<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY
SELECTED CONSOLIDATED FINANCIAL DATA


                                                    Year Ended December 31,
                                 1999         1998         1997         1996         1995
                                                      (in thousands)
<S>                           <C>          <C>          <C>          <C>          <C>
INCOME STATEMENTS DATA:

  Operating Revenues          $1,229,994   $1,187,745   $1,094,851   $1,105,683   $1,071,862
  Operating Expenses           1,007,204      975,534      899,724      920,136      886,054
  Operating Income               222,790      212,211      195,127      185,547      185,808
  Nonoperating Income (Loss)       2,709       (1,343)       3,137         (970)       5,202
  Income Before Interest
    Charges                      225,499      210,868      198,264      184,577      191,010
  Interest Charges (net)          75,229       77,824       78,885       77,469       80,394
  Net Income                     150,270      133,044      119,379      107,108      110,616
  Preferred Stock Dividend
    Requirements                   2,131        2,131        2,442        6,029       11,907
  Earnings Applicable
    to Common Stock           $  148,139   $  130,913   $  116,937   $  101,079   $   98,709



                                                        December 31,
                                 1999         1998         1997         1996         1995
BALANCE SHEETS DATA:                                  (in thousands)

  Electric Utility Plant      $3,151,619   $3,053,565   $2,976,110   $2,899,893   $2,820,208
  Accumulated Depreciation     1,210,994    1,134,348    1,074,588    1,016,909      953,170
  Net Electric Utility Plant  $1,940,625   $1,919,217   $1,901,522   $1,882,984   $1,867,038

  Total Assets                $2,809,990   $2,681,690   $2,613,860   $2,541,586   $2,594,126

  Common Stock and Paid-in
    Capital                   $  613,899   $  613,518   $  613,138   $  615,735   $  615,453
  Retained Earnings              246,584      186,441      138,172       99,582       74,320
  Total Common Shareholder's
    Equity                    $  860,483   $  799,959   $  751,310   $  715,317   $  689,773

  Cumulative Preferred
    Stock - Subject to
    Mandatory Redemption (a)  $   25,000   $   25,000   $   25,000   $   75,000   $   82,500

  Long-term Debt (a)          $  924,545   $  959,786   $  969,600   $  897,281   $  990,796

  Obligations Under Capital
    Leases (a)                $   40,270   $   42,362   $   38,587   $   36,134   $   27,816

  Total Capitalization and
    Liabilities               $2,809,990   $2,681,690   $2,613,860   $2,541,586   $2,594,126
</TABLE>


(a) Including portion due within one year.
<PAGE>
COLUMBUS SOUTHERN POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF
RESULTS OF OPERATIONS


  Columbus Southern Power Company is a wholly-owned subsidiary
of American Electric Power Company, Inc. (AEP Co., Inc.), a public
utility holding company.  The Company is engaged in the generation,
purchase, sale, transmission and distribution of electric power to
655,000 retail customers in central and southern Ohio and does
business as American Electric Power (AEP).  The Company as a member
of the AEP System Power Pool (AEP Power Pool) shares in the
revenues and costs of the AEP Power Pool's wholesale sales to
neighboring utility systems and power marketers.  The Company also
sells wholesale power to municipalities.

 The cost of the AEP System's generating capacity is allocated
among the AEP Power Pool members based on their relative peak
demands and generating reserves through the payment or receipt of
capacity charges and 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 or costs.  Since the
Company's MLR increased in 1999, the AEP Power Pool is allocating
a larger share of certain revenues and expenses to the Company.

Net Income Increases

   Net income increased $17.2 million or 13% in 1999 primarily due
to increased sales to retail customers reflecting an 8% increase in
sales to residential customers and a 6% increase in commercial
sales.

<PAGE>
Operating Revenues Increase

   Operating revenues increased $42.2 million in 1999 as follows:

                                 Increase (Decrease)
(dollars in millions)            From Previous Year
                                  Amount           %
Retail:
  Residential                     $33.0
  Commercial                       26.2
  Industrial                        2.9
  Other                             0.2
                                   62.3           6.2

Wholesale                         (25.0)        (17.2)

Transmission                        0.7           2.5

Other                               4.2          29.2

  Total                           $42.2           3.6

   The increase in retail revenues resulted from a 5% increase in
retail energy sales primarily due to the increased sales to
residential and commercial customers, which reflects colder winter
weather in the Company's service territory, and growth in the
number of residential and commercial customers.

   The 17% decrease in wholesale revenues is attributable to the
Company's MLR share of a decline in net revenues from AEP Power
Pool trading transactions reflecting a decline in trading margins
resulting from a moderation in 1999 of extreme weather in 1998 and
capacity shortages experienced in the summer of 1998 in the AEP
Power Pool's marketing area.  Power trading transactions involve
the purchase and sale of substantial amounts of electricity and are
conducted by the AEP Power Pool.  Revenues from regulated trading
activities are allocated to AEP Power Pool members based on MLR and
recorded net of purchases.


<PAGE>
Operating Expenses Increase

   Operating expenses increased $31.7 million or 3% in 1999 due
mainly to increased purchased power expense.  Changes in the
components of operating expenses were as follows:

                                   Increase (Decrease)
(dollars in millions)              From Previous Year
                                    Amount           %

Fuel                                $ (3.5)        (1.9)
Purchased Power                       27.8         11.7
Other Operation                      (12.1)        (6.0)
Maintenance                            3.1          5.0
Depreciation                           3.3          3.6
Taxes Other Than Federal
  Income Taxes                         3.6          3.1
Federal Income Taxes                   9.5         12.4
  Total                             $ 31.7          3.2

   An increase in purchases of electricity from the AEP Power Pool
to support retail demand and increased capacity charges paid to the
AEP Power Pool due to the increase in the Company's MLR are the
primary reasons for the increase in purchased power expense.

   The decrease in other operation expense was primarily
attributable to increased gains on the sale of emission allowances
and cost containment efforts including staff reductions at the
power plants and within the engineering and maintenance group of
AEP Service Corporation which bills the Company for operations
support services.

   Federal income taxes attributable to operations increased
primarily due to an increase in pre-tax operating income.

Market Risks

   The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and
interest rates.  The allocation of trading of electricity and
related financial derivative instruments through the AEP Power Pool
exposes the Company to market risk.  Market risk represents the
risk of loss that may impact the Company due to adverse changes in
electricity commodity market prices and rates.  Policies and
procedures have been established to identify, assess and manage
market risk exposures including the use of a risk measurement model
which calculates Value at Risk (VaR).  The VaR is based on the
variance - covariance method using historical prices to estimate
volatilities and correlations and assuming a 95% confidence level
and a three-day holding period.  Throughout 1999 and 1998, the
highest, lowest and average VaR in the wholesale electricity
trading portfolio was less than $2.5 and $2 million, respectively.
Based on this VaR analysis, at December 31, 1999 a near term change
in electricity commodity prices is not expected to have a material
effect on the Company's results of operations, cash flows or
financial condition.

   The Company is exposed to changes in interest rates primarily
due to short-term and long-term borrowings to fund its business
operations.  The debt portfolio has both fixed and variable
interest rates with terms from one day to 28 years and an average
duration of seven years at December 31, 1999.  The Company measures
interest rate market risk exposure utilizing a VaR model. The
interest rate VaR model is based on a Monte Carlo simulation with
a 95% confidence level and a one year holding period.  The
volatilities and correlations were based on three years of weekly
prices.  The risk of potential loss in fair value attributable to
the Company's exposure to interest rates, primarily related to
long-term debt with fixed interest rates, was $135 million at
December 31, 1999 and $75 million at December 31, 1998.  The
Company 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 the consolidated financial position of the Company.


<PAGE>
INDEPENDENT AUDITORS' REPORT






To the Shareholders and Board of
Directors of Columbus Southern
Power Company:

We have audited the accompanying consolidated balance sheets of
Columbus Southern Power Company and its subsidiaries as of December
31, 1999 and 1998, and the related consolidated statements of
income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1999.  These financial
statements are the responsibility of the Company's management.  Our
responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with generally accepted
auditing standards.  Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement.  An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements.  An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation.  We believe that our audits
provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of
Columbus Southern Power Company and its subsidiaries as of December
31, 1999 and 1998, and the results of their operations and their
cash flows for each of the three years in the period ended December
31, 1999 in conformity with generally accepted accounting
principles.


