<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
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            $1,672,244   $1,628,515   $1,624,869   $1,545,039   $1,535,500
  Operating Expenses             1,443,701    1,388,521    1,381,993    1,317,937    1,330,282
  Operating Income                 228,543      239,994      242,876      227,102      205,218
  Nonoperating Income (Loss)        (8,301)        (222)         128       (4,699)      (4,716)
  Income Before Interest Charges   220,242      239,772      243,004      222,403      200,502
  Interest Charges                 126,912      119,258      109,315      106,503       98,157
  Net Income                        93,330      120,514      133,689      115,900      102,345
  Preferred Stock Dividend
    Requirements                     2,497        7,006       15,938       16,405       15,660
  Earnings Applicable to
    Common Stock                $   90,833   $  113,508   $  117,751   $   99,495   $   86,685



                                                     Year Ended December 31,
                                   1998         1997         1996         1995         1994
                                                         (in thousands)

BALANCE SHEETS DATA:

  Electric Utility Plant        $5,087,359   $4,901,046   $4,717,132   $4,558,436   $4,398,727
  Accumulated Depreciation and
     Amortization                1,984,856    1,869,057    1,782,017    1,694,746    1,627,852
  Net Electric Utility Plant    $3,102,503   $3,031,989   $2,935,115   $2,863,690   $2,770,875
  Total Assets                  $4,047,038   $3,883,430   $3,800,737   $3,723,975   $3,635,632

  Common Stock and
    Paid-in Capital             $  924,091   $  873,506   $  835,838   $  785,509   $  764,866
  Retained Earnings                179,461      207,544      208,472      199,021      206,361
  Total Common Shareholder's
    Equity                      $1,103,552   $1,081,050   $1,044,310   $  984,530   $  971,227

  Cumulative Preferred Stock:
    Not Subject to Mandatory
      Redemption                $   19,359   $   19,747   $   29,815   $   55,000   $   55,000
    Subject to Mandatory
      Redemption (a)                22,310       22,310      190,000      190,235      190,385
        Total Cumulative
          Preferred Stock       $   41,669   $   42,057   $  219,815   $  245,235   $  245,385

  Long-term Debt (a)            $1,552,455   $1,494,535   $1,365,842   $1,285,684   $1,228,911

  Obligations Under Capital
    Leases (a)                  $   65,175   $   60,110   $   51,969   $   48,937   $   43,138

  Total Capitalization and
    Liabilities                 $4,047,038   $3,883,430   $3,800,737   $3,723,975   $3,635,632


(a) Including portion due within one year.
</TABLE>


<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION


     This discussion includes forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934.
These forward-looking statements reflect assumptions, and involve
a number of risks and uncertainties.  Among the factors that could
cause actual results to differ materially from forward looking
statements are: electric load and customer growth; abnormal weather
conditions; available sources and costs of fuels; availability of
generating capacity; the speed and degree to which competition is
introduced to our power generation business, the structure and
timing of a competitive market and its impact on energy prices or
fixed rates; the ability to recover stranded costs in connection
with deregulation of generation, new legislation and government
regulations; the ability of the Company to successfully control its
costs; the economic climate and growth in our service territory;
unforeseen problems or failures related to Year 2000 readiness of
computer software and hardware; inflationary trends; electricity
market prices; interest rates; and other risks and unforeseen
events.  This discussion contains a "Year 2000 Readiness
Disclosure" within the meaning of the Year 2000 Information and
Readiness Disclosure Act.

     Appalachian Power Company (the 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 888,000 retail customers in southwestern Virginia
and southern West Virginia 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.

Results of Operations

Net Income

     Although operating revenues increased in 1998, net income
declined $27.2 million or 23% due primarily to increased fuel and
maintenance expenses, losses on certain non-regulated electricity
trading activities outside of the AEP Power Pool's traditional
marketing area, increased interest charges and provisions for
revenue refunds.  The $13.2 million or 10% decline in 1997 was
primarily due to increased interest charges reflecting additional
amounts of long-term debt outstanding.
<PAGE>
Operating Revenues Increase

     Operating revenues increased 3% in 1998 primarily due to
increased revenues from trading and transmission services.  In 1997
revenues were relatively unchanged.  The changes in the components
of revenues are as follows:
                                      Increase (Decrease)
                                      From Previous Year
(Dollars in Millions)                  1998           1997
                                  Amount    %    Amount     %
Retail:
   Residential                    $(5.1)         $ (8.4)
   Commercial                       2.3            (2.8)
   Industrial                      (0.3)           13.6
   Other                            2.2             0.2
                                   (0.9)  (0.1)     2.6    0.2

Wholesale                          30.7    9.6    (13.5)  (4.1)

Transmission                       19.3   69.9      6.5   30.9

Miscellaneous                      (5.4) (25.5)     8.0   59.6

     Total                        $43.7    2.7   $  3.6    0.2

     The Company as part of the AEP System shares the benefits and
costs of the System's generation through the 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.

     The AEP Power Pool calculates each Company's prior twelve
month peak demand relative to the total peak demand of all member
companies as a basis for sharing revenues and costs.  The result of
this calculation is each Company's member load ratio (MLR) which
determines each Company's percentage share of revenues or costs.
During 1998 the Company's MLR decreased resulting in the Company
being allocated a smaller share of wholesale revenues and expenses
from the AEP Power Pool.

     In 1997 management decided to develop a power marketing and
trading business.  The power marketing and trading business is
conducted by American Electric Power Service Corporation as agent
for the AEP Power Pool and its revenues and expenses are allocated
to AEP Power Pool members based on MLR.

     The volume of the power marketing and trading business grew
substantially during 1998 and accounted for the increase in
wholesale revenues which reflects the Company's share of net
revenues from electricity trading with other utilities and power
marketers.  Trading revenues are recorded net of purchases.
Wholesale revenues decreased in 1997 primarily due to a decline in
energy sales to the AEP Power Pool reflecting the AEP Power Pool's
reduced need for energy as energy sales to unaffiliated entities
declined.

     Transmission service revenues increased due to a substantial
rise in the volume 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
(FERC) facilitated the growth in transmission services. The Company
receives its MLR share of transmission revenues.

     In 1998 miscellaneous revenues declined due to the recordation
of provisions for revenue refunds under final rate orders.  The
increase in miscellaneous operating revenues in 1997 was due to the
favorable effect of a provision recorded in 1996 for the completion
of rate refunds under a settlement in the Virginia jurisdiction.

Operating Expenses Increase

     Operating expenses increased 4% in 1998 and less than one
percent in 1997.  The increase in 1998 is mainly due to increased
fuel and maintenance costs.  Changes in the components of operating
expenses are as follows:
                               Increase (Decrease)
                               From Previous Year
(dollars in millions)        1998             1997
                       Amount      %    Amount     %

Fuel                   $33.7      8.4   $ 36.1    9.8
Purchased Power         (8.4)    (2.7)   (21.5)  (6.5)
Other Operation          7.9      3.2      6.5    2.7
Maintenance             22.0     19.5     (4.6)  (3.9)
Depreciation and
  Amortization           6.1      4.5      4.6    3.5
Taxes Other Than
  Federal Income Taxes  (0.5)    (0.4)    (3.7)  (3.1)
Federal Income Taxes    (5.6)    (9.6)   (10.9) (15.5)
  Total                $55.2      4.0   $  6.5    0.5

     The increase in fuel expense in 1998 is primarily due to an
increase in generation.  Fuel expense increased 10% in 1997
primarily due to increased generation and the operation of the West
Virginia power supply cost recovery mechanism which requires that
overcollections of fuel costs be deferred for future refund to
customers through a charge to fuel expense.  The level of
generation increased primarily in the fourth quarter of 1997 when
both units of the affiliate's nuclear plant were unavailable.

     The reduction in purchased power expense was due to reduced
capacity charges from the AEP Power Pool as a result of the
decrease in the Company's MLR and decreased purchases from the AEP
Power Pool.  The decline in purchased power expense in 1997 was
mainly due to decreased purchases from the AEP Power Pool.

     Maintenance expense increased in 1998 primarily as a result of
expenditures to restore service and make repairs following two
severe snow storms and to clear and maintain right-of-ways.

     Federal income taxes attributable to operations decreased in
both years primarily due to a decline in pre-tax operating income.

