energy Trading Contracts

AEP uses a risk measurement model which calculates Value at Risk (VaR) to
measure AEP's commodity price risk in the Energy Trading portfolio. The VaR is
based on the variance - covariance method using historical prices to estimate
volatilities and correlations and assumes 95% confidence level, a one-day
holding period and a one-tailed distribution. Based on this VaR analysis, at
March 31, 2003 a near term typical change in commodity prices is not expected to
have a material effect on AEP's results of operations, cash flows or financial
condition. The following table shows the end, high, average, and low market risk
as measured by VaR for quarter ended and year-to-date:

AEP VaR Model

March 31, December 31,
2003 2002
End High Average Low End High Average Low
(in millions)

AEP $7 $19 $ 7 $5 $5 $24 $12 $4

APCo 1 3 2 1 1 4 1 -
CSPCo 1 2 1 1 1 3 1 -
I&M 1 2 1 1 1 3 1 -
KPCo - 1 - - - 1 - -
OPCo 1 2 1 1 1 4 1 -
PSO - - - - - - - -
SWEPCo - - - - - - - -
TCC - - - - - - - -
TNC - - - - - - - -

The High VaR for the first quarter 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 quarter.

The AEP VaR model results are adjusted using standard statistical treatments to
calculate the Committee of Chief Risk Officers (CCRO) VaR reporting metrics
listed below. The adjustments are made to take the AEP model results from a
one-day holding period to the ten-day holding period, from a one-tailed result
to a two-tailed result and from the 95% confidence level to the 99% confidence
level. The AEP VaR model's performance has not been evaluated for its accuracy
at calculating VaR using the CCRO VaR Metrics assumptions.

Committee of Chief Risk Officers (CCRO) VaR Metrics
Average
End of Q1 2003 for Q1 2003 High for Q1 2003 Low for Q1 2003
(in millions)

95% Confidence Level, Ten-Day
Holding Period, Two-Tailed $26 $28 $71 $17

99% Confidence Level, One-Day
Holding Period, Two-Tailed $11 $12 $30 $ 7

AEP utilizes 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, a one year holding period and a one-tailed distribution. The
volatilities and correlations were based on three years of daily prices. The
risk of potential loss in fair value attributable to AEP's exposure to interest
rates, primarily related to long-term debt with fixed interest rates, was $1,047
million at March 31, 2003 and $527 million at December 31, 2002. AEP would not
expect to liquidate its entire debt portfolio in a one year holding period,
therefore a near term change in interest rates should not materially affect
results of operations or consolidated financial position.

AEGCo is not exposed to risk from changes in interest rates on short-term and
long-term borrowings used to finance operations since financing costs are
recovered through the unit power agreements.

AEP is 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 for CSPCo and OPCo) and in
the ERCOT area of Texas (effective January 1, 2002 for TCC and TNC) or frozen by
settlement agreements in Michigan and West Virginia or capped in Indiana. To the
extent the fuel supply of the generating units in these states is not under
fixed price long-term contracts AEP is subject to market price risk. AEP
continues to be protected against market price changes by active fuel clauses in
Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas.

AEP employs physical forward purchase and sale contracts, exchange futures and
options, over-the-counter options, swaps, and other derivative contracts to
offset price risk where appropriate. AEP engages in risk management of
electricity, gas and to a lesser degree other commodities and as a result AEP is
subject to price risk. The amount of risk taken by the staff is controlled by
risk management operations and AEP's Chief Risk Officer and his staff. When the
risk from energy trading activities exceeds certain pre-determined limits, the
positions are modified or hedged to reduce the risk to be within the limits
unless specifically approved by the Risk Executive Committee.

CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures. Our chief
executive officer and our chief financial officer, after
evaluating the effectiveness of "disclosure controls and
procedures" (as defined in the Securities Exchange Act of 1934
Rules 13a-14(c) and 15d-14(c)) as of a date (the "Evaluation
Date") within 90 days before the filing date of this quarterly
report, have concluded that as of the Evaluation Date, our
disclosure controls and procedures were adequate and designed
to ensure that material information relating to us and our
consolidated subsidiaries would be made known to them by others
within those entities.

(b) Changes in internal controls. There were no significant changes
in our internal controls or to our knowledge, in other factors
that could significantly affect our disclosure controls and
procedures subsequent to the Evaluation Date.

PART II. OTHER INFORMATION

Item 5. Other Information.

NONE

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits:

AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

Exhibit 12 - Computation of Consolidated Ratio of Earnings to
Fixed Charges.

AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

Exhibit 99.1 - Certification of Chief Executive Officer Pursuant
to Section 1350 of Chapter 63 of Title 18 of the United States
Code.

Exhibit 99.2 - Certification of Chief Financial Officer Pursuant
to Section 1350 of Chapter 63 of Title 18 of the United States
Code.

(b) Reports on Form 8-K:

AEGCo, APCo, I&M, KPCo, PSO, SWEPCo, TCC and TNC

The following reports on Form 8-K were filed during the quarter ended
March 31, 2003.

Company Reporting Date of Report Item Reported
AEP February 25, 2003 Item 5. Other Events and
Regulation FD Disclosure
Item 7. Financial Statements
and Exhibits
AEP February 26, 2003 Item 7. Financial Statements
And Exhibits
Item 9. Regulation FD
Disclosure
AEP February 27, 2003 Item 5. Other Events and
Regulation FD Disclosure
Item 7. Financial Statements
And Exhibits
AEP March 14, 2003 Item 5. Other Events and
Regulation FD Disclosures
Item 7. Financial Statements
And Exhibits
CSPCo and OPCo February 4, 2003 Item 5. Other Events and
Regulation FD Disclosure

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934,
each registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The signatures for each undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.

AMERICAN ELECTRIC POWER COMPANY, INC.

By: /s/Geoffrey S. Chatas By: /s/Joseph M. Buonaiuto
Geoffrey S. Chatas Joseph M. Buonaiuto
Treasurer Controller and Chief Accounting Officer

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

By: /s/Geoffrey S. Chatas By: /s/Joseph M. Buonaiuto
Geoffrey S. Chatas Joseph M. Buonaiuto
Treasurer Controller and Chief Accounting Officer

Date: May 14, 2003

CERTIFICATIONS

I, E. Linn Draper, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of:

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;

2. Based on my knowledge, this quarterly report does not
contain any untrue statement of a material fact or omit to
state a material fact necessary to make the statements
made, in light of the circumstances under which such
statements were made, not misleading with respect to the
period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report,
fairly present in all material respects the financial
condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
quarterly report;

4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules
13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the
period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior
to the filing date of this quarterly report (the
"Evaluation Date"); and

c) presented in this quarterly report our conclusions about
the effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and
report financial data and have identified for the
registrant's auditors any material weaknesses in internal
controls; and

b) any fraud, whether or not material, that involves
management or other employees who have a significant role
in the registrant's internal controls; and

6.

The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

Dated: May 14, 2003 By: /s/ E. Linn Draper, Jr.
E. Linn Draper, Jr.
Chief Executive Officer

I, Susan Tomasky, certify that:

1. I have reviewed this quarterly report on Form 10-Q of:

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;

2. Based on my knowledge, this quarterly report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light
of the circumstances under which such statements were made,
not misleading with respect to the period covered by this
quarterly report;

3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report,
fairly present in all material respects the financial
condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
quarterly report;

4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules
13a-14 and 15d-14) for the registrant and we have:

a. designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;

b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and

c. presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
function):

a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b. any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and

6.

The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.

Dated: May 14, 2003 By: /s/ Susan Tomasky
Susan Tomasky
Chief Financial Officer