/s/ Deloitte & Touche LLP


DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2000
(March 3, 2000 as to Note 6)

<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME


                                                              Year Ended December 31,
                                                       1999            1998            1997
                                                                  (in thousands)
<S>                                                 <C>             <C>             <C>
OPERATING REVENUES                                  $1,229,994      $1,187,745      $1,094,851

OPERATING EXPENSES:
  Fuel                                                 185,511         189,031         180,086
  Purchased Power                                      265,457         237,688         176,311
  Other Operation                                      190,614         202,720         180,663
  Maintenance                                           65,229          62,095          66,956
  Depreciation                                          94,532          91,218          90,723
  Amortization of Zimmer Plant Phase-in Costs             -               -             15,746
  Taxes Other Than Federal Income Taxes                120,147         116,548         117,519
  Federal Income Taxes                                  85,714          76,234          71,720
      TOTAL OPERATING EXPENSES                       1,007,204         975,534         899,724

OPERATING INCOME                                       222,790         212,211         195,127

NONOPERATING INCOME (LOSS)                               2,709          (1,343)          3,137

INCOME BEFORE INTEREST CHARGES                         225,499         210,868         198,264

INTEREST CHARGES                                        75,229          77,824          78,885

NET INCOME                                             150,270         133,044         119,379

PREFERRED STOCK DIVIDEND REQUIREMENTS                    2,131           2,131           2,442

EARNINGS APPLICABLE TO COMMON STOCK                 $  148,139      $  130,913      $  116,937
</TABLE>
<TABLE>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS


                                                                  Year Ended December 31,
                                                            1999          1998          1997
                                                                      (in thousands)
<S>                                                       <C>           <C>           <C>
Retained Earnings January 1                               $186,441      $138,172      $ 99,582
Net Income                                                 150,270       133,044       119,379
                                                           336,711       271,216       218,961
Deductions:
Cash Dividends Declared:
  Common Stock                                              87,996        82,644        78,684
  Cumulative Preferred Stock - 7% Series                     1,750         1,750         1,750
          Total Cash Dividends Declared                     89,746        84,394        80,434

Capital Stock Expense                                          381           381           355
          Total Deductions                                  90,127        84,775        80,789

Retained Earnings December 31                             $246,584      $186,441      $138,172


See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY
CONSOLIDATED BALANCE SHEETS


                                                                         December 31,
                                                                   1999                1998
                                                                        (in thousands)
ASSETS
<S>                                                            <C>                  <C>
ELECTRIC UTILITY PLANT:
  Production                                                   $ 1,544,858          $1,526,869
  Transmission                                                     350,826             339,934
  Distribution                                                   1,032,550             938,283
  General                                                          141,137             130,002
  Construction Work in Progress                                     82,248             118,477
          Total Electric Utility Plant                           3,151,619           3,053,565
  Accumulated Depreciation                                       1,210,994           1,134,348

          NET ELECTRIC UTILITY PLANT                             1,940,625           1,919,217

OTHER PROPERTY AND INVESTMENTS                                     101,286              73,088

CURRENT ASSETS:
  Cash and Cash Equivalents                                          5,107               7,206
  Accounts Receivable:
   Customers                                                        77,418              89,522
   Affiliated Companies                                             28,453              17,966
   Miscellaneous                                                     8,887              11,989
   Allowance for Uncollectible Accounts                             (3,045)             (2,598)
  Fuel - at average cost                                            21,484              22,140
  Materials and Supplies - at average cost                          41,696              33,263
  Accrued Utility Revenues                                          48,117              40,127
  Energy Marketing and Trading Contracts                            90,103              12,670
  Prepayments                                                       37,969              29,084
          TOTAL CURRENT ASSETS                                     356,189             261,369


REGULATORY ASSETS                                                  339,103             353,369

DEFERRED CHARGES                                                    72,787              74,647

           TOTAL                                               $ 2,809,990          $2,681,690

See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
</TABLE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY



                                                                         December 31,
                                                                   1999                1998
                                                                        (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                            <C>                 <C>
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized - 24,000,000 Shares
    Outstanding - 16,410,426 Shares                            $   41,026          $   41,026
  Paid-in Capital                                                 572,873             572,492
  Retained Earnings                                               246,584             186,441
           Total Common Shareholder's Equity                      860,483             799,959
  Cumulative Preferred Stock - Subject to Mandatory Redemption     25,000              25,000
  Long-term Debt                                                  924,545             959,786
           TOTAL CAPITALIZATION                                 1,810,028           1,784,745

OTHER NONCURRENT LIABILITIES                                       43,056              42,176

CURRENT LIABILITIES:
  Short-term Debt                                                  45,500              52,500
  Accounts Payable - General                                       28,279              34,631
  Accounts Payable - Affiliated Companies                          52,776              37,132
  Taxes Accrued                                                   143,477             141,831
  Interest Accrued                                                 13,936              14,355
  Energy Marketing and Trading Contracts                           87,911              13,682
  Other                                                            34,375              37,197
           TOTAL CURRENT LIABILITIES                              406,254             331,328

DEFERRED INCOME TAXES                                             447,607             442,100

DEFERRED INVESTMENT TAX CREDITS                                    44,716              48,710

DEFERRED CREDITS                                                   58,329              32,631

COMMITMENTS AND CONTINGENCIES (Notes 5 and 6)

           TOTAL                                               $2,809,990          $2,681,690
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS


                                                                 Year Ended December 31,
                                                            1999         1998            1997
                                                                    (in thousands)
<S>                                                      <C>          <C>            <C>
OPERATING ACTIVITIES:
  Net Income                                             $ 150,270    $ 133,044      $  119,379
  Adjustments for Noncash Items:
    Depreciation                                            94,962       91,426          90,959
    Deferred Federal Income Taxes                           10,481       17,101           5,250
    Deferred Investment Tax Credits                         (3,994)      (4,224)         (4,168)
    Deferred Fuel Costs (net)                                8,889      (11,311)         (6,115)
    Deferred Zimmer Plant Operating Expenses and
     Carrying Charges                                         -            -             16,097
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                                5,166       (5,910)        (47,966)
    Fuel, Materials and Supplies                            (7,777)      (8,226)         (4,900)
    Accrued Utility Revenues                                (7,990)      11,638         (19,939)
    Accounts Payable                                         9,292          476          16,459
  Payment of Disputed Tax and Interest
    Related to COLI                                         (2,240)     (37,243)           -
  Other (net)                                              (13,426)      29,776          (6,316)
          Net Cash Flows From Operating Activities         243,633      216,547         158,740

INVESTING ACTIVITIES:
  Construction Expenditures                               (115,321)    (114,979)       (108,931)
  Proceeds from Sale and Leaseback
    Transactions and Other                                   1,858        2,637           1,722
          Net Cash Flows Used For Investing Activities    (113,463)    (112,342)       (107,209)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt                                  -         111,075          86,172
  Retirement of Preferred Stock                               -            -            (52,953)
  Retirement of Long-term Debt                             (35,523)    (122,206)        (14,640)
  Change in Short-term Debt (net)                           (7,000)     (14,100)         14,800
  Dividends Paid on Common Stock                           (87,996)     (82,644)        (78,684)
  Dividends Paid on Cumulative Preferred Stock              (1,750)      (1,750)         (2,734)
          Net Cash Flows Used For Financing Activities    (132,269)    (109,625)        (48,039)

Net Increase (Decrease) in Cash and Cash Equivalents        (2,099)      (5,420)          3,492
Cash and Cash Equivalents January 1                          7,206       12,626           9,134
Cash and Cash Equivalents December 31                    $   5,107    $   7,206       $  12,626

See Notes to Consolidated Financial Statements.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
</TABLE>

1. SIGNIFICANT ACCOUNTING POLICIES:

Organization

     Columbus Southern Power Company (the Company or CSPCo) is a
wholly-owned subsidiary of American Electric Power Company, Inc.
(AEP Co., Inc.), a public utility holding company.  The Company is
engaged in the generation, purchase, sale, transmission and
distribution of electric power serving 655,000 retail customers in
its service territory in central and southern Ohio and does
business as American Electric Power (AEP).  Under the terms of the
AEP System Power Pool (AEP Power Pool) and the AEP System
Transmission Equalization Agreement, the Company's generation and
transmission facilities are operated in conjunction with the
facilities of certain other AEP affiliated utilities as an
integrated utility system.  The Company as a member of the AEP
Power Pool shares in the revenues and costs of AEP Power Pool
wholesale sales to neighboring utility systems and power marketers.
The Company also sells wholesale power to municipalities.

