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


                                                    Year Ended December 31,                 
                                 1998         1997         1996         1995         1994
                                                      (in thousands)
<S>                           <C>          <C>          <C>          <C>          <C>
INCOME STATEMENTS DATA:

  Operating Revenues          $1,187,745   $1,094,851   $1,105,683   $1,071,862   $1,031,151
  Operating Expenses             975,534      899,724      920,136      886,054      845,283
  Operating Income               212,211      195,127      185,547      185,808      185,868
  Nonoperating Income (Loss)      (1,343)       3,137         (970)       5,202        7,030
  Income Before Interest 
    Charges                      210,868      198,264      184,577      191,010      192,898
  Interest Charges (net)          77,824       78,885       77,469       80,394       83,053
  Net Income                     133,044      119,379      107,108      110,616      109,845
  Preferred Stock Dividend
    Requirements                   2,131        2,442        6,029       11,907       12,084
  Earnings Applicable
    to Common Stock           $  130,913   $  116,937   $  101,079   $   98,709   $   97,761



                                                        December 31,                        
                                 1998         1997         1996         1995         1994
BALANCE SHEETS DATA:                                  (in thousands)

  Electric Utility Plant      $3,053,565   $2,976,110   $2,899,893   $2,820,208   $2,729,577
  Accumulated Depreciation     1,134,348    1,074,588    1,016,909      953,170      884,237
  Net Electric Utility Plant  $1,919,217   $1,901,522   $1,882,984   $1,867,038   $1,845,340

  Total Assets                $2,681,690   $2,613,860   $2,541,586   $2,594,126   $2,594,342

  Common Stock and Paid-in
    Capital                   $  613,518   $  613,138   $  615,735   $  615,453   $  606,668
  Retained Earnings              186,441      138,172       99,582       74,320       46,976
  Total Common Shareholder's 
    Equity                    $  799,959   $  751,310   $  715,317   $  689,773   $  653,644

  Cumulative Preferred 
    Stock - Subject to
    Mandatory Redemption (a)  $   25,000   $   25,000   $   75,000   $   82,500   $  150,000

  Long-term Debt (a)          $  959,786   $  969,600   $  897,281   $  990,796   $  997,608

  Obligations Under Capital 
    Leases (a)                $   42,362   $   38,587   $   36,134   $   27,816   $   24,452

  Total Capitalization and 
    Liabilities               $2,681,690   $2,613,860   $2,541,586   $2,594,126   $2,594,342
</TABLE>
                      

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


Net Income Increases

   Net income increased 11% in 1998 primarily due to increased
energy sales to retail customers, growth in wholesale power
marketing and trading activities and increased transmission service
revenues.

Operating Revenues Increase

   Operating revenues increased $93 million or 8% in 1998
reflecting increased revenues from retail, wholesale and
transmission service customers as follows:

                                 Increase (Decrease)
(dollars in millions)            From Previous Year   
                                  Amount           %  
Retail:
  Residential                     $12.4   
  Commercial                       13.0  
  Industrial                        1.1
  Other                             1.0
                                   27.5           2.8

Wholesale                          48.4          49.8

Transmission                       12.1          77.0

Other                               4.9          52.2

  Total                           $92.9           8.5

   Retail energy sales increased 2% primarily due to increased
sales to residential and commercial customers reflecting warmer
summer weather and commercial customer growth.

   The Company as part of the American Electric Power (AEP) System
shares costs and benefits of the System's generating and
transmission facilities through the AEP System Power Pool (AEP
Power Pool).  The cost of the 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.
<PAGE>
   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 member load ratio (MLR) which determines each
Company's percentage share of revenues or costs.  During 1998 the
Company's MLR increased resulting in the Company being allocated a
larger share of certain revenues and expenses.

   In 1997 management decided to develop a power marketing and
trading business.  The power marketing and trading business is
conducted by the AEP Power Pool and its revenues and expenses are
allocated to AEP Power Pool members based on MLR.  During 1998 the
trading and marketing volume grew substantially.  Regulated trading
activities are recorded net of purchases.

   The 50% increase in wholesale revenues is attributable to the
Company's share of power marketing sales and trading to other
utilities and power marketers.  Power marketing sales are for the
sale to unaffiliated companies of electricity generated by the AEP
Power Pool or purchased from other unaffiliated companies.

   Transmission service revenues increased due to a substantial
rise in the quantity of energy transmitted for other entities over
the AEP System's transmission lines.  The issuance of open access
transmission rules by the Federal Energy Regulatory Commission
facilitated the growth in transmission services. The Company
receives its MLR share of transmission revenues from the AEP Power
Pool.  Transmission service is provided by the AEP System for a fee
and ownership of the electricity passes directly from seller to
purchaser.

