<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data


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

  Operating Revenues            $1,650,937   $1,672,244   $1,628,515   $1,624,869   $1,545,039
  Operating Expenses             1,409,701    1,443,701    1,388,521    1,381,993    1,317,937
  Operating Income                 241,236      228,543      239,994      242,876      227,102
  Nonoperating Income (Loss)         8,096       (8,301)        (222)         128       (4,699)
  Income Before Interest Charges   249,332      220,242      239,772      243,004      222,403
  Interest Charges                 128,840      126,912      119,258      109,315      106,503
  Net Income                       120,492       93,330      120,514      133,689      115,900
  Preferred Stock Dividend
    Requirements                     2,706        2,497        7,006       15,938       16,405
  Earnings Applicable to
    Common Stock                $  117,786   $   90,833   $  113,508   $  117,751   $   99,495



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

  Electric Utility Plant        $5,262,951   $5,087,359   $4,901,046   $4,717,132   $4,558,436
  Accumulated Depreciation and
     Amortization                2,079,490    1,984,856    1,869,057    1,782,017    1,694,746
  Net Electric Utility Plant    $3,183,461   $3,102,503   $3,031,989   $2,935,115   $2,863,690
  Total Assets                  $4,354,400   $4,047,038   $3,883,430   $3,800,737   $3,723,975

  Common Stock and
    Paid-in Capital             $  974,717   $  924,091   $  873,506   $  835,838   $  785,509
  Retained Earnings                175,854      179,461      207,544      208,472      199,021
  Total Common Shareholder's
    Equity                      $1,150,571   $1,103,552   $1,081,050   $1,044,310   $  984,530

  Cumulative Preferred Stock:
    Not Subject to Mandatory
      Redemption                $   18,491   $   19,359   $   19,747   $   29,815   $   55,000
    Subject to Mandatory
      Redemption (a)                20,310       22,310       22,310      190,000      190,235
        Total Cumulative
          Preferred Stock       $   38,801   $   41,669   $   42,057   $  219,815   $  245,235

  Long-term Debt (a)            $1,665,307   $1,552,455   $1,494,535   $1,365,842   $1,285,684

  Obligations Under Capital
    Leases (a)                  $   64,645   $   65,175   $   60,110   $   51,969   $   48,937

  Total Capitalization and
    Liabilities                 $4,354,400   $4,047,038   $3,883,430   $3,800,737   $3,723,975
</TABLE>

(a) Including portion due within one year.

<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 ability to recover generation-related
regulatory assets and other transition costs including stranded
costs under the Virginia and West Virginia restructuring plans; new
legislation and government regulations; the ability of the Company
to successfully control its costs; the economic climate and growth
in our service territory; the outcome of litigation with the
Internal Revenue Service (IRS) related to certain interest
deductions for a corporate owned life insurance (COLI) program; the
ability of the Company to successfully challenge new environmental
regulations and to successfully litigate claims that the Company
violated the Clean Air Act; inflationary trends; changes in
electricity market prices; interest rates; and other risks and
unforeseen events.

     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 896,000 retail customers in southwestern Virginia
and southern West Virginia and does business as American Electric
Power (AEP).  The Company as a member of the AEP System Power Pool
(AEP Power Pool) shares the revenues and costs of the AEP Power
Pool's wholesale sales to neighboring utility systems and power
marketers. The Company also sells wholesale power to
municipalities.

   The cost of the AEP System's generating capacity is allocated
among the AEP Power Pool members based on their relative peak
demands and generating reserves through the payment or receipt of
capacity charges and credits.  AEP Power Pool members are also
compensated for their out-of-pocket costs of energy delivered to
the AEP Power Pool and charged for energy received from the AEP
Power Pool.

   The AEP Power Pool calculates each Company's prior twelve month
peak demand relative to the total peak demand of all member
companies as a basis for sharing revenues and costs.  The result of
this calculation is the member load ratio (MLR) which determines
each Company's percentage share of revenues or costs.  Since the
Company's MLR decreased in 1999 and 1998, the AEP Power Pool is
allocating a smaller share of Power Pool revenues and expenses to
the Company.
<PAGE>
Results of Operations

Net Income

     Net income increased $27.2 million or 29% in 1999 primarily
due to a nonoperating gain in 1999 on the sale of real estate and
mining assets by the Company's inactive mining subsidiaries and a
decline in operating expenses.

     Although operating revenues increased in 1998, net income
declined $27.2 million or 23% due primarily to increased fuel and
maintenance expenses, losses on non-regulated electricity trading
outside of the AEP Power Pool's traditional marketing area,
increased interest charges and provisions for revenue refunds.

Operating Revenues

     Operating revenues decreased 1% in 1999 primarily due to a
decrease in wholesale sales and a decline in net revenues
reflecting lower margins on wholesale trading transactions.  An
increase of 3% in operating revenues in 1998 was primarily due to
increased revenues from regulated electricity trading and
transmission services.  The changes in the components of revenues
were as follows:

                                      Increase (Decrease)
                                      From Previous Year
(dollars in millions)                  1999           1998
                                  Amount    %    Amount     %
Retail:
   Residential                    $ 19.4          $(5.1)
   Commercial                       17.1            2.3
   Industrial                       (4.4)          (0.3)
   Other                             0.9            2.2
                                    33.0   2.6     (0.9)  (0.1)

Wholesale                          (80.6)(23.0)    30.7    9.6

Transmission                        (3.4) (7.3)    19.3   69.9

Miscellaneous                       29.7 186.9     (5.4) (25.5)

     Total                        $(21.3) (1.3)   $43.7    2.7

     Revenue from retail customers increased in 1999 primarily due
to a 2% increase in retail sales reflecting higher residential and
commercial sales.  The increase in retail sales is primarily due to
colder winter weather and customer growth.

     The decline in wholesale revenues in 1999 reflects the
termination of a contract with several municipal customers in July
1998 and a decline in margins on regulated power trading
transactions.  The decline in margins reflects the moderation in
1999 of extreme weather in 1998 and capacity shortage experienced
in the summer of 1998.  The volume of power trading grew
substantially during 1998 and accounted for the increase in
wholesale revenues in 1998.  Trading revenues are recorded net of
purchases.

     Transmission service revenues increased in 1998 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 AEP System transmission
revenues.

     The increase in miscellaneous revenues in 1999 reflects a
favorable adjustment to a provision for revenue refunds recorded
in connection with the execution of a final rate refund and an
increase in rental revenues from billings to telecommunications
companies for pole attachments.  In 1998 miscellaneous revenues
declined due to the recordation of provisions for revenue refunds
under final rate orders.