     The Company's three wholly-owned subsidiaries, which are
consolidated in these financial statements, are: Conesville Coal
Preparation Company (CCPC) which provides coal washing services for
one of the Company's generating stations; Simco Inc. which is
engaged in leasing a coal conveyor system to CCPC; and Colomet,
Inc. which is engaged in real estate activities on behalf of the
Company.

Regulation

     As a subsidiary of AEP Co., Inc., the Company is subject to
the regulation of the Securities and Exchange Commission (SEC)
under the Public Utility Holding Company Act of 1935 (1935 Act).
Retail rates are regulated by the Public Utilities Commission of
Ohio (PUCO).  The Federal Energy Regulatory Commission (FERC)
regulates the Company's wholesale and transmission rates.

Principles of Consolidation

     The consolidated financial statements include the revenues,
expenses, cash flows, assets, liabilities and equity of CSPCo and
its wholly-owned subsidiaries.  Significant intercompany items are
eliminated in consolidation.

Basis of Accounting

     As a cost-based rate-regulated entity, CSPCo's financial
statements reflect the actions of regulators that result in the
recognition of revenues and expenses in different time periods than
enterprises that are not rate regulated.  In accordance with
Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation,"
regulatory assets (deferred expenses) and regulatory liabilities
(deferred income) are recorded to reflect the economic effects of
regulation and to match expenses with regulated revenues.

Use of Estimates

     The preparation of these  financial statements in conformity
with generally accepted accounting principles requires in certain
instances the use of estimates.  Actual results could differ from
those estimates.

Utility Plant

     Electric utility plant is stated at original cost and is
generally subject to first mortgage liens.  Additions, major
replacements and betterments are added to the plant accounts.
Retirements of plant are deducted from the electric plant in
service account and are deducted from accumulated depreciation
together with associated removal costs, net of salvage.  The costs
of labor, materials and overheads incurred to operate and maintain
utility plant are included in operating expenses.

Allowance for Funds Used During Construction (AFUDC)

     AFUDC is a noncash nonoperating income item that is
capitalized and recovered through depreciation over the service
life of utility plant.  It represents the estimated cost of
borrowed and equity funds used to finance construction projects.
The amounts of AFUDC for 1999, 1998 and 1997 were not significant.

Depreciation

     Depreciation of electric utility plant is provided on a
straight-line basis over the estimated useful lives of utility
plant and is calculated largely through the use of composite rates
by functional class.  The annual composite depreciation rates for
1999, 1998 and 1997 are as follows:

Functional Class               Annual Composite
of Property                   Depreciation Rates
                            1999     1998     1997
Production                  3.2%     3.2%     3.2%
Transmission                2.3%     2.3%     2.3%
Distribution                3.7%     3.7%     3.7%
General                     3.3%     3.6%     3.4%



     Expenditures for the demolition and removal of plant are
charged to the accumulated provision for depreciation and recovered
through depreciation charges included in rates.

Cash and Cash Equivalents

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

Operating Revenues and Fuel Costs

     Revenues include billed revenues as well as an accrual of
electricity consumed but unbilled at month-end.  Changes in retail
jurisdictional fuel costs are deferred until reflected in revenues
in later months through a fuel cost recovery mechanism.  The
deferral is amortized to fuel expense commensurate with its
recovery in rates. Wholesale jurisdictional fuel cost changes are
expensed and billed as incurred.

Energy Marketing and Trading Transactions

     The AEP Power Pool implements and administers power marketing
and trading transactions (trading activities) in which the Company
shares.  Trading activities involve the sale of electricity under
physical forward contracts at fixed and variable prices and the
trading of electricity contracts including exchange traded futures
and options, over-the-counter options and swaps.  The majority of
these transactions represent physical forward electricity contracts
in the AEP System's traditional marketing area and are typically
settled by entering into offsetting contracts.  The net revenues
from these regulated transactions in AEP Power Pool's traditional
marketing area are included in operating revenues for ratemaking,
accounting and financial and regulatory reporting purposes.

     In addition the AEP Power Pool enters into transactions for
the purchase and sale of electricity options, futures and swaps,
and for the forward purchase and sale of electricity outside of the
AEP System's traditional marketing area.  The Company's share of
these non-regulated trading activities are included in nonoperating
income.

     In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's Emerging Issues Task Force Consensus
(EITF) 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities." The EITF requires that all energy
trading contracts be marked-to-market.  The effect on the
Consolidated Statements of Income of marking open trading contracts
to market is deferred as regulatory assets or liabilities for those
open trading transactions within the AEP Power Pool's marketing
area that are included in cost of service on a settlement basis for
rate-making purposes.  The Company's share of non-regulated open
trading contracts are accounted for on a mark-to-market basis in
nonoperating income.  Unrealized mark-to-market gains and losses
from trading activities are reported as assets and liabilities,
respectively. The adoption of the EITF did not have a material
effect on results of operations, cash flows or financial condition.

     The Company enters into contracts to manage the exposure to
unfavorable changes in the cost of debt to be issued.  These
anticipatory debt instruments are entered into in order to manage
the change in interest rates between the time a debt offering is
initiated and the issuance of the debt (usually a period of 60
days).  Gains or losses are deferred and amortized over the life of
the debt issuance with the amortization included in interest
charges.  There were no such forward contracts outstanding at
December 31, 1999 or 1998.

     See Note 11 - Financial Instruments, Credit and Risk
Management for further discussion.

Reclassification

     Certain prior year amounts have been reclassified to conform
to current year presentation.  Such reclassifications had no impact
on previously reported net income.

Income Taxes

     The Company follows the liability method of accounting for
income taxes as prescribed by SFAS 109, "Accounting for Income
Taxes." Under the liability method, deferred income taxes are
provided for all temporary differences between the book cost and
tax basis of assets and liabilities which will result in a future
tax consequence.  Where the flow-through method of accounting for
temporary differences is reflected in rates (that is, deferred
taxes are not included in the cost of service for determining
regulated rates for electricity), deferred income taxes are
recorded and related regulatory assets and liabilities are
established in accordance with SFAS 71.

Investment Tax Credits

     Investment tax credits have been accounted for under the
flow-through method except where regulatory commissions have reflected
investment tax credits in the rate-making process on a deferral
basis.  Investment tax credits that have been deferred are being
amortized over the life of regulated plant investment.

Debt and Preferred Stock

     Gains and losses from the reacquisition of debt are deferred
as regulatory assets and amortized over the remaining term of the
reacquired debt in accordance with rate-making treatment.  If debt
is refinanced, reacquisition costs are deferred and amortized over
the term of the replacement debt commensurate with their recovery
in rates.

     Debt discount or premium and debt issuance expenses are
deferred and amortized over the term of the related debt, with the
amortization included in interest charges.

     Redemption premiums paid to reacquire preferred stock are
included in paid-in capital and amortized to reduce retained
earnings commensurate with their recovery in rates.  The excess of
par value over the cost of preferred stock reacquired is credited
to paid-in capital and amortized to retained earnings.

Other Property and Investments

     Other property and investments are stated at cost.

Comprehensive Income

     There were no material differences between net income and
comprehensive income.


2.  RATE MATTERS:

     The Federal Energy Regulatory Commission (FERC) issued orders
888 and 889 in April 1996 which required each public utility that
owns or controls interstate transmission facilities to file an open
access network and point-to-point transmission tariff that offers
services comparable to the utility's own uses of its transmission
system.  The orders also require utilities to functionally unbundle
their services, by requiring them to use their own transmission
service tariffs in making off-system and third-party sales.  As
part of the orders, the FERC issued a pro-forma tariff which
reflects the Commission's views on the minimum non-price terms and
conditions for non-discriminatory transmission service.  The FERC
orders also allow a utility to seek recovery of certain
prudently-incurred stranded costs that result from
unbundled transmission service.