Operating Expenses Increase

   Operating expenses increased $76 million or 8.4% in 1998 due
mainly to increased power purchases from unaffiliated entities. 
Changes in the components of operating expenses were as follows:
<PAGE>
                                   Increase (Decrease)
(dollars in millions)              From Previous Year   
                                    Amount           %  

Fuel                                $  8.9          5.0
Purchased Power                       61.4         34.8
Other Operation                       22.1         12.2
Maintenance                           (4.9)        (7.3)
Depreciation                           0.5          0.5
Amortization of Zimmer Plant
 Phase-in Costs                      (15.7)      (100.0)
Taxes Other Than Federal 
  Income Taxes                        (1.0)        (0.8)
Federal Income Taxes                   4.5          6.3
  Total                             $ 75.8          8.4

   Fuel expense increased 5% primarily due to an increase in
generation due to the unavailability to the AEP Power Pool of an
affiliate's nuclear plant and the increased demand for electricity.

   The Company's share of purchases of electricity by the AEP
Power Pool for resale to other utilities and power marketers and
increased capacity charges from 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 increase in other operation expense was attributable to
increased costs under the AEP System Transmission Equalization
Agreement, reflecting the increase in the Company's MLR, severance
accruals for reductions in power generation and energy delivery
staff, increased expenses for emission allowances and increased
costs related to management's decision to grow the power marketing
and trading business.  The AEP System Transmission Equalization
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.

   Maintenance expense decreased due to lower expenditures for
repairs and upkeep of generating and energy delivery facilities.

   The reduction in the amortization of deferred Zimmer Plant
phase-in costs reflects the completion in June 1997 of the
surcharge recovery plan and the amortization of the original
deferral.  The cessation of the amortization did not affect net
income since the amortization was being recovered in revenues
through a surcharge which terminated with the completion of the
amortization.





   Federal income taxes attributable to operations increased
primarily due to an increase in pre-tax operating income partially
offset by accrual adjustments related to prior year tax returns.

   The decline in nonoperating income is due to losses in 1998
from non-regulated electricity trading activities.  These trading
activities are for forward electricity sales and purchases outside
of the AEP Power Pool's traditional marketing area and include
electricity derivatives transactions such as options, swaps, etc. 
Open trades are marked-to-market and recorded in nonoperating
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 price risk.  Market risk represents
the risk of loss that may impact the Company due to adverse changes
in electricity commodity market prices and rates.  In 1998 the AEP 
Power Pool substantially increased the volume of its wholesale
power marketing and trading activities. Various policies and
procedures have been established to manage market risk exposures
including the use of a risk measurement model utilizing Value at
Risk (VaR).  Throughout the year ending December 31, 1998, the
Company's share of the highest, lowest and average quarterly VaR in
the wholesale trading portfolio was less than $2 million at a 95%
confidence level with a holding period of three business days.  The
AEP Power Pool used the variance-covariance method for calculating
VaR based on three months of daily prices.  Based on this VaR
analysis, at December 31, 1998 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 risk resulting from changes in
interest rates primarily due to short-term and long-term borrowings
to fund its business operations.  The debt portfolio has variable
and fixed interest rates with terms from one day to twenty-eight
years and an average duration of five years at December 31, 1998. 
The Company measures interest rate market risk exposure also
utilizing a VaR model.  The model is based on the Monte Carlo
method of simulated price movements with a 95% confidence level and
a one year holding period.  The volatilities and correlations were
based on three years of monthly 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 $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.  Also since the Company's rates
are cost-based regulated, the risk of interest rate changes on debt
used to finance regulated operations is mitigated.

<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, 1998 and 1997, and the related consolidated statements of
income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1998.  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, 1998 and 1997, and the results of their operations and their
cash flows for each of the three years in the period ended December
31, 1998 in conformity with generally accepted accounting
principles.