Operating Expenses

     Operating expenses decreased by 2% in 1999 and increased 4% in
1998.  The decline in purchased power expense is the primary reason
for the decrease in operating expenses in 1999.  Operating expenses
increased in 1998 mainly due to increased fuel and maintenance
costs.  Changes in the components of operating expenses were as
follows:
                               Increase (Decrease)
                               From Previous Year
(dollars in millions)        1999             1998
                       Amount      %    Amount     %

Fuel                   $  7.2     1.6    $33.7    8.4
Purchased Power         (49.0)  (16.2)    (8.4)  (2.7)
Other Operation          (5.1)   (2.0)     7.9    3.2
Maintenance             (11.0)   (8.2)    22.0   19.5
Depreciation and
  Amortization            5.1     3.5      6.1    4.5
Taxes Other Than
  Federal Income Taxes    1.5     1.4     (0.5)  (0.4)
Federal Income Taxes     17.3    32.2     (5.6)  (9.6)
  Total                $(34.0)   (2.4)   $55.2    4.0

     The increases in fuel expense in 1999 and 1998 are primarily
due to increases in generation reflecting greater utilization of
internally generated power.

<PAGE>
     The reductions in purchased power expense in 1999 and 1998
were primarily due to reduced capacity charges from the AEP Power
Pool as a result of declines in the Company's MLR and decreased
purchases from the AEP Power Pool.  The decline in purchases from
the AEP Power Pool can be attributed to increased internal
generation and the termination of the contract with several
municipal customers.

     Maintenance expense decreased in 1999 and increased in 1998
primarily as a result of expenditures during 1998 to restore
service and make repairs following two severe snowstorms.  Also
contributing to the increase in maintenance expense in 1998 were
expenditures to clear and maintain right-of-ways.

     The increase in federal income taxes attributable to
operations in 1999 is primarily due to an increase in pre-tax
operating income and changes in certain book/tax differences
accounted for on a flow-through basis for rate-making purposes.
Federal income taxes attributable to operations decreased in 1998
primarily due to a decline in pre-tax operating income.

Nonoperating Income

     The increase in nonoperating income in 1999 is primarily due
to the effect of non-regulated electricity trading and a gain on
the sale of coal lands and mining assets by the Company's inactive
coal mining subsidiaries.  In 1999 nonoperating income included a
gain from non-regulated electricity trading transactions, which are
outside the AEP Power Pool's traditional marketing area, whereas
1998 included a net loss.  In November 1999 the subsidiaries sold
coal lands and mining assets which had been leased by an
unaffiliated company.

     Nonoperating income declined in 1998 primarily due to net
losses from non-regulated electricity trading transactions outside
of the AEP Power Pool's traditional marketing area which are
marked-to-market.

Interest Charges

     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.

Business Outlook

     The most significant factors affecting the Company's future
earnings are its ability to recover regulatory assets, transition
and other stranded costs under the Virginia and West Virginia
restructuring plans; weather in the service territories served by
the Company and its wholesale customers; generating unit
availability; the outcome of litigation with the IRS related to
certain interest deductions for COLI; and the outcome of ongoing
environmental litigation and challenges to proposed air quality
standards.  In 1999 significant progress was made related to many
of these major challenges.

Virginia Restructuring

     In March 1999 a law was enacted in Virginia to restructure the
electric utility industry.  Under the restructuring law, a
transition to choice of electricity supplier for retail customers
will commence on January 1, 2002 and be completed, subject to a
finding by the Virginia State Corporation Commission (Virginia SCC)
that an effective competitive market exists, on or before January
1, 2004.

     The law also provides an opportunity to recover just and
reasonable net stranded generation costs.  The mechanisms in the
Virginia law for net stranded cost recovery are: a capping of rates
until as late as July 1, 2007, and the application of a wires
charge upon customers who depart the incumbent utility in favor of
an alternative supplier prior to the termination of the rate cap.
The law provides for the establishment of capped rates prior to
January 1, 2001 and the establishment of a wires charge by the
fourth quarter of 2001.

West Virginia Restructuring

     On January 28, 2000, after over three years of workshops,
hearings and negotiations, the Public Service Commission of West
Virginia (WVPSC) issued an order approving an electricity
restructuring plan for West Virginia.  The restructuring plan has
been submitted to the West Virginia Legislature for approval or
rejection.

     The provisions of the proposed restructuring plan provide for
customer choice to begin on January 1, 2001, or at a later date set
by the WVPSC after all necessary rules are in place (the "starting
date"); deregulation of generating assets occurring on the starting
date; functional separation of the generation, transmission and
distribution businesses on the start date and their legal corporate
separation no later than January 1, 2005; a transition period of up
to 13 years, during which the incumbent utility must provide
default service for customers who do not change suppliers unless an
alternative default supplier is selected through a WVPSC-sponsored
bidding process; capped and fixed rates for the 13 year transition
period as discussed below; deregulation of metering and billing; a
0.5 mills per kwh wires charge applicable to all retail customers
for the period January 1, 2001 through December 31, 2010 intended
to provide for recovery of stranded cost including net regulatory
assets; and establishment of a rate stabilization deferred balance
by the Company of $76 million by the end of year ten of the
transition period to be used as determined by the WVPSC to offset
prices paid in the eleventh, twelfth, and thirteenth year of the
transition period by residential and small commercial customers
that do not choose a supplier.

     Default rates for residential and small commercial customers
are capped for four years after the starting date and then
increased as specified in the plan for the next six years.  In
years eleven, twelve and thirteen of the transition period, the
power supply rate shall equal the market price of comparable power.
Default rates for industrial and large commercial customers are
discounted by 1% for four and a half years, beginning July 1, 2000,
and then increased at pre-defined levels for the next three years.
After seven years the power supply rate for industrial and large
commercial customers will be market based.

Regulatory/Restructuring Accounting

     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 cost-based regulated utilities in accordance with
regulatory actions to match expenses and revenues.  In order to
maintain net regulatory assets on the balance sheet, SFAS 71
requires that rates charged to customers be cost-based and provide
for the probable recovery of regulatory assets over future
accounting periods.  Management has concluded that as of December
31, 1999 the requirements to apply SFAS 71 continue to be met for
all jurisdictions.  However, the recent legislation in Virginia
will result in the discontinuance of SFAS 71 regulatory accounting
for the generation portion of the Virginia jurisdiction.  When the
restructuring plan is enacted into law it will result in the
discontinuance of SFAS 71 regulatory accounting for the generation
portion of the West Virginia jurisdiction.