     In July 1996, the AEP System companies filed an Open Access
Transmission Tariff conforming with the FERC's pro-forma
transmission tariff, subject to the resolution of certain pricing
issues.  The 1996 tariff incorporated transmission rates which were
the result of a settlement of a pending rate case, but which were
being collected subject to refund from certain customers who
opposed the settlement and continued to litigate the reasonableness
of AEP's transmission rates.  On July 30, 1999, the FERC issued an
order in the litigated rate case which would reduce AEP's rates for
the affected customers below the settlement rate.  AEP and certain
of the affected customers have sought rehearing of the Commission's
Order.  The Company made a provision in September 1999 for its
share of the refund including interest.

     On December 10, 1999, the AEP System filed a settlement
agreement with the FERC resolving the issues on rehearing of the
July 30, 1999 order.  Under terms of the settlement, the AEP System
will make refunds retroactive to September 7, 1993 to certain
customers affected by the July 30, 1999 FERC order.  The refunds
will be made in two payments.  The first payment was made February
2, 2000 pursuant to  a FERC order granting AEP's request to make
interim refunds.  The remainder will be paid after the FERC issues
a final order and approves a compliance filing that the AEP System
will make pursuant to the final order.  In addition, a new rate was
made effective January 1, 2000, subject to FERC approval, for all
transmission service customers and a future rate was established to
take effect upon the consummation of the AEP and Central and South
West Corporation merger unless a superseding rate is made effective
prior to the merger.


3. EFFECTS OF REGULATION:

     In accordance with SFAS 71 the consolidated financial
statements include regulatory assets (deferred expenses) and
regulatory liabilities (deferred income) recorded in accordance
with regulatory actions in order to match expenses and revenues
from cost-based rates in the same accounting period.  Regulatory
assets are expected to be recovered in future periods through the
rate-making process and regulatory liabilities are expected to
reduce future cost recoveries.  Among other things, application of
SFAS 71 requires that the Company's regulated rates be cost-based
and the recovery of regulatory assets must be probable.  Management
has reviewed all the evidence currently available and concluded
that the Company continues to meet the requirements to apply SFAS
71.  In the event a portion of the Company's business no longer met
those requirements, net regulatory assets would have to be written
off for that portion of the business and assets attributable to
that portion of the business would have to be tested for possible
impairment and, if required, an impairment loss recorded unless the
net regulatory assets and impairment losses are recoverable as a
stranded cost.  (See Note 4 "Ohio Restructuring Legislation.")


<PAGE>
     Recognized regulatory assets and liabilities are comprised of
the following:
                                       December 31,
                                     1999       1998
                                      (in thousands)
Regulatory Assets:
  Amounts Due From Customers For
    Future Income Taxes            $243,031   $248,115
  Deferred Zimmer Plant
    Carrying Charges                 42,826     42,841
  Unamortized Loss On
    Reacquired Debt                  23,307     26,537
  Other                              29,939     35,876
  Total Regulatory Assets          $339,103   $353,369

Regulatory Liabilities:
  Deferred Investment Tax Credits   $44,716    $48,710
  Other*                             37,621     26,052
  Total Regulatory Liabilities      $82,337    $74,762

* Included in Deferred Credits on the Consolidated Balance Sheets.


4. OHIO RESTRUCTURING LEGISLATION:

     The Ohio Electric Restructuring Act of 1999 (the Act) became
law in October 1999.  The Act provides for customer choice of
electricity supplier, a residential rate reduction of 5% for the
generation portion of rates and a freezing of generation rates
including fuel rates beginning on January 1, 2001.  The Act also
provides for a five-year transition period to move from cost-based
rates to market pricing for generation services.  It authorizes the
PUCO to address certain major transition issues including
unbundling of rates and the recovery of transition costs.  Under
the Act, transition costs can include regulatory assets, generating
asset impairments and other stranded costs, employee severance and
retraining costs, consumer education costs and other costs.
Stranded generation costs are those costs of generation above the
market price for electricity that potentially would not be
recoverable in a competitive market.

     Retail electric services that will be competitive are defined
in the Act as electric generation service, aggregation service and
power marketing and brokering.  Under the legislation the PUCO is
granted broad oversight responsibility and is required by the Act
to promulgate rules for competitive retail electric generation
service and transition plan filings.  The Act also gives the PUCO
authority to approve a transition plan for each electric utility
company and sets a deadline of no later than October 31, 2000 for
those approvals.

     The Act provides that electric utilities in Ohio with an
opportunity to recover PUCO approved allowable transition costs
through generation rates paid through December 31, 2005 by
customers who do not switch generation suppliers and through a
transition charge for customers who switch generation suppliers.
Recovery of the regulatory asset portion of transition costs can,
under certain circumstances, extend beyond the five-year transition
period but cannot continue beyond December 31, 2010.

     The Act also provides for a reduction in property tax
assessments, the  imposition of franchise and income taxes, and the
replacement of a gross receipts tax with a kilowatt hour (kwh)
based excise tax.  The property tax assessment percentage on
generation property will be lowered from 100% to 25% of value
effective January 1, 2001 and electric utilities will become
subject to the Ohio Corporate Franchise Tax and municipal income
taxes on January 1, 2002.  The last year for which electric
utilities will pay the excise tax based on gross receipts is the
tax year ending April 30, 2002.  As of May 1, 2001 electric
distribution companies will be subject to an excise tax based on
kwh sold to Ohio customers.  The gross receipts tax is paid at the
beginning of the tax year, deferred as a prepaid expense and
amortized to expense during the tax year pursuant to the tax law
whereby the payment of the tax results in the privilege to conduct
business in the year following the payment of the tax.  The change
in the tax law to impose an excise tax based on kwh sold to Ohio
customers commencing before the expiration of the gross receipts
tax privilege period will result in a 12 month period when the
Company is recording as an expense both the gross receipts tax and
the excise tax.  In the Company's Ohio transition plan filing,
recovery of $40 million was sought for this overlap of the gross
receipts and excise taxes.

     The Company filed its transition plan with the PUCO on
December 30, 1999.  The filing included the following elements:

     a rate unbundling plan including tariff terms and conditions
     necessary for restructuring,
     a corporate separation plan,
     an application for transition revenues,
     a plan for independent operation of transmission facilities
     and
     other components for the implementation of restructuring.

     Under the rate unbundling plan in the transition plan filing,
the Company will offer two transition period tariffs beginning
January 1, 2001, the standard tariff and the open access
distribution tariff.  The proposed standard tariff applies to
customers who do not choose an alternative energy supplier.  This
tariff schedule includes detailed charges for generation,
transmission and distribution and riders to fund universal service,
to promote energy efficiency and to recover regulatory assets and
taxes.  Taxes include charges for municipal income, excise and
franchise taxes and tax credits for gross receipts and property
taxes.  For customers who choose an alternative electric supplier,
the proposed open access distribution tariff will apply.  This
tariff includes charges for transmission and distribution and
riders to fund universal service, to promote energy efficiency and
to recover regulatory assets and taxes.  These riders are the same
as those in the standard tariff except there is no property tax
credit.

     The corporate separation plan contains proposals for the
Company to establish separate subsidiaries to own and operate the
transmission and distribution assets.  The Company will retain
generation related assets.  The separation plan will be implemented
in a manner that recognizes the current overlap of financing
arrangements.  This would permit an orderly and economically
efficient separation of generation from transmission and
distribution so that additional transition costs can be minimized
from premature unwinding of existing financial instruments.  Prior
to the actual legal separation, the Company will functionally
separate generation from transmission and distribution.

     An application to receive transition revenues was included in
the Company's transition plan filing.  It requests recovery of
stranded generation costs over a five year period and recovery of
generation-related regulatory assets of $363 million over a 10-year
period.  The amount requested for recovery of regulatory assets
includes current and new regulatory assets including those arising
from compliance with the Act.

     Included in the transition plan is a proposal to implement
independent operation of the transmission system.  The Company
proposes to join a regional transmission organization whose
approval is currently pending before the FERC.  A project timeline
for activities to implement operational support systems and other
technical implementation issues to arrive at and support a
competitive electricity market are included in the transition plan.

     The Company plans to provide severance, retraining, early
retirement, retention, outplacement and other assistance for
displaced employees.  At this time no employees are identified as
affected by electric utility restructuring.  Consequently, recovery
of such costs was not requested in transition revenues as filed
with the transition plan.