/s/ Deloitte & Touche LLP


DELOITTE & TOUCHE LLP
Columbus, Ohio
February 23, 1999
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME


                                                              Year Ended December 31,          
                                                       1998            1997            1996
                                                                  (in thousands)
<S>                                                 <C>             <C>             <C>
OPERATING REVENUES                                  $1,187,745      $1,094,851      $1,105,683

OPERATING EXPENSES:
  Fuel                                                 189,031         180,086         188,746 
  Purchased Power                                      237,688         176,311         168,894
  Other Operation                                      202,720         180,663         196,762
  Maintenance                                           62,095          66,956          65,414
  Depreciation                                          91,218          90,723          88,070
  Amortization of Zimmer Plant Phase-in Costs             -             15,746          33,937
  Taxes Other Than Federal Income Taxes                116,548         117,519         115,518
  Federal Income Taxes                                  76,234          71,720          62,795
      TOTAL OPERATING EXPENSES                         975,534         899,724         920,136 

OPERATING INCOME                                       212,211         195,127         185,547

NONOPERATING INCOME (LOSS)                              (1,343)          3,137            (970)

INCOME BEFORE INTEREST CHARGES                         210,868         198,264         184,577

INTEREST CHARGES                                        77,824          78,885          77,469

NET INCOME                                             133,044         119,379         107,108

PREFERRED STOCK DIVIDEND REQUIREMENTS                    2,131           2,442           6,029

EARNINGS APPLICABLE TO COMMON STOCK                 $  130,913      $  116,937      $  101,079
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY
CONSOLIDATED BALANCE SHEETS


                                                                         December 31,         
                                                                   1998                1997
                                                                        (in thousands)
ASSETS
<S>                                                            <C>                  <C>
ELECTRIC UTILITY PLANT:
  Production                                                   $ 1,521,611          $1,521,381 
  Transmission                                                     338,505             336,446
  Distribution                                                     936,613             926,178
  General                                                          138,359             138,041
  Construction Work in Progress                                    118,477              54,064
          Total Electric Utility Plant                           3,053,565           2,976,110
  Accumulated Depreciation                                       1,134,348           1,074,588

          NET ELECTRIC UTILITY PLANT                             1,919,217           1,901,522

OTHER PROPERTY AND INVESTMENTS                                      73,088              33,653 

CURRENT ASSETS:
  Cash and Cash Equivalents                                          7,206              12,626
  Accounts Receivable:
   Customers                                                        89,522              87,357
   Affiliated Companies                                             17,966              12,317
   Miscellaneous                                                    11,989              12,353
   Allowance for Uncollectible Accounts                             (2,598)             (1,058)
  Fuel - at average cost                                            22,140              19,549
  Materials and Supplies - at average cost                          33,263              27,628
  Accrued Utility Revenues                                          40,127              51,765
  Energy Marketing and Trading Contracts                            12,670                 418
  Prepayments                                                       29,084              29,561
          TOTAL CURRENT ASSETS                                     261,369             252,516 


REGULATORY ASSETS                                                  353,369             359,481

DEFERRED CHARGES                                                    74,647              66,688

           TOTAL                                               $ 2,681,690          $2,613,860
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY



                                                                         December 31,         
                                                                   1998                1997
                                                                        (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                                                 572,492             572,112 
  Retained Earnings                                               186,441             138,172
           Total Common Shareholder's Equity                      799,959             751,310 
  Cumulative Preferred Stock - Subject to Mandatory Redemption     25,000              25,000
  Long-term Debt                                                  959,786             887,850
           TOTAL CAPITALIZATION                                 1,784,745           1,664,160

OTHER NONCURRENT LIABILITIES                                       42,176              42,271

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                                 -                 81,750
  Short-term Debt                                                  52,500              66,600
  Accounts Payable - General                                       34,631              43,199
  Accounts Payable - Affiliated Companies                          37,132              28,088
  Taxes Accrued                                                   141,831             131,107
  Interest Accrued                                                 14,355              14,198
  Energy Marketing and Trading Contracts                           13,682                 353
  Other                                                            37,197              28,266
           TOTAL CURRENT LIABILITIES                              331,328             393,561

DEFERRED INCOME TAXES                                             442,100             433,593

DEFERRED INVESTMENT TAX CREDITS                                    48,710              52,934

DEFERRED CREDITS                                                   32,631              27,341

COMMITMENTS AND CONTINGENCIES (Note 3)

           TOTAL                                               $2,681,690          $2,613,860
/TABLE
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS


                                                                 Year Ended December 31,        
                                                            1998         1997            1996
                                                                    (in thousands)
<S>                                                      <C>          <C>            <C>
OPERATING ACTIVITIES:
  Net Income                                             $ 133,044    $ 119,379      $  107,108
  Adjustments for Noncash Items:
    Depreciation                                            91,426       90,959          87,697
    Deferred Federal Income Taxes                           17,101        5,250         (12,771)
    Deferred Investment Tax Credits                         (4,224)      (4,168)         (3,909)
    Deferred Fuel Costs (net)                              (11,311)      (6,115)          4,519
    Deferred Zimmer Plant Operating Expenses and
     Carrying Charges                                         -          16,097          32,152
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                               (5,910)     (47,966)          2,850
    Fuel, Materials and Supplies                            (8,226)      (4,900)          5,558
    Accrued Utility Revenues                                11,638      (19,939)          8,563
    Accounts Payable                                           476       16,459           2,799
  Payment of Disputed Tax and Interest
    Related to COLI                                        (37,243)        -               -
  Other (net)                                               29,776       (6,316)         24,522
          Net Cash Flows From Operating Activities         216,547      158,740         259,088

INVESTING ACTIVITIES:
  Construction Expenditures                               (114,979)    (108,931)        (92,667)
  Proceeds from Sale and Leaseback
    Transactions and Other                                   2,637        1,722           2,956
          Net Cash Flows Used For Investing Activities    (112,342)    (107,209)        (89,711)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt                               111,075       86,172            -
  Retirement of Preferred Stock                               -         (52,953)         (7,500)
  Retirement of Long-term Debt                            (122,206)     (14,640)        (99,053)
  Change in Short-term Debt (net)                          (14,100)      14,800          17,475
  Dividends Paid on Common Stock                           (82,644)     (78,684)        (75,876)
  Dividends Paid on Cumulative Preferred Stock              (1,750)      (2,734)         (5,866)
          Net Cash Flows Used For Financing Activities    (109,625)     (48,039)       (170,820)

Net Increase (Decrease) in Cash and Cash Equivalents        (5,420)       3,492          (1,443)
Cash and Cash Equivalents January 1                         12,626        9,134          10,577
Cash and Cash Equivalents December 31                    $   7,206    $  12,626       $   9,134
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS


                                                                  Year Ended December 31,      
                                                            1998          1997          1996
                                                                      (in thousands)
<S>                                                       <C>           <C>           <C>
Retained Earnings January 1                               $138,172      $ 99,582      $ 74,320
Net Income                                                 133,044       119,379       107,108
                                                           271,216       218,961       181,428
Deductions:
Cash Dividends Declared:
  Common Stock                                              82,644        78,684        75,876
  Cumulative Preferred Stock:
    7% Series                                                1,750         1,750         1,750
    7-7/8% Series                                             -             -            3,938
          Total Cash Dividends Declared                     84,394        80,434        81,564

Capital Stock Expense                                          381           355           282
          Total Deductions                                  84,775        80,789        81,846

Retained Earnings December 31                             $186,441      $138,172      $ 99,582
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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 640,000 retail customers in
its service territory in central and southern Ohio and does
business as American Electric Power (AEP).  The Company supplies
electric power to the AEP System Power Pool (AEP Power Pool) and
shares 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.  As a member of the AEP
Power Pool and a signatory company to 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'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 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 1998, 1997 and 1996 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
1998, 1997 and 1996 are as follows:

Functional Class               Annual Composite
of Property                   Depreciation Rates  
                            1998     1997     1996
Production                  3.2%     3.2%     3.2%
Transmission                2.3%     2.3%     2.3%
Distribution                3.7%     3.7%     3.7%
General                     3.6%     3.4%     3.5%

     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 the accrual of electricity consumed but
unbilled at month-end as well as billed revenues.  Changes in
retail jurisdictional fuel cost 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.

Derivative Financial Instruments

     During 1998, the AEP Power Pool substantially increased the
volume of its 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 and over-the-counter
options and swaps.  The majority of these transactions represent
physical forward contracts in the AEP System's traditional
marketing area and are typically settled by entering into
offsetting contracts.  The net revenues from these transactions 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.  These non-regulated
trading activities are included in nonoperating income and
accounted for on a mark-to-market basis.  The unrealized 
mark-to-market gains and losses from such non-regulated 
trading activity are reported as assets and liabilities, 
respectively.

     The Company enters into forward 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).  Any resultant gains or losses are deferred and
amortized over the life of the debt issuance.  There were no such
forward contracts outstanding at December 31, 1998 or 1997.

     See Note 6 - Financial Instruments, Credit and Risk Management
for further discussion.


Reclassification

     In the fourth quarter of 1998 the Company changed the
presentation of its trading activities from a gross basis
(purchases and sales reported separately) to a net basis (purchases
and sales are reported on a net basis as revenues).  This
reclassification had no impact on net income.  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, deferred income taxes
are recorded with related regulatory assets and liabilities 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.
<PAGE>
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. EFFECTS OF REGULATION AND THE ZIMMER PHASE-IN PLAN:

     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
these requirements, that is its rates were no longer cost based,
regulatory assets and liabilities would have to be written off for
that portion of the business and assets 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.