     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 did not anticipate or
provide accounting guidance for an extended transition period and
for recovery of stranded costs during and after a transition period
through a wires charge or regulated distribution rates.  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 requires 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
transition to competitive market pricing from cost-based regulated
rates and/or a rate order is issued containing sufficient detail
for the utility to reasonably determine what the restructuring plan
would entail and how it will affect the utility's financial
statements.  The EITF indicated that the cessation of application
of SFAS 71 regulatory accounting would require that regulatory
assets and impaired stranded plant cost applicable to the portion
of the business that was no longer cost-based regulated, be written
off unless they are recoverable in the future through transition
rates and/or post-transition cost-based regulated rates.

Potential For Write Offs In Virginia And West Virginia
Jurisdictions

     The Company's accounting for generation will  continue to be
in accordance with SFAS 71 in the Virginia jurisdiction and will
continue to be considered to be cost-based regulated for accounting
purposes until the amount of transition rates and stranded cost
wires charges are determined and known.  The establishment of
transition rates and wire charges should enable management to
determine the Company's ability to recover stranded costs including
regulatory assets and transition costs, a requirement under EITF
97-4 to discontinue application of SFAS 71.  The application of
SFAS 71 will be discontinued for the Virginia retail jurisdictional
portion of the Company's generation business when the capped rates
and the wires charge are known in Virginia which is expected to
occur by the fourth quarter of 2000.  In the  West Virginia
jurisdiction accounting for generation will continue to be in
accordance with SFAS 71 and the generation business will continue
to be considered to be cost-based regulated for accounting purposes
until the proposed restructuring plan is enacted into law.  The
application of SFAS 71 for the generation portion of the West
Virginia jurisdiction will be discontinued when the restructuring
plan is enacted into law and when the WVPSC approves the rate
stipulation filed with the Commission.  Together these two
documents provide sufficient information for management to
determine the impact of restructuring on the Company's financial
statements.

     Upon the discontinuance of SFAS 71 the Company will have to
write off its Virginia and West Virginia jurisdictional generation-related
regulatory assets to the extent that they cannot be
recovered under the frozen transition rates and stranded costs
distribution wires charges and record any asset accounting
impairments.  An impairment loss would be recorded to the extent
that the cost of generation assets cannot be recovered through non-discounted
generation-related revenues during the transition period
and future market prices.  Absent the determination in the
legislative or regulatory process of transition rates, any wires
charge and other pertinent information, it is not possible at this
time for management to determine if any of the Company's generating
assets are impaired for accounting purposes on an undiscounted cash
flow basis.

     The amount of regulatory assets recorded on the books at
December 31, 1999 applicable to the Virginia and West Virginia
retail jurisdictional generation business before related tax
effects is estimated to be $64 million and $131 million,
respectively.  Based on current projections of future market
prices, the Company does not anticipate that it will experience
material tangible asset accounting impairment write-offs.  Whether
the Company will experience material regulatory asset write-offs
will depend on whether the capped transition rates and allowed
wires charges in Virginia and West Virginia will permit their
recovery.

     An estimated determination of whether the Company will
experience any asset impairment loss regarding its Virginia  and
West Virginia retail jurisdictional generating assets and any loss
from the possible inability to recover Virginia and West Virginia
generation related regulatory assets and other transition costs
cannot be made until such time as the transition rates and the
wires charges are determined through the regulatory or legislative
process.  Should the Virginia SCC fail to approve transition rates
and wires charges that are sufficient to provide for  recovery  or
the West Virginia Legislature approves a restructuring plan that
does not provide for recovery of the Company's generation-related
regulatory assets, any other stranded costs and transition costs,
it could have a material adverse effect on results of operations,
cash flows and possibly financial condition.

     The Company's firm wholesale sales are a relatively small part
of its business and are still under cost-of-service contracts.
Customer choice and competition for these sales could also
ultimately result in adverse impacts on results of operations and
cash flows depending on the future market prices of electricity.

Environmental Concerns and Issues

     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 cost effective
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 while
providing a vital commodity, electricity, to our customers at a
fair price.

Air Quality

     In 1998 United States (U.S.) Environmental Protection Agency
(Federal EPA) issued a final rule which requires substantial
reductions in nitrogen oxide (NOx) emissions in 22 eastern states,
including the states in which the Company's generating plants are
located.  A number of utilities, including the Company, filed
petitions seeking a review of the final rule in the U.S. Court of
Appeals for the District of Columbia Circuit (Appeals Court).  On
March 3, 2000, the Appeals Court issued a decision generally
upholding Federal EPA's final rule on NOx emission reductions.

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

     On December 17, 1999, Federal EPA issued a revised Section 126
Rule requiring 392 industrial plants, including certain generating
plants owned by the Company, to reduce their NOx emissions by May
1, 2003.  This rule approves petitions of four northeastern states
which contend that their failure to meet Federal EPA smog standards
is due to coal-fired generating plants in upwind states, including
many of the Company's plants, and not their automobiles and other
local sources.

     Preliminary estimates indicate that compliance with the
Federal EPA's final rule on NOx emission reductions that was upheld
by the Appeals Court could result in required capital expenditures
of approximately $365 million for the Company.  It should be noted,
however, that compliance costs cannot be estimated with certainty
since 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 compliance costs are recovered from customers
through regulated rates, unbundled generation transition rates,
wires charges and the future market price of electricity, such
compliance costs will have an adverse effect on future results of
operations, cash flows and possibly financial condition.

Federal EPA Complaint and Notice of Violation

     Under the Clean Air Act, if a plant undergoes a major
modification that results in a significant emissions increase,
permitting requirements might be triggered and the plant may be
required to install additional pollution control technology.  This
requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and
efficient operation of the plant.

     On November 3, 1999, the Department of Justice, at the request
of Federal EPA, filed a complaint in the U.S. District Court for
the Southern District of Ohio that alleges the Company and its
affiliates in the AEP System made modifications to certain of their
coal-fired generating plants over the course of the past 25 years
that extend their operating lives or increase their generating
capacity in violation of the Clean Air Act.  Federal EPA also
issued Notices of Violation to the Company and its affiliates in
the AEP System alleging violations of certain provisions of the
Clean Air Act at certain plants.  A number of unaffiliated
utilities also received Notices of Violation, complaints or
administrative orders.

     The states of New Jersey, New York and Connecticut were
subsequently allowed to join Federal EPA's action against the
Company under the Clean Air Act. On November 18, 1999, a number of
environmental groups filed a lawsuit against power plants owned by
the Company and its affiliates in the AEP System alleging similar
violations to those in the Federal EPA complaint and Notices of
Violation.  This action has been consolidated with the Federal EPA
action.  The complaints and Notices of Violation named four of the
Company's six coal-fired generating plants. Management believes its
maintenance, repair and replacement activities were in conformity
with the Clean Air Act provisions and intends to vigorously pursue
its defense of this matter.