     The transition plan includes a consumer education plan which
will be implemented in conjunction with other electric utilities
and the PUCO staff.  The transition plan also has terms and
conditions for changing suppliers and the commitment of time a
customer must accept in a service contract which are two features
necessary to accommodate restructuring.

     A proposed shopping incentive in the transition plan
represents the lower of the market price or the unbundled
generation rate in current tariff schedules.

     As discussed in Note 3, "Effects of Regulation," the Company
defers as regulatory assets and liabilities certain expenses and
revenues consistent with the regulatory process in accordance with
SFAS 71.  Management has concluded that as of December 31, 1999 the
requirements to apply SFAS 71 continue to be met since the
Company's rates for generation will continue to be cost-based
regulated until the PUCO takes action on the transition plan and
the proposed tariff schedules contained in it as provided in the
Act.  The establishment of rates and charges under the transition
plan should enable the Company to determine its ability to recover
regulatory assets, transition costs and other stranded costs, a
requirement to discontinue application of SFAS 71.

     When the transition plan and tariff schedules are approved,
the application of SFAS 71 will be discontinued for the Ohio retail
jurisdictional portion of the  generation business.  At that time
the Company will have to write-off its Ohio jurisdictional
generation-related regulatory assets to the extent that they cannot
be recovered under the tariff schedules in the transition plan
approved by the PUCO and record any asset impairments in accordance
with SFAS 121, "Accounting for the Impairment of Long-lived Assets
and for Long-lived Assets to Be Disposed Of."  An impairment loss
would be recorded to the extent that the cost of generation assets
cannot be recovered through generation-related revenues during the
transition period and future market prices.  Until the PUCO
completes its regulatory process and issues an order related to the
Company's transition plan, it is not possible for management to
determine if any of the Company's generating assets are impaired in
accordance with SFAS 121.  The amount of regulatory assets recorded
on the books at December 31, 1999 applicable to the Ohio retail
jurisdictional generating business is $305 million before related
tax effects.  Recovery of these regulatory assets and an estimated
asset impairment are being sought as a part of the Company's Ohio
transition plan filing.

     A determination of whether the Company will experience any
asset impairment loss regarding its Ohio retail jurisdictional
generating assets and any loss from a possible inability to recover
Ohio generation-related regulatory assets and other transition
costs cannot be made until the PUCO takes action on the Company's
transition plan.  Management is seeking full recovery of
generation-related regulatory assets, stranded costs and other
transition costs in its transition plan filing.  The PUCO is
required to complete its regulatory process including review of the
Company's transition plan filing and issue a transition order no
later than October 31, 2000.  Should the PUCO fail to fully approve
the Company's transition plan and its tariff schedules which
include recovery of the Company's generation-related regulatory
assets, stranded costs and other transition costs, it could have a
material adverse effect on results of operations, cash flows and
possibly financial condition.


5. COMMITMENTS AND CONTINGENCIES:

Construction and Other Commitments

     Substantial construction commitments have been made to support
the Company's utility operations and are estimated to be $395
million for 2000-2002.

     Long-term fuel supply contracts contain clauses that provide
for periodic price adjustments.  The PUCO has a fuel clause
mechanism that provides for deferral and subsequent recovery or
refund of changes in the cost of fuel with commission review and
approval.  The fuel supply contracts are for various terms, the
longest of which extends to 2007, and contain various clauses that
would release the Company from its obligation under certain force
majeure conditions.

Federal EPA Complaint and Notice of Violation - 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.

     On November 3, 1999 the Department of Justice, at the request
of the United States (U.S.) Environmental Protection Agency
(Federal EPA), filed a complaint in the U.S. District Court for the
Southern District of Ohio that alleges the Company and certain
other affiliated utilities made modifications to generating units
at certain of their coal-fired generating plants over the course of
the past 25 years that extend unit operating lives or increase unit
generating capacity without a preconstruction permit in violation
of the Clean Air Act.  Federal EPA also issued Notices of Violation
to other AEP companies alleging similar violations at certain AEP
plants.  A number of unaffiliated utilities also received Notices
of Violation, complaints or administrative orders.

     The states of New Jersey, New York and Connecticut were
subsequently granted leave to intervene in the Federal EPA's action
against the Company under the Clean Air Act.  On November 18, 1999
a number of environmental groups filed a lawsuit against power
plants owned by the Company alleging similar violations to those in
the Federal EPA complaint and Notices of Violation.  This action
has been consolidated with the Federal EPA action.

     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).  Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts Federal EPA's contentions, could be
substantial.

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

     In the event the Company does 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, transition charges and/or reflected in the future market
prices of electricity.

Litigation

     The Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns requested a ruling
from their National Office that certain interest deductions claimed
by the Company relating to AEP's corporate owned life insurance
(COLI) program should not be allowed.  As a result of a suit filed
in U.S. District Court (discussed below) this request for ruling
was withdrawn by the IRS agents.  Adjustments have been or will be
proposed by the IRS disallowing COLI interest deductions for
taxable years 1991-96.  A disallowance of the COLI interest
deductions through December 31, 1999 would reduce earnings by
approximately $43 million (including interest).

     The Company made payments of taxes and interest attributable
to COLI interest deductions for taxable years 1991-98 to avoid the
potential assessment by the IRS of any additional above market rate
interest on the contested amount.  The payments  to the IRS are
included on the consolidated balance sheet in other property and
investments pending the resolution of this matter.  The Company is
seeking refund through litigation of all amounts paid plus
interest.

     In order to resolve this issue, the Company filed suit against
the United States in the U.S. District Court for the Southern
District of Ohio in March 1998.  In 1999 a U.S. Tax Court judge
decided in the Winn-Dixie Stores v. Commissioner case that a
corporate taxpayer's COLI interest deduction should be disallowed.
Notwithstanding the Tax Court's decision in Winn-Dixie, management
has made no provision for any possible adverse earnings impact from
this matter because it believes, and has been advised by outside
counsel, that it has a meritorious position and will vigorously
pursue its lawsuit.  In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results of
operations, cash flows and possibly financial condition.

     The Company is involved in a number of other legal proceedings
and claims.  While management is unable to predict the ultimate
outcome of litigation, it is not expected that the resolution of
these matters will have a material adverse effect on the results of
operations, cash flows or financial condition.


6. SUBSEQUENT EVENT - NOx REDUCTIONS (March 3, 2000):

     On March 3, 2000, the U.S. Court of Appeals for the District
of Columbia Circuit (Appeals Court) issued a decision generally
upholding Federal EPA's final rule (the NOx rule) that requires
substantial reductions in nitrogen oxide (NOx) emissions in 22
eastern states, including Ohio where the Company's generating
plants are located.  A number of utilities, including the Company,
had filed petitions seeking a review of the final rule in the
Appeals Court.  On May 25, 1999, the Appeals Court had indefinitely
stayed the requirement that states develop revised air quality
programs to impose the NOx reductions but did not, however, stay
the final compliance date of May 1, 2003.

     On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to the
Clean Air Act (Section 126 Rule).  The rule approved portions of
the states' petitions and imposed NOx reduction requirements on AEP
System generating units which are approximately equivalent to the
reductions contemplated by the NOx Rule.  The AEP System companies
with generating plants, as well as other utility companies, filed
a petition in the Appeals Court seeking review of Federal EPA's
approval of the northeastern states' petitions.  In 1999, three
additional northeastern states and the District of Columbia filed
petitions with Federal EPA similar to those originally filed by the
eight northeastern states.  Since the petitions relied in part on
compliance with an 8-hour ozone standard remanded by the Appeals
Court in May 1999, Federal EPA indicated its intent to decouple
compliance with the 8-hour standard and issue a revised rule.

     On December 17, 1999, Federal EPA issued a revised Section 126
Rule not based on the 8-hour standard and ordered 392 industrial
facilities, including certain coal-fired generating plants owned by
the Company, to reduce their NOx emissions by May 1, 2003.  This
rule approves portions of the petitions filed by four northeastern
states which contend that their failure to meet Federal EPA smog
standards is due to emissions from upwind states' industrial and
coal-fired generating facilities.

     Preliminary estimates indicate that compliance with the NOx
rule upheld by the Appeal Court could result in required capital
expenditures of approximately $136 million for the Company.  Since
compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the Company's
preliminary estimate depending upon the compliance alternatives
selected to achieve reductions in NOx emissions.  Unless such costs
are recovered from customers through regulated rates, transition
charges and/or reflected in the future market price of electricity,
they will have an adverse effect on future results of operations
and cash flows and possibly financial condition.