     Recognized regulatory assets and liabilities are comprised of
the following:
                                       December 31,   
                                     1998       1997
                                      (in thousands)
Regulatory Assets:
  Amounts Due From Customers For
    Future Income Taxes            $248,115   $256,710
  Deferred Zimmer Plant
    Carrying Charges                 42,841     43,003
  Unamortized Loss On
    Reacquired Debt                  26,537     29,173
  Other                              35,876     30,595
  Total Regulatory Assets          $353,369   $359,481

Regulatory Liabilities:
  Deferred Investment Tax Credits   $48,710    $52,934
  Other*                             26,052     21,537
  Total Regulatory Liabilities      $74,762    $74,471

* Included in Deferred Credits on the Consolidated Balance Sheets.

     At January 1, 1997 rate phase-in plan deferrals existed for
the Zimmer Plant, a 1,300 mw coal-fired plant that commenced
commercial operation in 1991.  CSPCo owns 25.4% of the plant with
the remainder owned by two unaffiliated companies.  As a result of
an Ohio Supreme Court decision, in January 1994 the PUCO approved
a temporary rate surcharge of 3.39% effective February 1, 1994 to
recover Zimmer Plant phase-in plan deferrals.  In June 1997 the
Company completed recovery of the phase-in plan deferrals and
discontinued the 3.39% temporary rate surcharge.  In 1997 and 1996
$15.4 million and $31.5 million, respectively, of net phase-in
deferrals were collected through the surcharge.  The collection and
cessation of the surcharge recovery of amounts deferred under the
phase-in plan did not affect net income.  The rate surcharge
terminated with the completion of the amortization of the phase-in
plan deferral.


3. COMMITMENTS AND CONTINGENCIES:

Construction and Other Commitments

     Substantial construction commitments have been made to support
the Company's utility operations.  Such commitments do not include
any expenditures for new generating capacity.  Construction
expenditures for 1999-2001 are estimated to be $336.7 million.

     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 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.

Air Quality

     On September 24, 1998, United States (US) Environmental
Protection Agency (Federal EPA) finalized rules which require
reductions in nitrogen oxides (NOx) emissions in 22 eastern states,
including Ohio and the other states in which generating plants of
the Company and its affiliates in the AEP System are located.  The
implementation of the final rules would be achieved through the
revision of state implementation plans (SIPs) by September 1999. 
SIPs are a procedural method used by each state to comply with
Federal EPA rules.  The final rules anticipate the imposition of a
NOx reduction on utility sources of approximately 85% below 1990
emission levels by the year 2003.  On October 30, 1998, a number of
utilities, including the Company and the other operating companies
of the AEP System, filed petitions in the US Court of Appeals for
the District of Columbia Circuit seeking a review of the final
rules.

     Should the states fail to adopt the required revisions to
their SIPs within one year of the date of the final rules
(September 24, 1999), Federal EPA has proposed to implement a
federal plan to accomplish the NOx reductions.  Federal EPA also
proposed the approval of portions of petitions filed by eight
northeastern states that would result in imposition of NOx emission
reductions on utility and industrial sources in upwind midwestern
states.  These reductions are substantially the same as those
required by the final NOx rules and could be adopted by Federal EPA
in the event the states fail to implement SIPs in accordance with
the final rules.

     Preliminary estimates indicate that compliance could result in
required capital expenditures of approximately $140 million for the
Company.  Compliance costs cannot be estimated with certainty and
the actual costs incurred to comply could be significantly
different from this preliminary estimate depending upon the
compliance alternatives selected to achieve reductions in NOx
emissions.  Unless such costs are recovered from customers, they
would have a material adverse effect on results of operations, cash
flows and possibly financial condition.

Litigation

     The Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns for the years 1991
to 1993 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 by the Company in US 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,
1998 would reduce earnings by approximately $43 million (including
interest).  The Company has made no provision for any possible
adverse earnings impact from this matter.

     In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years 1991-97
to avoid the potential assessment by the IRS of any additional
above market rate interest on the contested amount.  These payments 
to the IRS are included on the balance sheet in other property and
investments pending the resolution of this matter.  The Company
will seek refund, either administratively or through litigation, of
all amounts paid plus interest.  In order to resolve this issue
without further delay, on March 24, 1998, the Company filed suit
against the US in the US District Court for the Southern District
of Ohio.  Management believes that it has a meritorious position
and will vigorously pursue this lawsuit.  In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations and cash flows.