Nonoperating Income

     Nonoperating income declined in 1998 primarily due to losses
from forward electricity sales and purchases outside of the AEP
Power Pool's traditional marketing area and electricity derivatives
such as options, swaps, etc.  Open non-regulated trades are
marked-to-market and recorded in nonoperating income.

Interest Charges and Preferred Stock Dividends

     The increase in interest charges in 1998 is primarily due to
increased long-term borrowings and the accrual of interest to be
paid to customers under rate refund orders.

     Interest charges increased in 1997 primarily as a result of an
increase in the balance of long-term debt outstanding to replace
preferred stock.  Preferred stock dividend requirements decreased
significantly due to a decrease in the number of shares outstanding
reflecting the reacquisition of 1.3 million shares in the first
quarter of 1997 as part of a tender offer and the redemption of the
remaining 477,500 outstanding shares of the 7.80% series in April
1997.

Business Outlook

     The most significant factor affecting the Company's future
earnings is its ability to recover its costs as the electric
generating business becomes more competitive.  Although the FERC
instituted open transmission access and competition in the
wholesale market in 1996, the introduction of competition and
customer choice for retail customers has been slow and continues at
a deliberate pace as legislators and regulatory officials recognize
the complexity of the issues.  Federal legislation has been
proposed to mandate competition and customer choice at the retail
level.  The Company's retail operations are in West Virginia and
Virginia.  West Virginia is currently considering initiatives to
move to customer choice, although the timing is uncertain.

     In February 1999 the Virginia legislature passed comprehensive
legislation, which will become law upon the Governor's signature,
to restructure the electric utility industry and taxes applicable
to electric utility services.  Under the restructuring bill a
transition to choice of supplier for retail customers will commence
on January 1, 2002 and be completed, subject to a finding by the
State Corporation Commission (SCC) that an effective competitive
market exists, on January 1, 2004.  Provisions allowing for an
acceleration or limited delay in this schedule are also contained
in the bill.  Except as provided in the legislation, the generation
of electricity will not be subject to rate regulation after January
1, 2002.  Additionally, each Virginia electric utility is required
by 2001 to join or establish a regional transmission entity which
will manage and control transmission assets.

     The Virginia restructuring bill also provides an opportunity
for recovery of just and reasonable net stranded costs.  Stranded
costs are those costs above market that potentially would not be
recoverable in a competitive market.  The mechanisms in the
Virginia legislation for stranded cost recovery are dual: a capping
of incumbent utility rates until as late as July 1, 2007, and the
application of a wires charge upon customers who may depart the
incumbent utility in favor of an alternative supplier prior to the
termination of the rate cap.  The legislation provides for the
establishment of capped rates prior to January 1, 2001. The capped
rates may be terminated after January 1, 2004, and prior to July 1,
2007, based upon the SCC determining that an effective competitive
market exists.  The wires charge will be equal to the difference
between the generation component of the capped rates and the market
price for generation service and will be imposed upon departing
customers through the expiration of the rate cap period.

     Related tax legislation, which is intended to be revenue
neutral, provides for replacement of the gross receipts and certain
other taxes on electric utilities with a consumption tax levied
upon customers on the basis of kilowatt-hour usage, and a state
corporate net income tax.

     Under the provisions of Statement of Financial Accounting
Standards (SFAS) 71 "Accounting for the Effects of Certain Types of
Regulation," regulatory assets (deferred expenses) and regulatory
liabilities (deferred revenues) are included in the consolidated
balance sheets of regulated utilities in accordance with regulatory
actions to match expenses and revenues with cost-based rates in the
same accounting period.  In order to maintain net regulatory assets
on the balance sheet, SFAS 71 requires that rates charged to
customers be cost-based and the recovery of regulatory assets must
be probable.  In the event a portion of the Company's business no
longer meets the requirements of SFAS 71, SFAS 101 "Accounting for
the Discontinuance of Application of Statement 71" requires that
net regulatory assets be written off for that portion of the
business.  The provisions of SFAS 71 and SFAS 101 never anticipated
that deregulation would include an extended transition period or
that it would provide for recovery of stranded costs during and
after a transition period.  In July 1997 the Financial Accounting
Standards Board's (FASB) Emerging Issues Task Force (EITF)
addressed such a situation with the consensus reached on issue 97-4
that the application of SFAS 71 to a segment of a regulated
electric utility cease when that segment is subject to a
legislatively approved plan for competition or an enabling rate
order is issued containing sufficient detail for the utility to
reasonably determine what the plan would entail.  The EITF
indicated that the cessation of application of SFAS 71 would
require that regulatory assets and impaired plant be written off
unless they are probable of recovery in future regulated rates.

     The Company's firm wholesale sales are a relatively small part
of our business and are still under cost-of-service contracts.  Our
Virginia rates for generation will continue to be cost-based
regulated until the establishment of capped rates.  Until the
capped rates are determined the Company does not have sufficient
detail to reasonably determine what the legislature's approved plan
for competition will entail.  In West Virginia retail rates
continue to be based upon cost-of-service.  Consequently, as of
December 31, 1998 the Company's generation business is still
cost-based regulated.

     When capped rates are established in Virginia the application
of SFAS 71 would be discontinued for the Virginia retail
jurisdiction portion of the generating business, generation-related
regulatory assets applicable to the Virginia jurisdiction will have
to be written off to the extent that they cannot be recovered under
the provisions of the restructuring legislation and generating
assets for the Virginia retail jurisdiction will have to be
evaluated for impairment.  Based upon initial reviews the amount of
regulatory assets applicable to the Virginia generating business at
December 31, 1998 is estimated to be $64 million before related tax
effects and any possible offsetting regulatory liabilities.
Regulatory liabilities applicable to the Virginia generation
business at December 31, 1998 are estimated to be $39 million of
which $26 million represents deferred investment tax credits.  The
Company is evaluating the tax normalization rules regarding the
timing of the reversal of deferred investment tax credits in
connection with the Virginia restructuring legislation.  Should it
not be possible under the Virginia legislation to recover any
portion of the generation net regulatory  assets, it could have a
material adverse impact on results of operations; however, the
amount of any impairment loss for Virginia retail jurisdictional
generating assets and any loss from a possible inability to recover
net generation regulatory assets cannot be estimated until such
time as capped rates are determined under the legislation.

     In the event West Virginia were to provide some form of retail
competition such that the Company's West Virginia jurisdiction was
no longer cost-based regulated for generation, and if it were not
possible to demonstrate probability of recovery of resultant
stranded costs including net regulatory assets during the
transition period or from regulated distribution rates, then
results of operations, cash flows and financial condition would be
adversely affected.  At the current time the timing and status of
initiatives to move to customer choice in West Virginia is
uncertain and the Company is in no position to determine whether it
will incur a loss if and when West Virginia adopts restructuring.

Litigation

Corporate Owned Life Insurance

     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 a corporate
owned life insurance (COLI) program should not be allowed.  As a
result of a suit filed by the Company in United States 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 $79 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.  The 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 United States in the United States 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 we are unable to predict the outcome of such
litigation, it is not expected that the ultimate resolution of
these matters will have a material adverse effect on the results of
operations, cash flows and/or financial condition.

Cost Containment and Process Improvement

     Efforts continue to reduce the cost of products and services
in order to maintain competitiveness.  The accounting department
completed its consolidation of operations and the marketing
department completed its reorganization in 1998 producing cost
reductions.  In 1998 the Company reviewed its staffing levels for
power generation and energy delivery and developed plans to reduce
staff in 1999.  The cost of staff reductions planned for 1999 was
provided for in the fourth quarter of 1998.  Although cost savings
are expected to result from the power generation and energy
delivery reorganizations, the Company continues to incur expenses
related to investments in marketing and customer services and the
reengineering and improvement of business processes.

     During 1998, the Company completed installation of a new
unified customer service system which is designed to support
customer requests for service, billings, accounts receivable,
credit and collection functions.  On January 1, 1999, the Company's
new financial data base and PeopleSoft client server accounting and
purchasing software became operational.  The move to client server
business software and related online data bases will empower
employees to maximize the benefits of their personal computers and
will position them to better access the power of the Internet and
other new technologies.