     The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997).  Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts all of Federal EPA's contentions,
could be  substantial.  In the event the Company does not prevail,
any capital and operating costs of additional pollution control
equipment that may be required as well as any penalties imposed
would adversely affect future results of operations, cash flows and
possibly financial condition unless such costs can be recovered
through regulated rates, approved unbundled transition generation
rates, wires charges and future market prices for electricity.

Financial Condition

     The Company issued $230 million principal amount of long-term
obligations in 1999 at interest rates ranging from 6.05% to 7.45%
and received from its parent a $50 million capital contribution.
The principal amount of long-term debt retirements, including
maturities, totaled $117 million with interest rates ranging from
7% to 8.43%.  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 $225 million in 1999
and $226 million in 1998.  Management estimates construction
expenditures for the next three years to be $839 million.  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 AEP Co., Inc.  Approximately 70% of
the construction expenditures for the next three years are expected
to be financed with internally generated funds.

<PAGE>
     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, 1999, $1,056 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, 1999, the
mortgage bonds and preferred stock coverage ratios were 5.29 and
1.89, 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.  Policies and
procedures have been established to identify, access and manage
market risk exposures including the use of a risk measurement model
which calculates Value at Risk (VaR).  The VaR is based on the
variance-covariance method using historical prices to estimate
volatilities and correlations and assuming a 95% confidence level
and a three-day holding period.  Throughout 1999 and 1998, the
Company's share of the highest, lowest and average quarterly VaR in
the wholesale trading portfolio was less than $4 million and $3
million, respectively.  Based on this VaR analysis, at December 31,
1999 a near term change in electricity commodity prices is not
expected to have a material effect on the Company's results of
operations, cash flows or financial condition.

     The Company is exposed to changes in interest rates primarily
due to short-term and long-term borrowings to fund its business
operations.  The debt portfolio has fixed and variable interest
rates with terms from one day to 39 years and an average duration
of eight years at December 31, 1999.  The Company measures interest
rate market risk exposure utilizing a VaR model.  The model is
based on a 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 weekly
prices.  The risk of potential loss in fair value attributable to
the Company's exposure to interest rates, primarily related to
long-term debt with fixed interest rates, was $218 million at
December 31, 1999 and $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.

     Inflation affects the Company's cost of replacing utility
plant and the cost of operating and maintaining its plant.  The
rate-making process limits 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.

Litigation

Corporate Owned Life Insurance

     The IRS agents auditing the AEP System's consolidated federal
income tax returns requested a ruling from their National Office
that certain interest deductions claimed by the Company relating to
a COLI program should not be allowed.  As a result of a suit filed
by the Company in U.S. District Court (discussed below) this
request for ruling was withdrawn by the IRS agents.  Adjustments
have been or will be proposed by the IRS disallowing COLI interest
deductions for taxable years 1991-96.  A disallowance of the COLI
interest deductions through December 31, 1999 would reduce earnings
by approximately $79 million (including interest).

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

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

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

Other Matters

Superfund

     By-products from the generation of electricity include
materials such as ash, slag and sludge.  Coal combustion by-products, which
constitute the overwhelming percentage of these
materials, are typically disposed of or treated in captive disposal
facilities or are beneficially utilized.  In addition, our
generating plants and transmission and distribution facilities have
used asbestos, 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 Federal EPA to
administer the clean-up programs.  As of year-end 1999, there are
two sites for which the Company has received information requests
which could lead to potentially responsible party (PRP)
designations.  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
identified sites.  However, if for reasons not currently identified
significant costs are incurred for cleanup, future results of
operations, cash flows and possibly financial condition would be
adversely affected unless the costs can be recovered from
customers.

     The Clean Air Act Amendments (CAAA) required Federal EPA to
issue rules to implement the law.  In 1996 Federal EPA issued final
rules governing NOx emissions that must be met after January 1,
2000 (Phase II of the CAAA).  The final rules required substantial
reductions in NOx emissions from certain types of boilers including
those in the power plants of the Company and its affiliates in the
AEP System.  To comply with Phase II of CAAA, the Company installed
NOx emission control equipment on certain units and switched fuel
at other units.  The Company is operating under the Phase II rules
which require reporting at the end of each year.  The Company does
not anticipate any material problems complying with the rules.

<PAGE>
     At the Third Conference of the Parties to the United Nations
Framework Convention on Climate Change held in Kyoto, Japan in
December 1997 more than 160 countries, including the U.S.,
negotiated a treaty requiring legally-binding reductions in
emissions of greenhouse gases, chiefly carbon dioxide, which many
scientists believe are contributing to global climate change.  The
treaty, which requires the advice and consent of the U.S. Senate
for ratification, would require the U.S. to reduce greenhouse gas
emissions seven percent below 1990 levels in the years 2008-2012.
Although the U.S. 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, methodologies and guidelines
of the treaty's emissions trading and 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 November
2000.  We will continue to work with the Administration and
Congress to develop responsible 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.  It is management's
belief, that the Kyoto protocol is unlikely to be ratified or
implemented in the U.S. in its current form.

Year 2000 Readiness Disclosure

     On or about midnight on December 31, 1999, digital computing
systems could have produced erroneous results or failed, unless
these systems had been modified or replaced, because such systems
have been programmed incorrectly and interpreted 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 or otherwise incorrectly
interpret a year 2000 date.

     The Company has not experienced any material failures of
generation or delivery of electric energy due to Year 2000 because
of the AEP System's preparations.  Such preparations included the
modification or replacement of certain computer hardware and
software to minimize Year 2000-related failures and repair.  This
included 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 was 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 sought written assurances from
third parties regarding their state of Year 2000 readiness.
Another issue addressed was the impact of electric power grid
problems that may have occurred outside of our transmission system.

     Through December 31, 1999, the Company's share of the AEP
System's expenditures on the Year 2000 project was $14 million.
Most Year 2000 costs were for IT contractors and consultants and
for salaries of internal IT professionals and were expensed;
however, in certain cases the Company acquired hardware and new
software that was capitalized.

New Accounting Standards

     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 and reviewing the Company's contracts
and transactions to determine the impact on the Company's results
of operations, cash flows and financial condition when SFAS 133 is
adopted on January 1, 2001.