     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.


4. 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 $20.1 million in 1998, $18.6
million in 1997 and $15.4 million in 1996 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,    
                          1998       1997       1996
                                 (in thousands)

Capacity Charges        $ 98,042   $ 82,536   $ 83,723
Energy Charges            69,577     74,416     76,758

     Total              $167,619   $156,952   $160,481

     Power marketing and trading operations, which are described in
Note 1, are conducted by the AEP Power Pool and shared with the
Company.  The Company's operating revenues, purchased power expense
and nonoperating income include amounts for power marketing and
trading allocated by the AEP Power Pool as follows:
<PAGE>
                             Year Ended December 31,  
                            1998       1997      1996
                                  (in thousands)
Operating Revenues        $109,963   $63,635   $63,642
Purchased Power Expense     62,728    13,209     7,064
Nonoperating Loss           (6,335)      (44)     -

     Purchased power expense includes $5.9 million in 1998, $6.1
million in 1997 and $1.3 million in 1996 for energy bought from the
Ohio Valley Electric Corporation, an affiliated company that is not
a member of the AEP Power Pool.

     AEP System electric operating utility companies including the
Company participate in the AEP Transmission Equalization Agreement. 
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 $35.6 million, $29.9 million and $30.6 million in 1998,
1997 and 1996, 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 clients on a direct-charge basis
whenever possible and on reasonable bases of proration for shared
services.  The billing 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.


5. 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
4.  For the years ended December 31, 1998, 1997 and 1996, all of
the Company's revenues are derived from the generation, sale and
delivery of electricity in the US.


6. 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
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 year ended December 31, 1998 was $19 million. 
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.  The Company's share of the net losses from
these non-regulated trading transactions for the year ended
December 31, 1998 was $6 million.  The unrealized mark-to-market
gains and losses from such 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 five years at December 31, 1998.  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.  Also since the Company's rates are cost-based regulated,
the risk of interest rate changes on debt used to finance regulated
operations is mitigated.

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, 1998 and 1997 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.  At December 31, 1997 the notional amounts
and fair values of derivatives were not material.

                       Book Value  Fair Value
                           (in thousands)
Non-Derivatives

1998

Long-term Debt          $959,800   $1,011,600

Preferred Stock           25,000       25,900

1997

Long-term Debt           969,600    1,014,000

Preferred Stock           25,000       26,700

Derivatives

1998
                                 Fair Value  Average Fair Value
                                        (in thousands)

Trading Assets

Electric
  Physicals                       $ 7,900        $ 7,100
  Options                           5,500         13,500
  Swaps                               600            200

Trading Liabilities

Electric
  Futures                          (1,200)          (300)
  Physicals                        (8,600)        (8,000)
  Options                          (4,900)       (12,600)
  Swaps                            (1,300)          (300)

     At December 31, 1998 the notional amounts of the Company's
nonregulated electric trading physical forward contract purchases
and sales are 1,750 Gigawatt hours (Gwh) and 1,872 Gwh,
respectively; the notional amounts for fixed priced swaps purchases
and sales are 64 Gwh and 69 Gwh, respectively; and the notional
amounts for options to purchase and to sell are 1,264 Gwh and 908
Gwh, respectively.  The Company has a net long position of 67 Gwh
for electric future contracts.

     At December 31, 1998 the fair value of the assets and
liabilities related to the wholesale electric forward contracts was
$64 million and $62 million, respectively.  The related notional
amounts were 8,327 Gwh for purchases and 8,498 Gwh for sales.  The
average fair value amounts outstanding during the period were $160
million of assets and $153 million of liabilities.

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.


7. 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.


8. 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 costs (credits) for the years ended
December 31, 1998 and 1996 were $(1.4) million and $1.5 million,
respectively.  There was no pension costs 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 $7.5 million in 1998
and 1997 and $13.6 million in 1996.

     A defined contribution employee savings plan required that the
Company make contributions to the plan totaling $1.8 million in
1998 and $1.9 million in 1997 and 1996.


9. 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 amounts reflected in the accompanying Consolidated Balance
Sheets under utility plant include such costs as follows:
<TABLE>
<CAPTION>
                                                                              Company's Share                   
                                                                                December 31,                    
                                                                      1998                        1997           
                                                 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       $ 13,869      $  211        $ 13,774      $  272
  Conesville Generating Station (Unit No. 4)       43.5         80,029       1,616          80,030          53
  J.M. Stuart Generating Station                   26.0        182,564       2,532         183,164         624
  Wm. H. Zimmer Generating Station                 25.4        699,704       3,978         699,512       2,708
                                                              $976,166      $8,337        $976,480      $3,657

Transmission                                        (a)        $59,668      $1,151         $59,345      $  300

(a) Varying percentages of ownership.