Fuel Costs

     The management and control of coal costs is critical to our
competitive position.  Approximately 98% of the Company's
generation is coal fired with coal supplied under long-term
contracts and purchased in the spot market.  As long-term contracts
expire we are negotiating with unaffiliated suppliers to lower coal
costs.  We intend to continue to prudently supplement our long-term
coal supplies with spot market purchases when spot market prices
are favorable.

Environmental Concerns

     We take great pride in our efforts to economically produce and
deliver electricity while minimizing the impact on the environment.
Over the years the Company has spent hundreds of millions of
dollars to equip its facilities with the latest economical clean
air and water technologies and to research new technologies.  We
intend to continue in a leadership role fostering economically
prudent efforts to protect and preserve the environment.

     By-products from the generation of electricity include
materials such as ash, slag and sludge.  Coal combustion by-products
are typically disposed of or treated in captive disposal
facilities or are beneficially utilized.  In addition, our
generating plants and transmission and distribution facilities have
used asbestos, polychlorinated biphenyls (PCBs) and other hazardous
and nonhazardous materials.  The Company is currently incurring
costs to safely dispose of such substances.  Additional costs could
be incurred to comply with new laws and regulations if enacted.

     The Comprehensive Environmental Response, Compensation and
Liability Act (Superfund) addresses clean-up of hazardous
substances at disposal sites and authorized the United States
Environmental Protection Agency (Federal EPA) to administer the
clean-up programs.  As of year-end 1998, there is one site for
which the Company has received an information request which could
lead to a potentially responsible party designation.  The Company's
liability has been resolved for a number of sites with no
significant effect on results of operations and present estimates
do not anticipate material cleanup costs for the identified site in
which the Company is involved.  However, if for reasons not
currently identified significant costs are incurred for cleanup,
future results of operations, cash flows and possibly financial
condition could be adversely affected unless the costs can be
recovered from customers.

     Federal EPA is required by the Clean Air Act Amendments of
1990 (CAAA) to issue rules to implement the law.  In 1996 Federal
EPA issued final rules governing nitrogen oxide (NOx) that must be
met after January 1, 2000 (Phase II of the CAAA).  The final rules
will require substantial reductions in NOx emissions from certain
types of boilers including those in power plants of the Company and
its affiliates in the AEP System.  To comply with Phase II of CAAA,
the Company plans to install NOx emission control equipment on
certain units and switch fuel at other units.  Total capital costs
to meet the requirements of Phase II of CAAA are estimated to be
approximately $55 million of which $37 million has been incurred
through December 31, 1998.

     On September 24, 1998, the administrator of Federal EPA signed
final rules which require reductions in NOx emissions in 22 eastern
states, including the states in which the Company's generating
plants 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 a petition in the
United States (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 the final rules were signed
(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 $325 million.
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.

     At the Third Conference of the Parties to the United Nations
Framework Convention on Climate Change held in Kyoto, Japan in
December 1997 more than 160 countries, including the US, negotiated
a treaty requiring legally-binding reductions in emissions of
greenhouse gases, chiefly carbon dioxide, which many scientists
believe are contributing to global climate change.  The treaty,
which requires the advice and consent of the US Senate for
ratification, would require the US to reduce greenhouse gas
emissions seven percent below 1990 levels in the years 2008-2012.
Although the US has agreed to the treaty and signed it on November
12, 1998, President Clinton has indicated that he will not submit
the treaty to the Senate for consideration until it contains
requirements for "meaningful participation by key developing
countries" and the rules, procedures, methodology and guidelines of
the treaty's market-based policy instruments, joint implementation
programs and compliance enforcement provisions have been
negotiated.  At the Fourth Conference of the Parties, held in
Buenos Aires, Argentina, in November 1998, the parties agreed to a
work plan to complete negotiations on outstanding issues with a
view toward approving them at the Sixth Conference of the Parties
to be held in December 2000.  We will continue to work with the
Administration and Congress to monitor the development of public
policy on this issue.

     If the Kyoto treaty is approved by Congress, the costs to
comply with the emission reductions required by the treaty are
expected to be substantial and would have a material adverse impact
on results of operations, cash flows and possibly financial
condition if not recovered from customers.

Financial Condition

     The Company issued $220 million principal amount of long-term
obligations in 1998 at interest rates ranging from 5% to 7.3% and
received from its parent a $50 million capital contribution.  The
principal amount of long-term debt retirements, including
maturities, totaled $157 million with interest rates ranging from
7-1/4% to 8.75%.  The Company's senior secured debt/first mortgage
bond ratings are: Moody's, A3; Standard and Poor's (S&P), A; Fitch,
A; and Duff & Phelps, LLC (D & P), A.

     Gross plant and property additions were $226 million in 1998
and $233 million in 1997.  Management estimates construction
expenditures for the next three years to be $766 million which
includes the cost of transmission and distribution projects for the
improvement of and addition to electric energy delivery facilities.
The funds for construction of new facilities and improvement of
existing facilities can come from a combination of internally
generated funds, short-term and long-term borrowings and
investments in common equity by the Company's parent, AEP Co., Inc.
Approximately 65% of the construction expenditures for the next
three years are expected to be financed with internally generated
funds.

     When necessary the Company generally issues short-term debt to
provide for interim financing of capital expenditures that exceed
internally generated funds.  At December 31, 1998, $763 million of
unused short-term lines of credit shared with other AEP System
companies were available.  Short-term debt borrowings are limited
by provisions of the 1935 Act to $325 million.  Generally periodic
reductions of outstanding short-term debt are made through
issuances of long-term debt and through additional capital
contributions by the parent company.

     The Company's earnings coverage presently exceeds all minimum
coverage requirements for the issuance of mortgage bonds and
preferred stock.  The minimum coverage ratio is 2.0 for mortgage
bonds and 1.5 for preferred stock.  At December 31, 1998, the
mortgage bonds and preferred stock coverage ratios were 3.88 and
1.8, respectively.

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.  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 $3 million at a 95%
confidence level with a holding period of three business days.  The
AEP Power Pool uses 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 changes in interest rates primarily
due to short-term and long-term borrowings to fund its business
operations.  The debt portfolio has fixed and variable interest
rates with terms from one day to forty years and an average
duration of six years at December 31, 1998.  The Company measures
interest rate market risk exposure 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 are 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 $135
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.

     Inflation affects the Company's cost of replacing utility
plant and the cost of operating and maintaining its plant.  The
rate-making process limits our recovery to the historical cost of
assets resulting in economic losses when the effects of inflation
are not recovered from customers on a timely basis.  However,
economic gains that result from the repayment of long-term debt
with inflated dollars partly offset such losses.

Other Matters

Year 2000 Readiness Disclosure

     On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date.  In
addition, certain systems may fail to detect that the year 2000 is
a leap year.  Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Year 2000
ready programs.

Readiness Program

     Internally, the Company, through the AEP System, is modifying
or replacing its computer hardware and software programs to
minimize Year 2000-related failures and repair such failures if
they occur.  This includes both information technology systems
(IT), which are mainframe and client server applications, and
embedded logic systems (non-IT), such as process controls for
energy production and delivery.  Externally, the problem is being
addressed with entities that interact with the Company, including
suppliers, customers, creditors, financial service organizations
and other parties essential to the Company's operations.  In the
course of the external evaluation, the Company has sought written
assurances from third parties regarding their state of Year 2000
readiness.

     Another issue we are addressing is the impact of electric
power grid problems that may occur outside of our transmission
system.  The Company, along with other electric utilities in North
America, regularly submits information to the North American
Electric Reliability Council (NERC) as part of NERC's Year 2000
readiness program.  NERC then publicly reports summary information
to the U.S. Department of Energy (DOE) regarding the Year 2000
readiness of electric utilities.  In 1999 AEP plans to participate
in two NERC-sponsored coordinated electric industry Year 2000
readiness drills.

     The second NERC report, dated January 11, 1999 and entitled:
Preparing the Electric Power Systems of North American for
Transition to the Year 2000 - A Status Report and Work Plan, Fourth
Quarter 1998, states that: "With more than 44% of mission critical
components tested through November 30, 1998, findings continue to
indicate that transition through critical Year 2000 (Y2K) rollover
dates is expected to have minimal impact on electric system
operations in North America."  The Company continues to set a
target date of June 30, 1999 for having all mission critical and
high priority systems and components Y2K ready.

     Through the Electric Power Research Institute, an electric
industry-wide effort has been established to deal with Year 2000
problems affecting embedded systems.  Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.