7. RELATED PARTY TRANSACTIONS:

     Benefits and costs of the AEP System's generating plants are
shared by members of the AEP Power Pool of which the Company is a
member.  Under the terms of the System Interconnection Agreement,
capacity charges and credits are designed to allocate the cost of
the System's capacity among the AEP Power Pool members based on
their relative peak demands and generating reserves.  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.

     Operating revenues include $15.1 million in 1999, $20.1
million in 1998 and $18.6 million in 1997 for energy supplied to
the AEP Power Pool.

     Since the Company's internal peak demand exceeds its
generating capacity, charges for AEP Power Pool capacity
reservation, which is a charge for the right to receive power even
if the power is not taken, and charges for energy received from the
AEP Power Pool were included in purchased power expense as follows:

                           Year Ended December 31,
                          1999       1998       1997
                                 (in thousands)

Capacity Charges        $114,794   $ 98,042   $ 82,536
Energy Charges            84,780     69,577     74,416

     Total              $199,574   $167,619   $156,952


<PAGE>
     The AEP Power Pool allocated operating revenues, purchased
power expense and nonoperating income to the Company. Power
marketing and trading operations, which are described in Note 1,
are conducted by the AEP Power Pool and shared with the Company.
Net trading transactions are included in operating revenues if the
trading transactions are within the AEP Power Pool's traditional
marketing area and are recorded in nonoperating income if the net
trading transactions are outside of the AEP Power Pool's
traditional marketing area.  The total amounts allocated by the AEP
Power Pool, which includes amounts for power marketing and trading
transactions, are as follow:

                            Year Ended December 31,
                            1999       1998      1997
                                  (in thousands)
Operating Revenues        $103,962   $109,963  $63,635
Purchased Power Expense     60,926     62,728   13,209
Nonoperating Income (Loss)   1,914     (6,335)     (44)

     Purchased power expense includes $6.0 million in 1999, $5.9
million in 1998 and $6.1 million in 1997 for energy bought from the
Ohio Valley Electric Corporation, an affiliated company that is not
a member of the AEP Power Pool.

     The Company participates in the AEP Transmission Equalization
Agreement along with other AEP System electric operating utility
companies.  This agreement combines certain AEP System companies'
investments in transmission facilities and shares the costs of
ownership in proportion to the System companies' respective peak
demands.  Pursuant to the terms of the agreement, since the
Company's relative investment in transmission facilities is less
than its relative peak demand, other operation expense includes
equalization charges of $39.0 million, $35.6 million and $29.9
million in 1999, 1998 and 1997, respectively.

     American Electric Power Service Corporation (AEPSC) provides
certain managerial and professional services to AEP System
companies including the Company.  The costs of the services are
billed by AEPSC to its affiliated companies on a direct-charge
basis whenever possible and on reasonable bases of proration for
shared services.  The billings for services are made at cost and
include no compensation for the use of equity capital, which is
furnished to AEPSC by AEP Co., Inc.  Billings from AEPSC are
capitalized or expensed depending on the nature of the services
rendered.  AEPSC and its billings are subject to the regulation of
the SEC under the 1935 Act.

<PAGE>
8. STAFF REDUCTIONS:

     During 1998 an internal evaluation of the power generation
organization was conducted with a goal of developing a better
organizational structure for a competitive generation market.  The
study was completed in October 1998.  In addition, a review of
energy delivery staffing levels was conducted in 1998.  As a result
approximately 70 power generation and energy delivery positions
were identified for elimination.

     Severance accruals totaling $3.4 million were recorded by the
Company in December 1998 for reductions in power generation and
energy delivery staffs and were charged to other operation expense
in the Consolidated Statements of Income.  In the first quarter of
1999 the power generation and energy delivery staff reductions were
made.  The amount of severance benefits paid was not significantly
different from the amount accrued.


9. BENEFIT PLANS:

     The Company and its subsidiaries participate in the AEP System
qualified pension plan, a defined benefit plan which covers all
employees.  Net pension credits for the years ended December 31,
1999 and 1998 were $4.9 million and $1.4 million, respectively.
Pension costs were not significant in 1997.

     Postretirement benefits other than pensions are provided for
retired employees for medical and death benefits under an AEP
System plan.  The annual accrued costs were $8.6 million in 1999
and $7.5 million in 1998 and 1997.

     A defined contribution employee savings plan required that the
Company make contributions to the plan totaling $1.7 million in
1999, $1.8 million in 1998 and $1.9 million in 1997.


10. SEGMENT INFORMATION:

     Effective December 31, 1998 the Company adopted SFAS 131,
"Disclosures about Segments of an Enterprise and Related
Information".  The Company has one reportable segment, a regulated
vertically integrated electricity generation and energy delivery
business.  All other activities are insignificant.  The Company's
operations are managed on an integrated basis because of the
substantial impact of bundled cost-based rates and regulatory
oversight on business processes, cost structures and operating
results.  Included in the regulated electric utility segment is the
power marketing and trading activities that are discussed in Note
1.  For the years ended December 31, 1999, 1998 and 1997, all of
the Company's revenues are derived from the generation, sale and
delivery of electricity in the U.S.


11. FINANCIAL INSTRUMENTS, CREDIT AND RISK MANAGEMENT:

     The Company is subject to market risk as a result of changes
in electricity commodity prices and interest rates.  The Company
through its membership in the AEP Power Pool participates in a
power marketing and trading operation that manages the exposure to
electricity commodity price movements using physical forward
purchase and sale contracts at fixed and variable prices, and
financial derivative instruments including exchange traded futures
and options, over-the-counter options, swaps and other financial
derivative contracts at both fixed and variable prices.  Physical
forward electricity contracts within the AEP System's traditional
marketing area are recorded on a net basis as operating revenues in
the month when the physical contract settles.  The Company's share
of the net gains from these regulated transactions for the years
ended December 31, 1999 and 1998 are $4 million and $19 million,
respectively.  These activities were not material in 1997.

     Non-regulated physical forward electricity contracts outside
AEP's traditional marketing area, and all financial electricity
trading transactions where the underlying physical commodity is
outside AEP's traditional marketing area are marked to market and
recorded in nonoperating income.  These non-regulated open trading
contracts are accounted for on a mark-to-market basis in
non-operating income.  The Company's share of the net gains (losses)
from these non-regulated trading transactions for the year ended
December 31, 1999 and 1998 are $2 million and $(6) million,
respectively.

     In the first quarter of 1999 the Company adopted EITF 98-10
"Accounting for Contracts Involved in Energy Trading and Risk
Management Activities."  The EITF requires that all energy trading
contracts be marked-to-market.  The effect on the Consolidated
Statements of Income of marking open regulated trading contracts to
market is deferred as regulatory assets or liabilities for those
open trading transactions within the AEP Power Pool's marketing
area that are included in the cost of service on a settlement basis
for rate-making purposes.  The unrealized mark-to-market gains and
losses from trading of financial instruments are reported as assets
and liabilities, respectively.  These activities were not material
in prior periods.

     The Company is exposed to risk from changes in interest rates
primarily due to short-term and long-term borrowings used to fund
its business operations.  The debt portfolio has both fixed and
variable interest rates with terms from one day to 28 years and an
average duration of seven years at December 31, 1999.  A near term
change in interest rates should not materially affect results of
operations or financial position since the Company would not expect
to liquidate its entire debt portfolio in a one year holding
period.

Market Valuation

     The book value of cash and cash equivalents, accounts
receivable, short-term debt and accounts payable approximate fair
value because of the short-term maturity of these instruments.

     The book value amounts and fair values of the Company's
significant financial instruments at December 31, 1999 and 1998 are
summarized in the following table.  The fair values of long-term
debt and preferred stock are based on quoted market prices for the
same or similar issues and the current dividend or interest rates
offered for instruments of the same remaining maturities.  The fair
value of those financial instruments that are marked-to-market are
based on management's best estimates using over-the-counter
quotations, exchange prices, volatility factors and valuation
methodology.  The estimates presented herein are not necessarily
indicative of the amounts that the Company could realize in a
current market exchange.