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


                                                               Year Ended December 31,
                                                         1999           1998           1997
                                                                   (in thousands)
<S>                                                   <C>            <C>            <C>
OPERATING REVENUES                                    $1,650,937     $1,672,244     $1,628,515

OPERATING EXPENSES:
 Fuel                                                    444,711        437,500        403,777
 Purchased Power                                         254,100        303,116        311,514
 Other Operation                                         249,616        254,718        246,785
 Maintenance                                             123,834        134,856        112,873
 Depreciation and Amortization                           148,874        143,809        137,670
 Taxes Other Than Federal Income Taxes                   117,641        116,070        116,590
 Federal Income Taxes                                     70,925         53,632         59,312
          Total Operating Expenses                     1,409,701      1,443,701      1,388,521

OPERATING INCOME                                         241,236        228,543        239,994

NONOPERATING INCOME (LOSS)                                 8,096         (8,301)          (222)

INCOME BEFORE INTEREST CHARGES                           249,332        220,242        239,772

INTEREST CHARGES                                         128,840        126,912        119,258

NET INCOME                                               120,492         93,330        120,514

PREFERRED STOCK DIVIDEND REQUIREMENTS                      2,706          2,497          7,006

EARNINGS APPLICABLE TO COMMON STOCK                   $  117,786     $   90,833     $  113,508
</TABLE>
See Notes to Consolidated Financial Statements.

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


                                                                           December 31,
                                                                      1999             1998
                                                                          (in thousands)
ASSETS
<S>                                                                <C>              <C>
ELECTRIC UTILITY PLANT:
   Production                                                      $2,014,968       $1,979,180
   Transmission                                                     1,151,377        1,118,726
   Distribution                                                     1,741,685        1,641,523
   General                                                            247,798          228,464
   Construction Work in Progress                                      107,123          119,466
                 Total Electric Utility Plant                       5,262,951        5,087,359
   Accumulated Depreciation and Amortization                        2,079,490        1,984,856
                 NET ELECTRIC UTILITY PLANT                         3,183,461        3,102,503


OTHER PROPERTY AND INVESTMENTS                                        160,546          111,020


CURRENT ASSETS:
   Cash and Cash Equivalents                                           64,828            7,755
   Accounts Receivable:
      Customers                                                       109,525          122,746
      Affiliated Companies                                             37,827           35,802
      Miscellaneous                                                     9,154            8,572
      Allowance for Uncollectible Accounts                             (2,609)          (2,234)
   Fuel - at average cost                                              58,161           49,826
   Materials and Supplies - at average cost                            56,917           60,440
   Accrued Utility Revenues                                            53,418           45,985
   Energy Marketing and Trading Contracts                             143,777           22,436
   Prepayments                                                          7,713            8,151
                 TOTAL CURRENT ASSETS                                 538,711          359,479


REGULATORY ASSETS                                                     436,894          433,516

DEFERRED CHARGES                                                       34,788           40,520
                     TOTAL                                         $4,354,400       $4,047,038
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES


                                                                           December 31,
                                                                      1999             1998
                                                                          (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                                                    714,259          663,633
   Retained Earnings                                                  175,854          179,461
                Total Common Shareholder's Equity                   1,150,571        1,103,552
   Cumulative Preferred Stock:
       Not Subject to Mandatory Redemption                             18,491           19,359
       Subject to Mandatory Redemption                                 20,310           22,310
   Long-term Debt                                                   1,539,302        1,472,451
                TOTAL CAPITALIZATION                                2,728,674        2,617,672

OTHER NONCURRENT LIABILITIES                                          132,130          120,281

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                                 126,005           80,004
   Short-term Debt                                                    123,480           76,400
   Accounts Payable - General                                          59,150           60,569
   Accounts Payable - Affiliated Companies                             42,459           50,313
   Taxes Accrued                                                       49,038           35,719
   Customer Deposits                                                   12,898           14,123
   Interest Accrued                                                    19,079           19,990
   Revenue Refunds Accrued                                               -              95,267
   Energy Marketing and Trading Contracts                             140,279           24,076
   Other                                                               71,044           78,808
                TOTAL CURRENT LIABILITIES                             643,432          535,269

DEFERRED INCOME TAXES                                                 671,917          643,711

DEFERRED INVESTMENT TAX CREDITS                                        57,259           62,231

DEFERRED CREDITS                                                      120,988           67,874

COMMITMENTS AND CONTINGENCIES (Notes 5 and 6)

                    TOTAL                                          $4,354,400       $4,047,038

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


                                                                Year Ended December 31,
                                                            1999          1998          1997
                                                                     (in thousands)
<S>                                                      <C>           <C>           <C>
OPERATING ACTIVITIES:
   Net Income                                            $ 120,492     $  93,330     $ 120,514
   Adjustments for Noncash Items:
      Depreciation and Amortization                        149,791       144,967       138,975
      Deferred Federal Income Taxes                         13,033        (2,338)       (5,117)
      Deferred Investment Tax Credits                       (4,972)       (5,265)       (5,181)
      Deferred Power Supply Costs (net)                     35,955        30,081        12,310
      Provision for Rate Refunds                             4,818       (31,019)        7,601
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                             10,989        (1,562)       (3,990)
      Fuel, Materials and Supplies                          (4,812)       (5,006)        3,950
      Accrued Utility Revenues                              (7,433)        5,223           635
      Accounts Payable                                      (9,273)       14,066        10,924
      Taxes Accrued                                         13,319        (5,830)          614
      Revenue Refunds Accrued                              (95,267)       91,956        (2,272)
   Payment of Disputed Tax and Interest Related to COLI     (4,124)      (68,316)         -
   Net Book Value of Assets Sold                           (24,373)       (9,286)      (14,036)
   Change in Operating Reserves                              7,451        10,052         8,872
   Net Change in Unrealized (Gain) Loss
    on Forward Commitments                                 (14,531)        3,529          (194)
   Other (net)                                             (23,174)        9,582         6,908
        Net Cash Flows From Operating Activities           167,889       274,164       280,513

INVESTING ACTIVITIES:
   Construction Expenditures                              (211,416)     (204,869)     (218,074)
   Proceeds from Sales of Property and Other                19,296         2,930         4,971
        Net Cash Flows Used For Investing Activities      (192,120)     (201,939)     (213,103)

FINANCING ACTIVITIES:
   Capital Contributions from Parent Company                50,000        50,000        40,000
   Issuance of Long-term Debt                              227,236       211,944       183,257
   Retirement of Cumulative Preferred Stock                 (2,675)         (294)     (183,875)
   Retirement of Long-term Debt                           (116,688)     (157,973)      (56,379)
   Change in Short-term Debt (net)                          47,080       (53,900)       69,600
   Dividends Paid on Common Stock                         (121,392)     (118,916)     (114,436)
   Dividends Paid on Cumulative Preferred Stock             (2,257)       (2,278)       (5,890)
        Net Cash Flows From (Used For)
          Financing Activities                              81,304       (71,417)      (67,723)