     At December 31, 1998 and 1997, the accumulated depreciation with
respect to the Company's share of jointly owned facilities amounted
to $331.9 million and $301.2 million, respectively.
</TABLE>
<TABLE>
<PAGE>
10. FEDERAL INCOME TAXES:
<CAPTION>
     The details of federal income taxes as reported are as follows:

                                                                         Year Ended December 31,                
                                                              1998                  1997                  1996
                                                                               (in thousands)
<S>                                                          <C>                   <C>                  <C>
Charged (Credited) to Operating Expenses (net):
  Current                                                    $62,120               $ 69,619             $ 78,262
  Deferred                                                    17,612                  5,678              (11,842)
  Deferred Investment Tax Credits                             (3,498)                (3,577)              (3,625)
        Total                                                 76,234                 71,720               62,795
Charged (Credited) to Nonoperating Income (net):
  Current                                                     (3,795)                  (941)              (1,280)
  Deferred                                                      (511)                  (428)                (929)
  Deferred Investment Tax Credits                               (726)                  (591)                (284)
        Total                                                 (5,032)                (1,960)              (2,493)

Total Federal Income Taxes as Reported                       $71,202               $ 69,760             $ 60,302

     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,                
                                                               1998                  1997                 1996
                                                                                 (in thousands)

Net Income                                                   $133,044              $119,379            $107,108
Federal Income Taxes                                           71,202                69,760              60,302
Pre-tax Book Income                                          $204,246              $189,139            $167,410

Federal Income Taxes on Pre-tax Book Income at 
  Statutory Rate (35%)                                        $71,486               $66,199             $58,594
Increase (Decrease) in Federal Income Taxes
  Resulting From the Following Items:
    Depreciation                                                8,604                 8,651               7,861
    Investment Tax Credits (net)                               (4,224)               (4,168)             (3,909)
    Other                                                      (4,664)                 (922)             (2,244)
Total Federal Income Taxes as Reported                        $71,202               $69,760             $60,302

Effective Federal Income Tax Rate                                34.9%                 36.9%               36.0%

</TABLE>
     The following tables show the elements of the net deferred tax
liability and the significant temporary differences giving rise to
such deferrals:
                                      December 31,     
                                   1998         1997
                                    (in thousands)

Deferred Tax Assets             $  79,374    $  79,047
Deferred Tax Liabilities         (521,474)    (512,640)
  Net Deferred Tax Liabilities  $(442,100)   $(433,593)

Property Related Temporary
  Differences                   $(346,483)   $(341,701)
Amounts Due From Customers For
  Future Federal Income Taxes     (86,822)     (89,824)
All Other (net)                    (8,795)      (2,068)
  Net Deferred Tax Liabilities  $(442,100)   $(433,593)

     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 the deductibility of
interest deductions related to AEP's corporate owned life insurance
program, which is discussed under the heading, Litigation, in Note 3,
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.


11. COMMON SHAREHOLDER'S EQUITY:

     In 1998, 1997 and 1996 net changes to paid-in capital of
$380,000, $(2,597,000) and $282,000, 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 1998, 1997 and 1996.


12.  CUMULATIVE PREFERRED STOCK:

     At December 31, 1998, 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 and 75,000 shares of 9.50% Series
Cumulative Preferred Stock in 1996.

        Call Price             Shares                   Amount         
        December 31,  Par   Outstanding              December 31,      
Series     1998      Value December 31, 1998    1998            1997     
                       
                                                  (in thousands)
7%          (a)      $100     250,000         $25,000          $25,000

<PAGE>
(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 and 2003.


13.  LONG-TERM DEBT AND LINES OF CREDIT:

     Long-term debt by major category was outstanding as follows:
                                     December 31,     
                                 1998            1997  
                                    (in thousands)      
First Mortgage Bonds           $597,847       $719,218
Installment Purchase Contracts   91,058         91,003
Senior Unsecured Notes          159,105         47,721
Junior Debentures               111,776        111,658
                                959,786        969,600
Less Portion Due Within 
  One Year                         -            81,750
  Total                        $959,786       $887,850