     The state regulatory commissions in the Company's service
territory are also reviewing the Year 2000 readiness of the
Company.

Company's State of Readiness

     Work has been prioritized in accordance with business risk.
The highest priority has been assigned to activities that
potentially affect safety, the physical generation and delivery of
energy, and communications; followed by back office activities such
as customer service/billing, regulatory reporting, internal
reporting and administrative activities (e.g. payroll, procurement,
accounts payable); and finally, those activities that would cause
inconvenience or productivity loss in normal business operations.

     The following chart shows our progress toward becoming ready
for the Year 2000 as of December 31, 1998:
                                 IT SYSTEMS              NON-IT  SYSTEMS
                         COMPLETION                 COMPLETION
                         DATE/ESTIMATED   PERCENT   DATE/ESTIMATED   PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE  COMPLETE  COMPLETION DATE  COMPLETE

Launch: Initiation of      2/24/1998        100%      5/31/1998       100%
the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.

Inventory and Assessment:
Identifying all Company    7/31/1998        100%       2/15/1999      99%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.


Remediation/Testing: The
process of modifying,      6/30/1999     Mainframe    6/30/1999       37%
replacing or retiring                    70%
those mission critical and
high priority digital-based
systems with problems                    Client
processing dates past the                Server:
Year 2000. Testing these                 18%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.

Costs to Address the Company's Year 2000 Issues

     Through December 31, 1998, the Company has spent $6 million on
the Year 2000 project and, estimates spending an additional $10
million to $14 million to achieve Year 2000 readiness.  Most Year
2000 costs are for software modifications, IT consultants and
salaries and are expensed; however, in certain cases the Company
has acquired hardware that was capitalized.  The Company intends to
fund these expenditures through internal sources.  Although
significant, the cost of becoming Year 2000 compliant is not
expected to have a material impact on the Company's results of
operations, cash flows or financial condition.

Risks of the Company's Year 2000 Issues

     The applications posing the greatest business risk to the
Company's operations should they experience Y2K problems are:

*    Automated power generation, transmission and distribution systems
*    Telecommunications systems
*    Energy trading systems
*    Time-in-use, demand and remote metering systems for commercial
     and industrial customers and
*    Work management and billing systems.

     The potential problems related to erroneous processing by, or
failure of, these systems are:

*    Power service interruptions to customers
*    Interrupted revenue data gathering and collection
*    Poor customer relations resulting from delayed billing and
     settlement.

     In addition, although as discussed relationships with third
parties, such as suppliers, customers and other electric utilities,
are being monitored, these third parties nonetheless represent a
risk that cannot be assessed with precision or controlled with
certainty.

     Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others who impact the AEP System's operations but are
not affiliated with the AEP System, fail for critical applications,
Year 2000-related issues may materially adversely affect the
Company.

Company's Contingency Plans

     To address possible failures of electric generation and
delivery of electrical energy due to Year 2000 related failures, we
have established a draft Year 2000 contingency plan and submitted
it to the East Central Area Reliability Council in December 1998 as
part of NERC's review of regional and individual electric utility
contingency plans in 1999.  NERC's target date is June 1999 for the
completion of this contingency plan.  In addition, the Company
intends to establish contingency plans for its business units to
address alternatives if Year 2000 related failures occur.
Contingency plans will be developed by the end of 1999.  The
Company's plans build upon the disaster recovery, system
restoration, and contingency planning that we have had in place.

New Accounting Standards

     In 1997 the FASB issued SFAS 130 "Reporting Comprehensive
Income" and SFAS No. 131 "Disclosures About Segments of an
Enterprise and Related Information." SFAS 130 establishes the
standards for reporting and displaying components of "comprehensive
income," which is the total of net income and all transactions not
included in net income affecting equity except those with
shareholders.  The Company adopted SFAS 130 in the first quarter of
1998.  For 1998 there were no material differences between net
income and comprehensive income.

     SFAS 131 initiates standards for annual and interim financial
statements to report operating segments of a business for which
separate financial information is available and regularly evaluated
by the chief operating decision maker in allocating resources and
reviewing performance.  Information about products and services and
geographic areas is to be reported at an enterprise-level instead
of by segment.  SFAS 131 was required to be adopted by the Company
for the year ended December 31, 1998 with restatement of prior
period comparative information.  Adoption of SFAS 131 did not have
any effect on results of operations, cash flows or financial
condition.

     In the first quarter of 1998 the Company adopted the American
Institute of Certified Public Accountants' (AICPA) Statement of
Position (SOP) 98-1, "Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use". The SOP requires the
capitalization and amortization of certain costs of acquiring or
developing internal use computer software.  The SOP had to be
adopted at the beginning of a fiscal year with no restatement or
retroactive adjustment of prior periods.  The adoption of the SOP
effective January 1, 1998 did not have a material effect on results
of operations, cash flows or financial condition.

     In February 1998, the FASB issued SFAS 132 "Employers'
Disclosure about Pensions and Other Postretirement Benefits"  which
revised employers' disclosures about pensions and other
postretirement benefit plans and suggested that the disclosure be
combined.  It did not change the measurement or recognition
requirements for postretirement benefit accounting.  The adoption
of SFAS 132 did not have an effect on results of operations, cash
flows or financial condition.

     EITF 98-10 "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities" was issued in November 1998
to address the application of mark-to-market accounting for energy
trading contracts.  Under the provisions of this standard, which
must be adopted by the Company in January 1999, energy trading
contracts can no longer be accounted for on a settlement basis.
Instead they are to be marked-to-market.  Initial adoption of EITF
98-10 is not expected to have a significant impact on results of
operations, cash flows or financial condition.

     The FASB issued SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" in June 1998.  SFAS 133
establishes accounting and reporting standards for derivative
instruments.  It requires that all derivatives be recognized as
either an asset or a liability and measured at fair value in the
financial statements.  If certain conditions are met a derivative
may be designated as a hedge of possible changes in fair value of
an asset, liability or firm commitment; variable cash flows of
forecasted transactions; or foreign currency exposure.  The
accounting/reporting for changes in a derivative's fair value
(gains and losses) depend on the intended use and resulting
designation of the derivative.  Management is currently studying
the provisions of SFAS 133 to determine the impact of its adoption
on January 1, 2000 on results of operations, cash flows and
financial condition.

     In April 1998 the AICPA issued SOP 98-5 "Reporting on the
Costs of Start-up Activities".  The SOP clarifies the accounting
and reporting for one time start-up activities and organization
costs, requiring that they be expensed as incurred.  The adoption
of this standard in January 1999 is not expected to have a material
effect on results of operations, cash flows or financial condition.

<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income


                                                               Year Ended December 31,
                                                         1998           1997           1996
                                                                   (in thousands)
<S>                                                   <C>            <C>            <C>
OPERATING REVENUES                                    $1,672,244     $1,628,515     $1,624,869

OPERATING EXPENSES:
 Fuel                                                    437,500        403,777        367,651
 Purchased Power                                         303,116        311,514        333,014
 Other Operation                                         254,718        246,785        240,249
 Maintenance                                             134,856        112,873        117,483
 Depreciation and Amortization                           143,809        137,670        133,074
 Taxes Other Than Federal Income Taxes                   116,070        116,590        120,307
 Federal Income Taxes                                     53,632         59,312         70,215
          Total Operating Expenses                     1,443,701      1,388,521      1,381,993

OPERATING INCOME                                         228,543        239,994        242,876

NONOPERATING INCOME (LOSS)                                (8,301)          (222)           128

INCOME BEFORE INTEREST CHARGES                           220,242        239,772        243,004

INTEREST CHARGES                                         126,912        119,258        109,315

NET INCOME                                                93,330        120,514        133,689

PREFERRED STOCK DIVIDEND REQUIREMENTS                      2,497          7,006         15,938

EARNINGS APPLICABLE TO COMMON STOCK                   $   90,833     $  113,508     $  117,751
</TABLE>
See Notes to Consolidated Financial Statements.