Net Increase (Decrease) in Cash and Cash Equivalents        57,073           808          (313)
Cash and Cash Equivalents January 1                          7,755         6,947         7,260
Cash and Cash Equivalents December 31                    $  64,828     $   7,755     $   6,947
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings


                                                                   Year Ended December 31,
                                                               1999         1998         1997
                                                                       (in thousands)
<S>                                                          <C>          <C>          <C>
Retained Earnings January 1                                  $179,461     $207,544     $208,472
Net Income                                                    120,492       93,330      120,514
                                                              299,953      300,874      328,986
Deductions:
   Cash Dividends Declared:
     Common Stock                                             121,392      118,916      114,436
     Cumulative Preferred Stock:
        4-1/2% Series                                             850          875          892
        5.90%  Series                                             425          455          455
        5.92%  Series                                             364          364          364
        6.85%  Series                                             579          579          579
        7.80%  Series                                            -            -             931
                Total Cash Dividends Declared                 123,610      121,189      117,657

   Capital Stock Expense                                          489          224        3,785
                Total Deductions                              124,099      121,413      121,442

Retained Earnings December 31                                $175,854     $179,461     $207,544
</TABLE>
See Notes to Consolidated Financial Statements.

<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 896,000 retail customers in southwestern Virginia
and southern West Virginia and does business as American Electric
Power (AEP).  Under the terms of the AEP System Power Pool (AEP
Power Pool) and the AEP System Transmission Equalization Agreement,
the Company's generation and transmission facilities are operated
in conjunction with the facilities of certain other AEP affiliated
utilities as an integrated utility system.  The Company as a member
of the AEP Power Pool shares in the revenues and costs of Power
Pool wholesale sales to neighboring utility systems and power
marketers. The Company also sells wholesale power to
municipalities.

    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 and transmission 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 1999, 1998 and 1997 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
1999, 1998 and 1997 are as follows:

                   Annual Composite
Functional Class   Depreciation
of Property        Rates
                   1999   1998   1997
Production:
  Steam            3.4%   3.4%   3.4%
  Hydro            2.9%   2.8%   2.8%
Transmission       2.2%   2.2%   2.2%
Distribution       3.3%   3.3%   3.3%
General            3.1%   3.1%   3.1%


<PAGE>
    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 was practiced for the over
and under collection of fuel, AEP Power Pool capacity charges and
certain transmission revenue for the period November 1996 through
December 1999.  Although a cumulative over and under recovery
balance has been 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 ratepayers and are included
in operating income annually.

    Under a pending rate settlement agreement, beginning January
1, 2000 deferral accounting for over or under recovery of fuel
would be discontinued and the current cumulative overrecovery
balance of $65.9 million shall remain on the Company's books as a
regulatory liability.  (see Note 4 "Rate Matters".)  In addition,
the cumulative overrecovery balance would be used to reduce
unrecoverable generation-related regulatory assets and, to the
extent possible, any additional cost or obligations that
deregulation may impose (see Note 3 for discussion of West Virginia
Restructuring Plan).

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

Energy Marketing and Trading Transactions

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

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

    In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's Emerging Issues Task Force Consensus
(EITF) 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities".  The EITF requires that all energy
trading contracts be marked-to-market.  The effect on the
Consolidated Statements of Income of marking open trading contracts
to market is deferred as regulatory assets or liabilities for those
open trading transactions within the AEP Power Pool's marketing
area that are included in cost of service on a settlement basis for
ratemaking purposes in the Company's non-Virginia jurisdictions.
A Virginia jurisdiction net mark-to-market after-tax gain of $3
million as of December 31, 1999 is included in net income as a
result of an agreed prohibition against establishing new regulatory
assets in a February 1999 Virginia SCC approved settlement
agreement.  The Company's share of non-regulated open trading
contracts are accounted for on a mark-to-market basis in
nonoperating income.  Unrealized mark-to-market gains and losses
from trading activities are reported as assets and liabilities,
respectively.  The adoption of the EITF did not have a material
effect on results of operations, cash flows or financial condition.

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

    See Note 9 - Financial Instruments, Credit and Risk Management
for further discussion.

<PAGE>
Reclassification

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

Income Taxes

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

Investment Tax Credits

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

Debt and Preferred Stock

    Gains and losses from the reacquisition of debt are deferred
as regulatory assets and amortized over the remaining term of the
reacquired debt in accordance with rate-making treatment.  If debt
is refinanced, reacquisition costs are deferred except in the
Virginia jurisdiction 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.

<PAGE>
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.  Management
has reviewed all the evidence currently available and concluded
that the Company continues to meet the requirements to apply SFAS
71.  In the event a portion of the Company's business 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.  (See Note 3 "Restructuring
Legislation".)

    Recognized regulatory assets and liabilities are comprised of
the following:
                                    December 31,
                                 1999          1998
                                   (in thousands)
Regulatory Assets:
  Amounts Due From Customers
    For Future Income Taxes    $389,922      $374,750
  Unamortized Loss On
    Reacquired Debt              20,828        22,827
  Deferred Storm Damage           6,619        13,424
  Other                          19,525        22,515
  Total Regulatory Assets      $436,894      $433,516

Regulatory Liabilities:
  Deferred Investment Tax
    Credits                    $ 57,259      $ 62,231
  Other*                         80,312        53,955
  Total Regulatory Liabilities $137,571      $116,186

* Included in Deferred Credits on Consolidated Balance Sheets.


<PAGE>
3. RESTRUCTURING LEGISLATION:

Virginia

    In March 1999 a law was enacted in Virginia to restructure the
electric utility industry.  Under the restructuring law a
transition to choice of electricity 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.

    The law also provides an opportunity for recovery of just and
reasonable net stranded generation costs.  The mechanisms in the
Virginia law for net stranded cost recovery are: a capping of rates
until as late as July 1, 2007, and the application of a wires
charge upon customers who depart the incumbent utility in favor of
an alternative supplier prior to the termination of the rate cap.
The law provides for the establishment of capped rates prior to
January 1, 2001 and the establishment of a wires charge by the
fourth quarter of 2001.

    Management has concluded that as of December 31, 1999 the
requirements to apply SFAS 71 continue to be met.  The Company's
Virginia rates for generation will continue to be cost-based
regulated until the establishment of capped rates and the wires
charge as provided in the law.  The establishment of capped rates
and the wires charge should enable management to determine its
ability to recover stranded costs, a requirement to discontinue
application of SFAS 71.