     First mortgage bonds outstanding were as follows:
                                    December 31,      
                                1998           1997   
                                  (in thousands)      
% Rate  Due                
9.15    1998 - February 2     $   -          $ 57,000 
7.00    1998 - June 1             -            24,750 
7.95    2002 - July 1             -            40,000 
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         40,000         40,000 
7.45    2024 - March 1          50,000         50,000 
7.60    2024 - May 1            50,000         50,000 
Unamortized Discount            (2,653)        (3,032)
                               597,847        719,218 
Less Portion Due Within 
  One Year                        -            81,750 
  Total                       $597,847       $637,468 

     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,     
                                  1998          1997
                                    (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             (1,187)      (1,242)
  Total                         $91,058      $91,003

     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,      
                                  1998          1997
                                    (in thousands)
% Rate Due                   
6.85   2005 - October 3         $ 48,000      $48,000
6.51   2008 - February 1          52,000         -   
6.55   2008 - June 26             60,000         -
Unamortized Discount                (895)        (279)
  Total                         $159,105      $47,721

     Junior debentures are composed of the following:

                                     December 31,      
                                  1998          1997
                                    (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              (3,224)       (3,342)
  Total                         $111,776      $111,658

     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.

<PAGE>
     At December 31, 1998 future annual long-term debt payments are
as follows:
                                       Amount
                                   (in thousands) 

  1999                               $   -
  2000                                   -
  2001                                   -
  2002                                 95,000
  2003                                110,000
  Later Years                         762,745
    Total Principal Amount            967,745
  Unamortized Discount                 (7,959)
      Total                          $959,786

     Short-term debt borrowings are limited by provisions of the 1935
Act to $300 million.  Lines of credit are shared with AEP System
companies  and  at  December 31, 1998 and 1997 were available in the
amounts of $763 million and $442 million, respectively.  Facility fees
of approximately 1/10 of 1% of the short-term lines of credit are
required to maintain the lines of credit.  Outstanding short-term debt
consisted of:
                                          Year-end
                             Balance      Weighted
                          Outstanding     Average
                        (in thousands) Interest Rate

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

December 31, 1997:
  Notes Payable             $ 4,300         5.8%
  Commercial Paper           62,300         6.7
    Total                   $66,600         6.7


14.  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.

<PAGE>
     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,  
                             1998      1997      1996
                                 (in thousands)

Operating Leases           $ 8,107   $ 6,279   $ 7,544
Amortization of Capital
 Leases                      6,530     6,675     5,169 
Interest on Capital Leases   2,626     2,022     2,094 
  Total Rental Costs       $17,263   $14,976   $14,807 

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

                                                    December 31,   
                                                   1998      1997
                                                   (in thousands)

 Electric Utility Plant Under Capital Leases      $59,687   $53,537
 Other Property Under Capital Leases                2,699     2,511
 Total Properties Under Capital Leases             62,386    56,048
 Accumulated Amortization                          20,024    17,461
 Net Properties Under Capital Leases              $42,362   $38,587

 Obligations Under Capital Leases*:
 Noncurrent Liability                             $35,335   $32,649
 Liability Due Within One Year                      7,027     5,938
 Total Capital Lease Obligations                  $42,362   $38,587

* 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.

     Future minimum lease payments consisted of the following at
December 31, 1998:

                                               
  
                                               Non-   
                                               cancelable
                                    Capital    Operating
                                      Leases     Leases  
                                         (in thousands)

  1999                               $ 9,692    $ 4,739
  2000                                 8,878      4,596
  2001                                 7,788      4,425
  2002                                 6,678        939
  2003                                 5,102        939
  Later Years                         16,268      5,087
  Total Future 
    Minimum Lease Payments            54,406    $20,725
  Less Estimated Interest Element     12,044
  Estimated Present Value of 
   Future Minimum Lease Payments     $42,362



15.  SUPPLEMENTARY INFORMATION:

                               Year Ended December 31,  
                              1998      1997      1996
                                   (in thousands)
Cash was paid for:
  Interest (net of
    capitalized amounts)     $73,917   $74,248   $77,021
  Income Taxes                53,410    70,870    76,298

Noncash Acquisitions under
 Capital Leases               11,107     8,568    14,247


16.  UNAUDITED QUARTERLY FINANCIAL INFORMATION:

Quarterly Periods  Operating   Operating      Net
     Ended          Revenues    Income      Income
                             (in thousands)
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

1997
 March 31            265,007     47,430     29,324
 June 30             263,263     42,968     23,430
 September 30        300,806     64,895     45,488
 December 31         265,775     39,834     21,137 

Fourth quarter 1998 net income declined primarily as a result of
unseasonably mild weather.

See "Reclassification" section in Note 1 regarding reclassification
of prior period amounts.