<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets


                                                                           December 31,
                                                                      1998             1997
                                                                          (in thousands)
ASSETS
<S>                                                                <C>              <C>
ELECTRIC UTILITY PLANT:
   Production                                                      $1,976,729       $1,942,325
   Transmission                                                     1,116,421        1,079,919
   Distribution                                                     1,641,278        1,583,161
   General                                                            233,465          207,380
   Construction Work in Progress                                      119,466           88,261
                 Total Electric Utility Plant                       5,087,359        4,901,046
   Accumulated Depreciation and Amortization                        1,984,856        1,869,057
                 NET ELECTRIC UTILITY PLANT                         3,102,503        3,031,989


OTHER PROPERTY AND INVESTMENTS                                        111,020           34,544


CURRENT ASSETS:
   Cash and Cash Equivalents                                            7,755            6,947
   Accounts Receivable:
      Customers                                                       122,746          129,924
      Affiliated Companies                                             35,802           24,502
      Miscellaneous                                                     8,572           10,231
      Allowance for Uncollectible Accounts                             (2,234)          (1,333)
   Fuel - at average cost                                              49,826           47,901
   Materials and Supplies - at average cost                            60,440           57,359
   Accrued Utility Revenues                                            45,985           51,208
   Energy Marketing and Trading Contracts                              22,436              923
   Prepayments                                                          8,151            6,037
                 TOTAL CURRENT ASSETS                                 359,479          333,699


REGULATORY ASSETS                                                     426,193          441,223

DEFERRED CHARGES                                                       47,843           41,975
                     TOTAL                                         $4,047,038       $3,883,430

See Notes to Consolidated Financial Statements.
</TABLE>

<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES


                                                                           December 31,
                                                                      1998             1997
                                                                          (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                               <C>               <C>
CAPITALIZATION:
   Common Stock - No Par Value:
      Authorized - 30,000,000 Shares
      Outstanding - 13,499,500 Shares                             $   260,458       $  260,458
   Paid-in Capital                                                    663,633          613,048
   Retained Earnings                                                  179,461          207,544
                Total Common Shareholder's Equity                   1,103,552        1,081,050
   Cumulative Preferred Stock:
       Not Subject to Mandatory Redemption                             19,359           19,747
       Subject to Mandatory Redemption                                 22,310           22,310
   Long-term Debt                                                   1,472,451        1,415,026
                TOTAL CAPITALIZATION                                2,617,672        2,538,133

OTHER NONCURRENT LIABILITIES                                          120,281          137,371

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                                  80,004           79,509
   Short-term Debt                                                     76,400          130,300
   Accounts Payable - General                                          60,569           52,683
   Accounts Payable - Affiliated Companies                             50,313           44,133
   Taxes Accrued                                                       35,719           41,549
   Customer Deposits                                                   14,123           13,713
   Interest Accrued                                                    19,990           20,949
   Revenue Refunds Accrued                                             95,267            3,311
   Energy Marketing and Trading Contracts                              24,076              729
   Other                                                               78,808           68,083
                TOTAL CURRENT LIABILITIES                             535,269          454,959

DEFERRED INCOME TAXES                                                 643,711          658,655

DEFERRED INVESTMENT TAX CREDITS                                        62,231           67,496

DEFERRED CREDITS                                                       67,874           26,816

COMMITMENTS AND CONTINGENCIES (Note 4)

                    TOTAL                                          $4,047,038       $3,883,430

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows


                                                                Year Ended December 31,
                                                            1998          1997          1996
                                                                     (in thousands)
<S>                                                      <C>           <C>           <C>
OPERATING ACTIVITIES:
   Net Income                                            $  93,330     $ 120,514     $ 133,689
   Adjustments for Noncash Items:
      Depreciation and Amortization                        144,967       138,975       134,381
      Deferred Federal Income Taxes                         (2,338)       (5,117)          592
      Deferred Investment Tax Credits                       (5,265)       (5,181)       (5,602)
      Deferred Power Supply Costs (net)                     30,081        12,310           293
      Provision for Rate Refunds                           (31,019)        7,601        (2,626)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                             (1,562)       (3,990)      (19,176)
      Fuel, Materials and Supplies                          (5,006)        3,950        15,583
      Accrued Utility Revenues                               5,223           635        13,235
      Accounts Payable                                      14,066        10,924         3,668
      Taxes Accrued                                         (5,830)          614        (7,731)
      Revenue Refunds Accrued                               91,956        (2,272)        5,583
   Payment of Disputed Tax and Interest Related to COLI    (68,316)         -             -
   Change in Operating Reserves                             30,631        16,473         6,906
   Other (net)                                             (16,754)      (14,923)       (3,052)
        Net Cash Flows From Operating Activities           274,164       280,513       275,743

INVESTING ACTIVITIES:
   Construction Expenditures                              (204,869)     (218,074)     (191,815)
   Proceeds from Sales of Property and Other                 2,930         4,971         1,933
        Net Cash Flows Used For Investing Activities      (201,939)     (213,103)     (189,882)

FINANCING ACTIVITIES:
   Capital Contributions from Parent Company                50,000        40,000        50,000
   Issuance of Long-term Debt                              211,944       183,257       273,340
   Retirement of Cumulative Preferred Stock                   (294)     (183,875)      (25,904)
   Retirement of Long-term Debt                           (157,973)      (56,379)     (195,910)
   Change in Short-term Debt (net)                         (53,900)       69,600       (64,825)
   Dividends Paid on Common Stock                         (118,916)     (114,436)     (108,300)
   Dividends Paid on Cumulative Preferred Stock             (2,278)       (5,890)      (15,666)
        Net Cash Flows Used For Financing Activities       (71,417)      (67,723)      (87,265)

Net Increase (Decrease) in Cash and Cash Equivalents           808          (313)       (1,404)
Cash and Cash Equivalents January 1                          6,947         7,260         8,664
Cash and Cash Equivalents December 31                    $   7,755     $   6,947     $   7,260

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings


                                                                   Year Ended December 31,
                                                               1998         1997         1996
                                                                       (in thousands)
<S>                                                          <C>          <C>          <C>
Retained Earnings January 1                                  $207,544     $208,472     $199,021
Net Income                                                     93,330      120,514      133,689
                                                              300,874      328,986      332,710
Deductions:
   Cash Dividends Declared:
     Common Stock                                             118,916      114,436      108,300
     Cumulative Preferred Stock:
        4-1/2% Series                                             875          892        1,348
        4.50%  Series                                            -            -               9
        5.90%  Series                                             455          455        2,950
        5.92%  Series                                             364          364        3,552
        6.85%  Series                                             579          579        2,055
        7.40%  Series                                            -            -           1,385
        7.80%  Series                                            -             931        3,900
                Total Cash Dividends Declared                 121,189      117,657      123,499

   Capital Stock Expense                                          224        3,785          739
                Total Deductions                              121,413      121,442      124,238

Retained Earnings December 31                                $179,461     $207,544     $208,472

See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>

<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. SIGNIFICANT ACCOUNTING POLICIES:

Organization

    Appalachian Power Company (the Company or APCo) 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 888,000 retail customers in southwestern Virginia
and southern West Virginia and does business as American Electric
Power (AEP).  The Company supplies electric power to the American
Electric Power System Power Pool (AEP Power Pool) and shares the
revenues and costs of Power Pool wholesale sales to neighboring
utility systems and power marketers.  The Company also sells
wholesale power to municipalities.  As a member of the American
Electric Power System (AEP System) 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 has four wholly-owned subsidiaries which are
consolidated in these financial statements: Cedar Coal Co., Central
Appalachian Coal Company and Southern Appalachian Coal Company
(which were formerly engaged in coal mining and now lease their
coal reserves to unaffiliated companies) and West Virginia Power
Company (which is inactive).

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 State Corporation Commission of Virginia
(Virginia SCC) and the Public Service Commission of West Virginia
(WVPSC).  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 APCo and
its wholly-owned subsidiaries.  Significant intercompany items are
eliminated in consolidation.

Basis of Accounting

    As a cost-based rate-regulated entity, APCo'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) 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 utility plant
in service account and 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.  In the Virginia
jurisdiction, construction work in progress is included in rate
base and earns a return in regulated rates in lieu of recording
AFUDC.  The amounts of AFUDC in 1998, 1997 and 1996 were not
significant.

Depreciation and Amortization

    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:

                   Annual Composite
Functional Class   Depreciation
of Property        Rates

Production:
  Steam            3.4%
  Hydro            2.8%
Transmission       2.2%
Distribution       3.3%
General            3.1%


    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

    Revenues include the accrual of electricity consumed but
unbilled at month-end as well as billed revenues.