    When the capped rates and the wires charge are established in
Virginia, the application of SFAS 71 will be discontinued for the
Virginia retail jurisdictional portion of the Company's generating
business.  At that time the Company will have to write-off its
generation-related regulatory assets to the extent that they cannot
be recovered under the capped rates and wires charges approved by
the Virginia SCC under the provisions of the restructuring law and
record any asset impairments in accordance with SFAS 121,
"Accounting for the Impairment of Long-lived Assets and for Long-lived Assets
to Be Disposed Of."  An impairment loss would be
recorded to the extent that the cost of impaired assets cannot be
recovered through generation-related revenues during the transition
period and future market prices.  Absent the determination through
the regulatory process, wires charges and other pertinent
information of capped rates as required by the restructuring law,
it is not possible at this time for management to determine if any
generation-related assets are impaired in accordance with SFAS 121
and if generation-related regulatory assets will be recovered.  The
amount of regulatory assets recorded on the books applicable to the
Company's Virginia retail generating business at December 31, 1999
is estimated to be $64.1 million before related tax effects.

    Should it not be possible under the Virginia law to recover all
or a portion of the generation-related regulatory assets and/or
tangible generating assets, it could have a material adverse impact
on results of operations and cash flows.  An estimated
determination of whether the Company will experience any asset
impairment loss regarding its Virginia retail jurisdictional
generating assets and any loss from a possible inability to recover
generation-related regulatory assets and other transition costs
cannot be made until such time as the Company completes economic
studies to estimate an asset impairment and until the transition
period capped rates and the wires charge are determined under the
law, which is expected to occur by the fourth quarter of 2000.

West Virginia

    On January 28, 2000, the WVPSC issued an order approving an
electricity restructuring plan for West Virginia.  The
restructuring plan has been submitted to the West Virginia
Legislature for approval or rejection.

    The provisions of the proposed restructuring plan provide for
customer choice to begin on January 1, 2001, or at a later date set
by the WVPSC after all necessary rules are in place (the "starting
date"); deregulation of generation assets occurring on the starting
date; functional separation of the generation, transmission and
distribution businesses on the start date and their legal corporate
separation no later than January 1, 2005; a transition period of up
to 13 years, during which the incumbent utility must provide
default service for customers who do not change suppliers unless an
alternative default supplier is selected through a WVPSC-sponsored
bidding process; capped and fixed rates for the 13 year transition
period as discussed below; deregulation of metering and billing; a
0.5 mills per kwh wires charge applicable to all retail customers
for the period January 1, 2001 through December 31, 2010 intended
to provide for recovery of any stranded cost including net
regulatory assets; and establishment of a rate stabilization
deferred balance of $75.6 million by the end of year ten of the
transition period to be used as determined by the WVPSC to offset
prices paid in the eleventh, twelfth, and thirteenth year of the
transition period by residential and small commercial customers
that do not choose a supplier.

    Default rates for residential and small commercial customers
are capped for four years after the starting date and then
increased as specified in the plan for the next six years.  In
years eleven, twelve and thirteen of the transition period, the
power supply rate shall equal the market price of comparable power.
Default rates for industrial and large commercial customers are
discounted by 1% for four and a half years, beginning July 1, 2000,
and then increased at pre-defined levels for the next three years.
After seven years the power supply rate for industrial and large
commercial customers will be market based.

<PAGE>
    Management has concluded that as of December 31, 1999 the
requirements to apply SFAS 71 continue to be met.  The Company's
West Virginia rates for generation will continue to be cost-based
regulated until the restructuring plan is enacted into law.  At
that time, management should be able to determine its ability to
recover stranded costs, a requirement to discontinue application of
SFAS 71.

    When the restructuring plan is enacted into law, the
application of SFAS 71 will be discontinued for the West Virginia
retail jurisdictional portion of the Company's generating business.
At that time the Company will have to write-off its generation-related
regulatory assets to the extent that they cannot be
recovered under the provisions of the approved restructuring plan
and record any asset impairments in accordance with SFAS 121.  An
impairment loss would be recorded to the extent that the cost of
impaired assets cannot be recovered through generation-related
revenues during the transition period and future market prices.
Absent the approval through the regulatory and legislative
processes of rates and other pertinent information, it is not
possible at this time for management to determine if any
generation-related assets are impaired in accordance with SFAS 121
and if generation-related regulatory assets will be recovered.  The
amount of regulatory assets recorded on the books applicable to the
Company's West Virginia retail generating business at December 31,
1999 is estimated to be $131.1 million before related tax effects.

    Should it not be possible under the West Virginia restructuring
plan to recover all or a portion of the generation-related
regulatory assets and/or tangible generating assets, it could have
a material adverse impact on results of operations and cash flows.
An estimated determination of whether the Company will experience
any asset impairment loss regarding its West Virginia retail
jurisdictional generating assets and any loss from a possible
inability to recover generation-related regulatory assets and other
transition costs cannot be made until such time as the Company
completes economic studies to estimate an asset impairment and
until the restructuring plan is enacted into law and the WVPSC
approves the Joint Stipulation (See Note 4).


4. RATE MATTERS:

West Virginia

    On May 12, 1999, the Company filed with the WVPSC for a base
rate increase of $50 million annually and a reduction in expanded
net energy cost (ENEC) rates of $38 million annually.  On February
7, 2000, APCo and other parties to the proceeding filed a Joint
Stipulation and Agreement for Settlement (Joint Stipulation) with
the WVPSC for approval.  The Joint Stipulation's main provisions
include no change in either base or ENEC rates effective January 1,
2000 from those base and ENEC rates in effect from November 1, 1996
until December 31, 1999 (these rates provide for recovery of
regulatory assets including any generation related regulatory
assets of approximately 0.5 mills per kwh); annual ENEC recovery
proceedings are suspended and deferral accounting for over or under
recovery is discontinued effective January 1, 2000; the net
cumulative deferred ENEC recovery balance as established by a WVPSC
order on December 27, 1996, which is $65.9 million at December 31,
1999, shall remain on the books as a regulatory liability.
However, if deregulation of generation occurs in West Virginia
(WV), APCo will use this regulatory liability to reduce
unrecoverable generation-related regulatory assets and, to the
extent possible, any additional costs or obligations that
deregulation may impose.  APCo's share of any net savings from the
pending merger between AEP and Central and South West Corporation
prior to December 31, 2004 shall be retained by APCo.  All costs
incurred in the merger that are allocated to APCo, whether the
merger is consummated or not, shall be fully charged to expense as
of December 31, 2004 and shall not be included in any WV rate
proceeding after that date.  After December 31, 2004 any savings
related to the merger will be reflected in rates in any future rate
proceeding before the WVPSC to establish distribution rates or to
adjust rate caps during the transition to market based rates.  If
deregulation of generation occurs in WV the net retained generation
related merger savings should be used to recover any generation
related regulatory assets that are not recovered under the
provisions of the Joint Stipulation and the mechanisms provided for
in the deregulation legislation and, to the extent possible, to
recover any additional costs or obligations that deregulation may
impose on APCo.  Regardless of whether the net cumulative deferred
ENEC recovery balance and the net merger savings are sufficient to
offset all of APCo's generation related regulatory assets, under
the terms of the Joint Stipulation there will be no further
explicit adjustment to APCo's rates to provide for recovery of
generation-related regulatory assets beyond the above discussed
specific adjustments provided in the Joint Stipulation and the 0.5
mills per kwh wires charge in the WV Restructuring Plan (see Note
3 for discussion of WV Restructuring Plan).