                       Book Value  Fair Value
                           (in thousands)
Non-Derivatives

Long-term Debt
  1999                  $925,000   $  889,000

  1998                   959,800    1,011,600

Preferred Stock
  1999                    25,000       25,438

  1998                    25,000       25,900

<TABLE>
Derivatives
<CAPTION>
                      1999                             1998
                Notional   Fair     Average      Notional   Fair     Average
                 Amount    Value   Fair Value     Amount    Value   Fair Value
                                    (Dollars in thousands)
<S>               <C>     <C>        <C>          <C>      <C>        <C>
Trading Assets
                  GWH                              GWH
Electric
  NYMEX Futures
   and Options        40   $    312  $   159
  Physicals       12,503    103,794   91,570      10,161   $7,900     $ 7,100
  Options          1,116      7,369   11,140         673    5,500      13,500
  Swaps               32         70       56          48      600         200

Trading Liabilities

                  GWH                              GWH
Electric
  NYMEX Futures
   and Options      -          -        -            122   (1,200)       (300)
  Physicals       13,449     96,748   88,194      10,010   (8,600)     (8,000)
  Options          1,602      7,717   10,114         509   (4,900)    (12,600)
  Swaps               32         64       53          85   (1,300)       (300)

Credit and Risk Management

     In addition to market risk associated with electricity price
movements, the Company through the AEP Power Pool is also subject
to the credit risk inherent in its risk management activities.
Credit risk refers to the financial risk arising from commercial
transactions and/or the intrinsic financial value of contractual
agreements with trading counter parties, by which there exists a
potential risk of nonperformance.  The AEP Power Pool has
established and enforced credit policies that minimize this risk.
The AEP Power Pool accepts as counter parties to forwards, futures,
and other derivative contracts primarily those entities that are
classified as Investment Grade, or those that can be considered as
such due to the effective placement of credit enhancements and/or
collateral agreements.  Investment grade is the designation given
to the four highest debt rating categories (i.e., AAA, AA, A, BBB)
of the major rating services, e.g., ratings BBB- and above at
Standard & Poor's and Baa3 and above at Moody's. When adverse
market conditions have the potential to negatively affect a counter
party's credit position, the AEP Power Pool requires further credit
enhancements to mitigate risk.  Since the formation of the power
marketing and trading business in July of 1997, the Company has
experienced no significant losses due to the credit risk associated
with risk management activities; furthermore, the Company does not
anticipate any future material effect on its results of operations,
cash flow or financial condition as a result of counter party
nonperformance.
</TABLE>

12. COMMON OWNERSHIP OF GENERATING AND TRANSMISSION FACILITIES:

     The Company jointly owns, as tenants in common, four
generating units and transmission facilities with two unaffiliated
companies.  Each of the participating companies is obligated to pay
its share of the costs of any such jointly owned facilities in the
same proportion as its ownership interest.  The Company's
proportionate share of the operating costs associated with such
facilities is included in the Consolidated Statements of Income and
the investments are reflected in the accompanying Consolidated
Balance Sheets under utility plant as follows:
<TABLE>

<PAGE>
                                                                              Company's Share
<CAPTION>                                                                                December 31,

                                                               1999                        1998
                                                 Percent      Utility    Construction     Utility   Construction
                                                   of          Plant         Work          Plant         Work
                                                Ownership   in Service   in Progress    in Service   in Progress
                                                                               (in thousands)
<S>                                                <C>        <C>           <C>           <C>           <C>
Production:
  W.C. Beckjord Generating Station (Unit No. 6)    12.5       $ 13,919      $   390       $ 13,869      $  211
  Conesville Generating Station (Unit No. 4)       43.5         80,433           80         80,029       1,616
  J.M. Stuart Generating Station                   26.0        184,168        3,620        182,564       2,532
  Wm. H. Zimmer Generating Station                 25.4        701,054        6,030        699,704       3,978
                                                              $979,574      $10,120       $976,166      $8,337

Transmission                                        (a)        $60,333       $1,210        $59,668      $1,151

(a) Varying percentages of ownership.

     At December 31, 1999 and 1998, the accumulated depreciation with
respect to the Company's share of jointly owned facilities amounted
to $361.1 million and $331.9 million, respectively.

</TABLE>
<TABLE>
13. FEDERAL INCOME TAXES:
<CAPTION>
     The details of federal income taxes as reported are as follows:

                                                                         Year Ended December 31,
                                                              1999                  1998                  1997
                                                                               (in thousands)
<S>                                                          <C>                    <C>                 <C>
Charged (Credited) to Operating Expenses (net):
  Current                                                    $79,409                $62,120             $ 69,619
  Deferred                                                     9,737                 17,612                5,678
  Deferred Investment Tax Credits                             (3,432)                (3,498)              (3,577)
        Total                                                 85,714                 76,234               71,720
Charged (Credited) to Nonoperating Income (net):
  Current                                                     (3,210)                (3,795)                (941)
  Deferred                                                       744                   (511)                (428)
  Deferred Investment Tax Credits                               (562)                  (726)                (591)
        Total                                                 (3,028)                (5,032)              (1,960)

Total Federal Income Taxes as Reported                       $82,686                $71,202             $ 69,760

     The following is a reconciliation of the difference between the
amount of federal income taxes computed by multiplying book income
before federal income taxes by the statutory tax rate, and the amount
of federal income taxes reported.

                                                                        Year Ended December 31,
                                                               1999                  1998                 1997
                                                                                 (in thousands)

Net Income                                                   $150,270              $133,044            $119,379
Federal Income Taxes                                           82,686                71,202              69,760
Pre-tax Book Income                                          $232,956              $204,246            $189,139

Federal Income Taxes on Pre-tax Book Income at
  Statutory Rate (35%)                                        $81,535               $71,486             $66,199
Increase (Decrease) in Federal Income Taxes
  Resulting From the Following Items:
    Depreciation                                                8,846                 8,604               8,651
    Investment Tax Credits (net)                               (3,994)               (4,224)             (4,168)
    Other                                                      (3,701)               (4,664)               (922)
Total Federal Income Taxes as Reported                        $82,686               $71,202             $69,760

Effective Federal Income Tax Rate                                35.5%                 34.9%               36.9%
</TABLE>

<PAGE>
     The following tables show the elements of the net deferred tax
liability and the significant temporary differences giving rise to
such deferrals:
                                      December 31,
                                   1999         1998
                                    (in thousands)

Deferred Tax Assets             $  79,510    $  79,374
Deferred Tax Liabilities         (527,117)    (521,474)
  Net Deferred Tax Liabilities  $(447,607)   $(442,100)

Property Related Temporary
  Differences                   $(352,805)   $(346,483)
Amounts Due From Customers For
  Future Federal Income Taxes     (85,078)     (86,822)
All Other (net)                    (9,724)      (8,795)
  Net Deferred Tax Liabilities  $(447,607)   $(442,100)

     The Company and its subsidiaries join in the filing of a
consolidated federal income tax return with their affiliates in the
AEP System.  The allocation of the AEP System's current consolidated
federal income tax to the System companies is in accordance with SEC
rules under the 1935 Act.  These rules permit the allocation of the
benefit of current tax losses to the System companies giving rise to
them in determining their current tax expense.  The tax loss of the
System parent company, AEP Co., Inc., is allocated to its subsidiaries
with taxable income.  With the exception of the loss of the parent
company, the method of allocation approximates a separate return
result for each company in the consolidated group.

     The AEP System has settled with the IRS all issues from the
audits of the consolidated federal income tax returns for the years
prior to 1991.  Returns for the years 1991 through 1996 are presently
being audited by the IRS.  With the exception of interest deductions
related to AEP's corporate owned life insurance program, which is
discussed under the heading "Litigation" in Note 5, management is not
aware of any issues for open tax years that upon final resolution are
expected to have a material adverse effect on results of operations.


14. COMMON SHAREHOLDER'S EQUITY:

     In 1999, 1998 and 1997 net changes to paid-in capital of
$381,000, $380,000 and $(2,597,000), respectively, represented gains
and expenses associated with cumulative preferred stock transactions.
There were no other material transactions affecting the common stock
and paid-in capital accounts in 1999, 1998 and 1997.