Power Supply Costs and Fuel Costs

    The Company practices deferred accounting with respect to over
or under collection of certain fuel and power supply costs pursuant
to the Virginia SCC's fuel cost recovery mechanism.  In the
Virginia jurisdiction, changes in fuel costs and the fuel portion
of purchased power costs are deferred and reviewed for recovery or
refund annually by the Virginia SCC.  In the West Virginia
jurisdiction, under the terms of a 1996 settlement agreement, a
modified version of deferral accounting will be practiced for the
over and under collection of fuel, Power Pool capacity charges and
certain transmission revenue for the period November 1996 through
December 1999.  Although a cumulative over and under recovery
balance will be maintained, ratepayers will not be responsible for
any cumulative underrecovery balance at December 31, 1999.
Overrecoveries during the annual periods through December 31, 1999
in excess of $10 million per period would be accumulated and shared
equally between the Company and its ratepayers.  Overrecoveries
under $10 million are not shared with rate payers and are included
in operating income annually.

    Wholesale jurisdictional fuel cost changes are expensed and
billed as incurred through a FERC fuel clause.

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 7 - 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 (purchase
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 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 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. 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.  In the
event a portion of the Company's business were to no longer meet
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.

    In February 1999 the Virginia legislature passed comprehensive
legislation, which will become law upon the Governor's signature,
to restructure the electric utility industry.  Under the
restructuring bill a transition to choice of supplier for retail
customers will commence on January 1, 2002 and be completed,
subject to a finding by the Virginia SCC that an effective
competitive market exists, on January 1, 2004.  Provisions allowing
for an acceleration or limited delay in this schedule are also
contained in the bill.  Except as provided in the legislation, the
generation of electricity will not be subject to rate regulation
after January 1, 2002.  Additionally, each Virginia electric
utility is required by 2001 to join or establish a regional
transmission entity which will manage and control transmission
assets.

    The Virginia restructuring bill also provides an opportunity
for recovery of just and reasonable net stranded costs.  Stranded
costs are those costs above market that potentially would not be
recoverable in a competitive market.  The mechanisms in the
Virginia legislation for stranded cost recovery are dual: a capping
of incumbent utility rates until as late as July 1, 2007, and the
application of a wires charge upon customers who may depart the
incumbent utility in favor of an alternative supplier prior to the
termination of the rate cap.  The legislation provides for the
establishment of capped rates prior to January 1, 2001. The capped
rates may be terminated after January 1, 2004, and prior to July 1,
2007, based upon the Virginia SCC determining that an effective
competitive market exists.  The wires charge will be equal to the
difference between the generation component of the capped rates and
the market price for generation service and will be imposed upon
departing customers through the expiration of the rate cap period.

    Management has reviewed all the evidence currently available
and concluded that as of December 31, 1998 the requirements to
apply SFAS 71 continue to be met.  Virginia rates for generation
will continue to be cost-based regulated until the establishment of
capped rates as provided in the legislation.  When capped rates are
established the application of SFAS 71 would be discontinued for
the Virginia retail jurisdiction portion of the generating
business.  At that time generation-related regulatory assets
applicable to the Virginia jurisdiction will have to be written off
to the extent that they cannot be recovered under the provisions of
the restructuring legislation and generating assets for the
Virginia retail jurisdiction will have to be evaluated for
impairment.  Based upon initial reviews the amount of regulatory
assets applicable to the Virginia generating business at December
31, 1998 is estimated to be $64 million before related tax effects
and any possible offsetting regulatory liabilities.  Regulatory
liabilities applicable to the Virginia generation business at
December 31, 1998 are estimated to be $39 million of which $26
million represents deferred investment tax credits.  The Company is
evaluating the tax normalization rules regarding the timing of the
reversal of deferred investment tax credits in connection with the
Virginia restructuring legislation.  Should it not be possible
under the Virginia legislation to recover any portion of the
generation net regulatory  assets, it could have a material adverse
impact on results of operations; however, the amount of any
impairment loss for Virginia retail jurisdictional generating
assets and any loss from a possible inability to recover net
generation regulatory assets cannot be estimated until such time as
capped rates are determined under the legislation.

    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    $374,750      $386,127
  Unamortized Loss On
    Reacquired Debt              22,827        23,561
  Deferred Storm Damage           6,101         8,542
  Other                          22,515        22,993
  Total Regulatory Assets      $426,193      $441,223

Regulatory Liabilities:
  Deferred Investment Tax
    Credits                    $ 62,231       $67,496
  Other*                         53,955        21,121
  Total Regulatory Liabilities $116,186       $88,617

* Included in Deferred Credits on Consolidated Balance Sheets.


3. RATE MATTERS:

    In June 1997 the Company filed an application with the Virginia
SCC for approval, among other things, of an increase of $30.5
million in base rates on an annual basis.  In July 1997 the
Virginia SCC suspended implementation of the proposed rates until
November 11, 1997 when rates were placed into effect subject to
refund.  On January 11, 1999, the Company and the Virginia SCC
Staff filed a Stipulation agreement with the Virginia SCC which was
approved in February 1999.  The Stipulation's main provisions
include the retroactive elimination of the $30.5 million annual
increase in base rates that was being collected subject to refund;
a reduction in base rates of $6 million effective January 1, 1998;
the refund with interest of all amounts collected above the
approved rates; the intention to hold rates at these levels through
December 31, 2000; an investment of at least $90 million in
Virginia distribution facilities between January 1, 1998 and
December 31, 2000 (Plan Period); and a benchmark rate of return on
equity of 10.85% (Benchmark Rate) upon which future earnings will
be tested.  During the Plan Period, one-third of any earnings above
the Benchmark Rate will be retained by the Company and the
remaining two-thirds will be refunded to ratepayers.  The fuel
factor component of rates will continue to be administered under
current regulation.  A refund liability, including interest, of
$51.6 million at December 31, 1998 has been accrued.



    In September 1992 the Company implemented, subject to refund,
an $8.7 million annual rate increase to its wholesale customers
pending a final order from the Federal Energy Regulatory Commission
(FERC).  On June 29, 1998 the FERC granted an annual rate increase
of $3.4 million and required a refund including interest of amounts
collected in excess of the $3.4 million annual increase.  A
rehearing of the FERC's order has been requested.  A refund
liability, including interest, of $42.8 million at December 31,
1998 has been accrued.


4. 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 $766 million.

    Long-term fuel supply contracts contain clauses that provide
for periodic price adjustments.  The contracts are for various
terms, the longest of which extends to 2006, and contain various
clauses that would release the Company from its obligation under
certain force majeure conditions.

Clean Air Act/Air Quality

    The United States (US) Environmental Protection Agency (Federal
EPA) is required by the Clean Air Act Amendments of 1990 (CAAA) to
issue rules to implement the law.  In 1996 Federal EPA issued final
rules governing nitrogen oxides (NOx) emissions that must be met
after January 1, 2000 (Phase II of CAAA).  The final rules will
require substantial reductions in NOx emissions from certain types
of boilers including those in the AEP System's and the Company's
power plants.  To comply with Phase II of CAAA, the Company plans
to install NOx emission control equipment on certain units and
switch fuel at other units.  The Company's total capital costs to
meet the requirements of Phase II of CAAA are estimated to be
approximately $55 million of which $37 million has been incurred
through December 31, 1998.

    On September 24, 1998, Federal EPA finalized rules which
require reductions in NOx emissions in 22 eastern states, including
the states in which the AEP System's and the Company's generating
plants 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 by the Company of approximately $325
million.  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 $79 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.  The 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.


5. 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 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 $36.9 million in 1998, $40.1 million
in 1997 and $54.8 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      $ 83,536   $128,680    $125,456
Energy Charges          97,226    149,113     187,754

     Total            $180,762   $277,793    $313,210

    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:

                             Year Ended December 31,
                            1998       1997      1996
                                  (in thousands)
Operating Revenues        $193,441   $128,041  $126,971
Purchased Power Expense    111,909     27,330    14,700
Nonoperating Loss          (11,179)       (81)     -

<PAGE>
    Energy sold directly to Kingsport Power Company (KGPCo), an
affiliated distribution utility that is not a member of the AEP
Power Pool, was included in operating revenues in the amounts of
$56.8 million in 1998, $57.9 million in 1997 and $59.5 million in
1996.

    Purchased power expense includes $10.4 million in 1998, $6.4
million in 1997 and $5.1 million in 1996 of 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 greater than its relative
peak demands in 1998 and less than its relative peak demands in
1997 and 1996, other operation expense includes equalization
charges (credits) of $(2.4) million, $8.4 million and $6.5 million
in 1998, 1997 and 1996, respectively.

    The Company and an affiliate, Ohio Power Company (OPCo),
jointly own two power plants.  The costs of operating these
facilities are apportioned between the owners based on ownership
interests.  The Company's share of these costs is included in the
appropriate expense accounts on the Consolidated Statements of
Income.  The Company's investment in these plants is included in
electric utility plant on the Consolidated Balance Sheets.

    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 to its affiliated clients by AEPSC 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.


6. 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 business is
the power marketing and trading activities that are discussed in
Note 5.  For the years ended December 31, 1998, 1997 and 1996, all
of the Company's revenues are derived from the generation, sale and
distribution of electricity in the United States.


7.  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 market area are recorded as net 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 $33 million.  Physical
forward electricity contracts outside AEP's traditional economic
marketing area, and all financial electricity trading transactions
where the underlying physical commodity is outside AEP's
traditional market 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 $11 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 forty years and
an average duration of six 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 still 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 valves of derivatives were not material.

                       Book Value  Fair Value
                           (in thousands)
Non-Derivatives

1998

Long-term Debt         $1,552,500  $1,638,700

Preferred Stock            22,300      23,400

1997

Long-term Debt          1,494,500   1,572,300

Preferred Stock            22,300      23,400

Derivatives

1998

                                Fair Value  Average Fair Value
                                      (in thousands)
Trading Assets

Electric
  Physicals                       $13,700        $12,200
  Options                          10,100         24,300
  Swaps                             1,000            300

Trading Liabilities

Electric
  Futures                          (2,100)          (500)
  Physicals                       (14,800)       (13,900)
  Options                          (8,900)       (23,700)
  Swaps                            (2,300)          (600)

    At December 31, 1998 the notional amounts of the Company's
non-regulated electric trading physical forward contract purchases and
sales are 3,024 Gigawatt hours (Gwh) and 3,234 Gwh, respectively;
the notional amounts for fixed priced swaps purchases and sales are
111 Gwh and 119 Gwh, respectively; and the notional amounts for
options to purchase and to sell are 2,184 Gwh and 1,570 Gwh,
respectively.  The Company has a net long position of 117 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
$110 million and $107 million, respectively.  The related notional
amounts were 14,388 Gwh for purchases and 14,682 Gwh for sales.
The average fair value amounts outstanding during the period were
$277 million of assets and $265 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 the 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
Standards & 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.


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 180 power generation and energy delivery positions
were identified for elimination.

    Severance accruals totaling $7.6 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.


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 costs for the years ended December 31,
1998, 1997 and 1996 were $0.8 million, $1.9 million and $4.2
million, respectively.

    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 $16.6 million in 1998,
$17.3 million in 1997 and $19 million in 1996.

    A defined contribution employee savings plan required that the
Company make contributions to the plan totaling $4.3 million in
1998, $4 million in 1997, and $4.1 million in 1996.

<TABLE>
10. FEDERAL INCOME TAXES:

     The details of federal income taxes as reported are as
follows:
<CAPTION>
                                                               Year Ended December 31,
                                                       1998             1997               1996
                                                                  (in thousands)
<S>                                                  <C>              <C>                <C>
Charged (Credited) to Operating Expenses (net):
  Current                                            $56,446          $66,810            $71,648
  Deferred                                              (143)          (4,801)             1,283
  Deferred Investment Tax Credits                     (2,671)          (2,697)            (2,716)
           Total                                      53,632           59,312             70,215
Charged (Credited) to Nonoperating Income (net):
  Current                                             (4,902)          (1,677)              (837)
  Deferred                                            (2,195)            (316)              (691)
  Deferred Investment Tax Credits                     (2,594)          (2,484)            (2,886)
           Total                                      (9,691)          (4,477)            (4,414)
Total Federal Income Taxes as Reported               $43,941          $54,835            $65,801

     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                                      $ 93,330            $120,514            $133,689
Federal Income Taxes                              43,941              54,835              65,801
Pre-tax Book Income                             $137,271            $175,349            $199,490

Federal Income Taxes on Pre-tax Book Income at
  Statutory Rate (35%)                           $48,045             $61,372             $69,822
Increase (Decrease) in Federal Income Taxes
  Resulting From the Following Items:
    Depreciation                                  11,667              10,945              11,932
    Corporate Owned Life Insurance                (4,212)             (3,974)             (2,298)
    Removal Costs                                 (4,200)             (4,200)             (5,460)
    Investment Tax Credits (net)                  (5,265)             (5,181)             (5,602)
    Other                                         (2,094)             (4,127)             (2,593)
Total Federal Income Taxes as Reported           $43,941             $54,835             $65,801

Effective Federal Income Tax Rate                   32.0%               31.3%               33.0%
</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              $ 168,898  $ 144,869
Deferred Tax Liabilities          (812,609)  (803,524)
  Net Deferred Tax Liabilities   $(643,711) $(658,655)

Property Related Temporary
  Differences                    $(496,464) $(491,904)
Amounts Due From Customers For
  Future Federal Income Taxes     (106,436)  (108,727)
Deferred State Income Taxes        (70,644)   (75,476)
All Other (net)                     29,833     17,452
  Net Deferred Tax Liabilities   $(643,711) $(658,655)

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

     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 4, 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:

     The Company received from AEP Co., Inc. cash capital
contributions of $50 million, $40 million and $50 million in 1998,
1997 and 1996, respectively, which were credited to paid-in
capital.  In 1998, 1997 and 1996 net changes in paid-in capital of
$585,000, $(2,332,000) and $329,000, respectively, resulted from
gains and (expenses) associated with cumulative preferred stock
transactions.  There were no other material transactions affecting
common stock and paid-in capital accounts in 1998, 1997 and 1996.
At December 31, 1998 there were no dividend restrictions on
retained earnings.  To pay dividends out of paid-in capital, the
Company needs regulatory approval.


12.  CUMULATIVE PREFERRED STOCK:

     The authorized number of shares of no par value cumulative
preferred stock is 8,000,000.  The aggregate involuntary
liquidation price for all shares of cumulative preferred stock may
not exceed $300 million.  The unissued shares of the cumulative
preferred stock may or may not possess mandatory redemption
characteristics upon issuance.

     The cumulative preferred stock is callable at the price
indicated plus accrued dividends.  The involuntary liquidation
preference is $100 per share.

     The Company redeemed and canceled 500,000 shares of the 7.80%
series and 2,348 shares of the 4.50% series subject to mandatory
redemption in 1997 and 1996, respectively.  The Company redeemed
and canceled 250,000 shares of the 7.40% series not subject to
mandatory redemption in 1996.

Cumulative Preferred Stock Not Subject to Mandatory Redemption:
<TABLE>
<CAPTION>
            Call Price                                             Shares               Amount
           December 31,      Number of Shares Redeemed          Outstanding          December 31,
Series         1998            Year Ended December 31,       December 31, 1998     1998        1997
                              1998      1997      1996                               (in thousands)
<S>          <C>              <C>     <C>         <C>              <C>           <C>         <C>
4-1/2%       $110.00          3,878   100,685     1,850            193,587       $19,359     $19,747
</TABLE>
<TABLE>
Cumulative Preferred Stock Subject to Mandatory Redemption:
<CAPTION>
           Call Price
          December 31,      Number of Shares Redeemed           Outstanding          December 31,
Series(a)     1998            Year Ended December 31,        December 31, 1998      1998       1997
                             1998      1997      1996                                (in thousands)
<S>         <C>               <C>    <C>          <C>              <C>            <C>        <C>
5.90% (b)   $  (d)            -      422,900      -                77,100         $ 7,710    $ 7,710
5.92% (b)      (d)            -      538,500      -                61,500           6,150      6,150
6.85% (c)      (e)            -      215,500      -                84,500           8,450      8,450
                                                                                  $22,310    $22,310