<PAGE>
15.  CUMULATIVE PREFERRED STOCK:

     At December 31, 1999, authorized shares of cumulative preferred
stock were as follows:

                       Par Value                     Shares Authorized
                        $100                           2,500,000
                          25                           7,000,000

     The cumulative preferred stock outstanding is subject to
mandatory redemption and has an involuntary liquidation preference of
par value.  The Company redeemed 500,000 shares of the 7-7/8% Series
Cumulative Preferred Stock in 1997.
<TABLE>
<CAPTION>
            Call Price                                         Shares                             Amount
            December 31,               Par                   Outstanding                       December 31,
Series          1999                  Value                December 31, 1999               1999            1998
<C>              <S>                   <C>                      <C>                       <C>              <C>
                                                                                             (in thousands)
7%               (a)                   $100                      250,000                  $25,000          $25,000

(a) Commencing in 2000, a sinking fund will  require the redemption
of 50,000 shares at  $100 a share on or before August 1 of each year.
The Company has the right, on  each sinking fund date, to redeem an
additional 50,000 shares.  Redemption of this series is prohibited
prior to August 1, 2000.  The sinking fund provisions of the 7% series
aggregate $5,000,000, in 2000, 2001, 2002, 2003 and 2004.


16.  LONG-TERM DEBT AND LINES OF CREDIT:

     Long-term debt by major category was outstanding as follows:
                                     December 31,
                                 1999            1998
                                    (in thousands)
First Mortgage Bonds           $562,327       $597,847
Installment Purchase Contracts   91,112         91,058
Senior Unsecured Notes          159,212        159,105
Junior Debentures               111,894        111,776
  Total                        $924,545       $959,786

     First mortgage bonds outstanding were as follows:

                                    December 31,
                                1999           1998
                                  (in thousands)
% Rate  Due
7.25    2002 - October 1      $ 75,000       $ 75,000
7.15    2002 - November 1       20,000         20,000
6.80    2003 - May 1            50,000         50,000
6.60    2003 - August 1         40,000         40,000
6.10    2003 - November 1       20,000         20,000
6.55    2004 - March 1          50,000         50,000
6.75    2004 - May 1            50,000         50,000
8.70    2022 - July 1           35,000         35,000
8.40    2022 - August 1         15,000         15,000
8.55    2022 - August 1         15,000         15,000
8.40    2022 - August 15        25,500         25,500
8.40    2022 - October 15       15,000         15,000
7.90    2023 - May 1            50,000         50,000
7.75    2023 - August 1         33,000         40,000
7.45    2024 - March 1          30,000         50,000
7.60    2024 - May 1            41,000         50,000
Unamortized Discount            (2,173)        (2,653)
  Total                       $562,327       $597,847

     Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the
deposit of cash or bonds with the trustee, or in lieu thereof,
certification of unfunded property additions.

     Installment purchase contracts have been entered into in
connection with the issuance of pollution control revenue bonds by the
Ohio Air Quality Development Authority as follows:

                                      December 31,
                                  1999          1998
                                    (in thousands)
% Rate Due
6-3/8  2020 - December 1        $48,550      $48,550
6-1/4  2020 - December 1         43,695       43,695
Unamortized Discount             (1,133)      (1,187)
  Total                         $91,112      $91,058

     Under the terms of the installment purchase contracts, the
Company is required to pay amounts sufficient to enable the payment
of interest on and the principal of related pollution control revenue
bonds issued to finance the Company's share of construction of
pollution control facilities at the Zimmer Plant.

     Senior Unsecured Notes are composed of the following:

                                     December 31,
                                  1999          1998
                                    (in thousands)
% Rate Due
6.85   2005 - October 3         $ 48,000      $ 48,000
6.51   2008 - February 1          52,000        52,000
6.55   2008 - June 26             60,000        60,000
Unamortized Discount                (788)         (895)
  Total                         $159,212      $159,105

<PAGE>
     Junior debentures are composed of the following:

                                     December 31,
                                  1999          1998
                                    (in thousands)
% Rate Due
8-3/8  2025 - September 30      $ 75,000      $ 75,000
7.92   2027 - March 31            40,000        40,000
Unamortized Discount              (3,106)       (3,224)
  Total                         $111,894      $111,776

     Interest may be deferred and payment of principal and interest
on the junior debentures is subordinated and subject in right to the
prior payment in full of all senior indebtedness of the Company.

     At December 31, 1999 future annual long-term debt payments are
as follows:
                                       Amount
                                   (in thousands)

  2000                               $   -
  2001                                   -
  2002                                 95,000
  2003                                110,000
  2004                                100,000
  Later Years                         626,745
    Total Principal Amount            931,745
  Unamortized Discount                 (7,200)
      Total                          $924,545

     Short-term debt borrowings are limited by provisions of the 1935
Act to $350 million.  Lines of credit are shared with AEP System
companies  and  at  December 31, 1999 and 1998 were available in the
amounts of $1,056 million and $763 million, respectively.
The short-term bank lines of credit require the payment of facility
fees and donot require compensating balances.
Outstanding short-term debt consisted of:

                                          Year-end
                             Balance      Weighted
                          Outstanding     Average
                        (in thousands) Interest Rate

December 31, 1999:
  Commercial Paper          $45,500         6.5%

December 31, 1998:
  Commercial Paper          $52,500         6.4%


<PAGE>
17.  SUPPLEMENTARY INFORMATION:

                               Year Ended December 31,
                              1999      1998      1997
                                   (in thousands)
Cash was paid for:
  Interest (net of
    capitalized amounts)     $72,007   $73,917   $74,248
  Income Taxes                71,809    53,410    70,870

Noncash Acquisitions under
 Capital Leases                6,855    11,107     8,568


18.  LEASES:

     Leases of property, plant and equipment are for periods of up to
31 years and require payments of related property taxes, maintenance
and operating costs.  The majority of the leases have purchase or
renewal options and will be renewed or replaced by other leases.

     Lease rentals for both operating and capital leases are generally
charged to operating expenses in accordance with rate-making treat-
ment.  The components of rental costs are as follows:

                             Year Ended December 31,
                             1999      1998      1997
                                 (in thousands)

Operating Leases           $ 5,687   $ 8,107   $ 6,279
Amortization of Capital
 Leases                      7,427     6,530     6,675
Interest on Capital Leases   2,720     2,626     2,022
  Total Rental Costs       $15,834   $17,263   $14,976

     Properties under capital leases and related obligations recorded
on the Consolidated Balance Sheets are as follows:

                                                    December 31,
                                                   1999      1998
                                                   (in thousands)

 Electric Utility Plant Under Capital Leases      $60,469   $59,687
 Other Property Under Capital Leases                2,917     2,699
 Total Properties Under Capital Leases             63,386    62,386
 Accumulated Amortization                          23,116    20,024
 Net Properties Under Capital Leases              $40,270   $42,362

 Obligations Under Capital Leases*:
 Noncurrent Liability                             $33,031   $35,335
 Liability Due Within One Year                      7,239     7,027
 Total Capital Lease Obligations                  $40,270   $42,362

* Represents the present value of future minimum lease payments.

     Capital lease obligations are included in other noncurrent
liabilities and other current liabilities on the Consolidated Balance
Sheets.  Properties under operating leases and related obligations are
not included in the Consolidated Balance Sheets.

</TABLE>
<TABLE>
<CAPTION>
     Future minimum lease payments consisted of the following at
December 31, 1999:

                                                                                         Non-
                                                                                         cancelable
                                                                              Capital    Operating
                                                                              Leases     Leases
                                                                                (in thousands)
<S>                                                                           <C>        <C>
  2000                                                                        $ 9,777    $ 4,575
  2001                                                                          8,771      4,318
  2002                                                                          7,589        774
  2003                                                                          5,976        735
  2004                                                                          4,723        735
  Later Years                                                                  14,419      3,555
  Total Future Minimum Lease Payments                                          51,255    $14,692
  Less Estimated Interest Element                                              10,985
  Estimated Present Value of Future Minimum Lease Payments                    $40,270


19.  UNAUDITED QUARTERLY FINANCIAL INFORMATION:

Quarterly Periods  Operating   Operating      Net
     Ended          Revenues    Income      Income
                             (in thousands)
1999
 March 31           $279,067    $46,047    $27,418
 June 30             301,419     54,473     34,559
 September 30        368,946     83,478     63,719
 December 31         280,562     38,792     24,574

1998
 March 31           $266,399    $45,229    $25,645
 June 30             298,263     57,151     38,742
 September 30        361,405     74,263     52,291
 December 31         261,678     35,568     16,366



</TABLE>