(a) The sinking fund provisions of each series have been met by
purchase of shares in advance of the due date.
(b) Commencing in 2003 and continuing through 2007 the Company may
redeem at $100 per share 25,000 shares of the 5.90% series and 30,000
shares of the 5.92% series outstanding under sinking fund provisions
at its option and all outstanding shares must be reacquired in 2008.
Shares redeemed in 1997 may be applied to meet the sinking fund
requirement.
(c) Commencing in 2000 and continuing through date of redemption, a
sinking fund for the 6.85% cumulative preferred stock will require the
redemption of 60,000 shares each year, in each case at $100 per share.
The Company has the non-cumulative option to redeem up to 60,000
additional shares on any sinking fund date at a redemption price of
$100 per share.  Shares redeemed in 1997 may be applied to meet the
sinking fund requirement.
(d) Not callable until after 2002.
(e) Not callable until after 1999.
</TABLE>

<PAGE>
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         $  960,597    $1,096,811
Installment Purchase
  Contracts                     234,262       234,217
Senior Unsecured Notes          193,959          -
Junior Debentures               161,087       160,948
Other Long-term Debt              2,550         2,559
                              1,552,455     1,494,535
Less Portion Due Within
  One Year                       80,004        79,509
   Total                     $1,472,451    $1,415,026

     First mortgage bonds outstanding were as follows:

                                   December 31,
                                 1998         1997
                                  (in thousands)
% Rate  Due
7.00    1999 - December 1    $   30,000   $   30,000
6.35    2000 - March 1           48,000       48,000
6.71    2000 - June 1            48,000       48,000
6-3/8   2001 - March 1          100,000      100,000
7.95    2002 - March 1             -          60,000
7.38    2002 - August 15         50,000       50,000
7.40    2002 - December 1        30,000       30,000
6.65    2003 - May 1             40,000       40,000
6.85    2003 - June 1            30,000       30,000
6.00    2003 - November 1        30,000       30,000
7.70    2004 - September 1       21,000       21,000
7.85    2004 - November 1 (a)    50,000       50,000
8.00    2005 - May 1             50,000       50,000
6.89    2005 - June 22           30,000       30,000
6.80    2006 - March 1          100,000      100,000
8.75    2022 - February 1          -          29,919
8.70    2022 - May 22              -          35,000
8.43    2022 - June 1            37,471       50,000
8.50    2022 - December 1        70,000       70,000
7.80    2023 - May 1             40,000       40,000
7.90    2023 - June 1            30,000       30,000
7.15    2023 - November 1        30,000       30,000
7.125   2024 - May 1             50,000       50,000
8.00    2025 - June 1            50,000       50,000
Unamortized Discount             (3,874)      (5,108)
                                960,597    1,096,811
Less Portion Due Within
 One Year                        80,000       60,000
  Total                      $  880,597   $1,036,811

(a)  A one time put feature allows this series of bonds to be put
     back to the Company on November 1, 1999.  Consequently the
     bonds are classified as due in 1999.

     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
governmental authorities as follows:

                                      December 31,
                                    1998       1997
                                     (in thousands)
% Rate   Due
Industrial Development Authority of
 Russell County, Virginia:

7-1/4    1998 - November 1        $   -      $ 19,500
7.70     2007 - November 1          17,500     17,500
5.00     2021 - November 1          19,500       -

Putnam County, West Virginia:

5.45     2019 - June 1              40,000     40,000
6.60     2019 - July 1              30,000     30,000

Mason County, West Virginia:

7-7/8    2013 - November 1          10,000     10,000
7.40     2014 - January 1           30,000     30,000
6.85     2022 - June 1              40,000     40,000
6.60     2022 - October 1           50,000     50,000

Unamortized Discount                (2,738)    (2,783)
                                   234,262    234,217
Less Portion Due Within
 One Year                             -        19,500
  Total                           $234,262   $214,717

     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 (at stated maturities and upon
mandatory redemptions) of related pollution control revenue bonds
issued to finance the construction of pollution control facilities at
certain plants.


<PAGE>
     Senior unsecured notes outstanding were as follows:

                                      December 31,
                                    1998       1997
                                     (in thousands)
% Rate   Due
7.20     2038 - March 31          $100,000   $   -
7.30     2038 - June 30            100,000       -
Unamortized Discount                (6,041)      -
  Total                           $193,959   $   -

     Junior debentures outstanding were as follows:

                                     December 31,
                                1998            1997
                                   (in thousands)
8-1/4% Series A due 2026
  - September 30               $ 75,000       $ 75,000
8% Series B due 2027
  - March 31                     90,000         90,000
Unamortized Discount             (3,913)        (4,052)
  Total                        $161,087       $160,948

     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, 1998, future annual long-term debt payments
are as follows:

                                       Amount
                                   (in thousands)

  1999                               $   80,004
  2000                                   96,005
  2001                                  100,006
  2002                                   80,006
  2003                                  100,007
  Later Years                         1,112,993
    Total Principal Amount            1,569,021
  Unamortized Discount                  (16,566)
      Total                          $1,552,455

     Short-term debt borrowings are limited by provisions of the
1935 Act to $325 million.  Lines of credit are shared with other 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 line of credit are
required to maintain the lines of credit.  Outstanding short-term debt
consisted of:

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

December 31, 1998:
  Notes Payable                $34,600          5.7%
  Commercial Paper              41,800          6.2%
    Total                      $76,400          6.0%

December 31, 1997:
  Notes Payable               $ 33,700          6.5%
  Commercial Paper              96,600          6.8%
    Total                     $130,300          6.7%


14. LEASES:

     Leases of property, plant and equipment are for periods of up
to 30 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
treatment.  The components of rental costs are as follows:

                               Year Ended December 31,
                               1998     1997     1996
                                   (in thousands)

Operating Leases              $ 7,047  $ 8,016  $ 9,567
Amortization of
  Capital Leases               13,561   11,771   12,175
Interest on Capital Leases      3,541    3,290    3,416
Total Rental Costs            $24,149  $23,077  $25,158

     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:
  Production Plant                       $ 9,463      $10,553
  General Plant                           87,776       77,980
Total Electric Utility Plant
  Under Capital Leases                    97,239       88,533
  Accumulated Amortization                32,064       28,423
Net Properties Under Capital Leases      $65,175      $60,110

Capital Lease Obligations*:
  Noncurrent Liability                   $52,429      $48,552
  Liability Due Within One Year           12,746       11,558
Total Capital Lease Obligations          $65,175      $60,110

*Represents the present value of future minimum lease payments.

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


<PAGE>
     Future minimum lease payments consisted of the following at
December 31, 1998:
                                        Non-
                                     Cancelable
                        Capital      Operating
                        Leases          Leases
                           (in thousands)

1999                    $16,704        $2,227
2000                     14,453         1,991
2001                     12,235           932
2002                     11,158           415
2003                      8,222           413
Later Years              17,018         3,712

Total Future Minimum
  Lease Rentals          79,790        $9,690

Less Estimated Interest
  Element                14,615

Estimated Present Value
  of Future Minimum
  Lease Payments        $65,175


15.  SUPPLEMENTARY INFORMATION:

                             Year Ended December 31,
                             1998      1997      1996
                                  (in thousands)
Cash was paid for:
  Interest (net of
   capitalized amounts)    $124,027  $115,508 $104,156
  Income Taxes              $65,102   $71,749  $82,194

Noncash Acquisitions Under
   Capital Leases           $21,146   $15,266  $15,308


16. UNAUDITED QUARTERLY FINANCIAL INFORMATION:

Quarterly Periods       Operating  Operating     Net
     Ended               Revenues   Income     Income
                                (in thousands)
1998
 March 31               $415,366    $64,249    $33,199
 June 30                 403,080     46,192     15,124
 September 30            474,476     70,951     33,446
 December 31             379,322     47,151     11,561

1997
 March 31                416,450     64,334     36,484
 June 30                 373,084     45,397     15,378
 September 30            413,532     64,780     34,753
 December 31             425,449     65,483     33,899

Fourth quarter 1998 net income declined primarily as a result of
unseasonably mild weather, provisions for rate refunds recorded for
the Virginia retail jurisdiction and severance accruals for staff
reductions.

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


<PAGE>
INDEPENDENT AUDITORS' REPORT






To the Shareholders and Board of
Directors of Appalachian Power Company:

We have audited the accompanying consolidated balance sheets of
Appalachian 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 Appalachian 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