FERC

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

    On July 9, 1996, the AEP System companies filed an Open Access
Transmission Tariff conforming with the FERC's pro-forma
transmission tariff, subject to the resolution of certain pricing
issues.  The 1996 tariff incorporated transmission rates which were
the result of a settlement of a pending rate case, but which were
being collected subject to refund from certain customers who
opposed the settlement and continued to litigate the reasonableness
of AEP's transmission rates.  On July 30, 1999, the FERC issued an
order in the litigated rate case which would reduce AEP's rates for
the affected customers below the settlement rate.  AEP and certain
of the affected customers sought rehearing of the Commission's
Order.  The Company made a provision in September 1999 for the
refund including interest.

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


5. COMMITMENTS AND CONTINGENCIES:

Construction and Other Commitments

    Substantial construction commitments have been made to support
the Company's utility operations and are estimated to be $839
million for 2000-2002.

    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.

Federal EPA Complaint and Notice of Violation - Under the Clean Air
Act, if a plant undertakes a major modification that directly
results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional
pollution control technology.  This requirement does not apply to
activities such as routine maintenance, replacement of degraded
equipment or failed components, or other repairs needed for the
reliable, safe and efficient operation of the plant.

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

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

    The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997).  Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts Federal EPA's contentions, could be
substantial.

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

    In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that may
be required as well as any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated
rates, and as generation is deregulated through future market
prices for energy.

Litigation

    The Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns requested a ruling
from their National Office that certain interest deductions claimed
by the Company relating to AEP's corporate owned life insurance
(COLI) program should not be allowed.  As a result of a suit filed
in U.S. District Court (discussed below) this request for ruling
was withdrawn by the IRS agents.  Adjustments have been or will be
proposed by the IRS disallowing COLI interest deductions for
taxable years 1991-96.  A disallowance of the COLI interest
deductions through December 31, 1999 would reduce earnings by
approximately $79 million (including interest).

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

    In order to resolve this issue, the Company filed suit against
the United States in the U.S. District Court for the Southern
District of Ohio in March 1998.  In 1999 a U.S. tax court judge
decided in the Winn-Dixie Stores v. Commissioner case that a
corporate taxpayer's COLI interest deductions should be disallowed.
Notwithstanding the Tax Court's decision in Winn-Dixie, management
has made no provision for any possible earnings impact from this
matter because it believes, and has been advised by outside
counsel, that it has a meritorious position and will vigorously
pursue 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.


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

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

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

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

    Preliminary estimates indicate that compliance with the NOx
rule upheld by the Appeal Court could result in required capital
expenditures of approximately $365 million for the Company.  Since
compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the Company's
preliminary estimate depending upon the compliance alternatives
selected to achieve reductions in NOx emissions.  Unless such costs
are recovered from customers through regulated rates, transition
charges and/or reflected in the future market price of electricity,
they will have an adverse effect on future results of operations
and cash flows and possibly financial condition.


7. RELATED PARTY TRANSACTIONS:

    Benefits and costs of the AEP System's generating plants are
shared by members of the AEP Power Pool of which the Company is a
member.  Under 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 $41.9 million in 1999, $36.9 million
in 1998 and $40.1 million in 1997 for energy supplied to the AEP
Power Pool.

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

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

Capacity Charges          $ 67,894   $ 83,536  $128,680
Energy Charges              63,097     97,226   149,113

     Total                $130,991   $180,762  $277,793

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

                             Year Ended December 31,
                            1999       1998      1997
                                  (in thousands)
Operating Revenues        $148,803   $193,441  $128,041
Purchased Power Expense    101,345    111,909    27,330
Nonoperating Income (Loss)   3,088    (11,179)      (81)

    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
$57.2 million in 1999, $56.8 million in 1998 and $57.9 million in
1997.

    Purchased power expense includes $21.7 million in 1999, $10.4
million in 1998 and $6.4 million in 1997 of energy bought from the
Ohio Valley Electric Corporation, an affiliated company that is not
a member of the AEP Power Pool.

    The Company participates in the AEP Transmission Equalization
Agreement along with other AEP System electric operating utility
companies.  This agreement combines certain AEP System companies'
investments in transmission facilities and shares the costs of
ownership in proportion to the System companies' respective peak
demands.  Pursuant to the terms of the agreement since the
Company's relative investment in transmission facilities is greater
than its relative peak demands in 1999 and 1998 and less than its
relative peak demands in 1997, other operation expense includes
equalization charges (credits) of $(8.3) million, $(2.4) million
and $8.4 million in 1999, 1998 and 1997, respectively.

<PAGE>
    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 companies 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.


8. 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 1.  For the years ended December 31, 1999, 1998 and 1997, all
of the Company's revenues are derived from the generation, sale and
distribution of electricity in the United States.


9.  FINANCIAL INSTRUMENTS, CREDIT AND RISK MANAGEMENT

    The Company is subject to market risk as a result of changes
in electricity commodity prices and interest rates.  The Company
through its membership in the AEP Power Pool participates in a
power marketing and trading operation that manages the exposure to
electricity commodity price movements using physical forward
purchase and sale contracts at fixed and variable prices, and
financial derivative instruments including exchange traded futures
and options, over-the-counter options, swaps and other financial
derivative contracts at both fixed and variable prices.  Physical
forward electricity contracts within the AEP System's traditional
marketing area are recorded on a net basis as operating revenues in
the month when the physical contract settles.  The Company's share
of the net realized gains from these regulated transactions for the
years ended December 31, 1999 and 1998 are $7 million and $33
million, respectively.  These activities were not material in 1997.

    Non-regulated physical forward electricity contracts outside
AEP's traditional marketing area, and all financial electricity
trading transactions where the underlying physical commodity is
outside AEP's traditional market area are marked to market and
recorded in nonoperating income.  The Company's share of the net
income (loss) from these non-regulated trading transactions for the
years ended December 31, 1999 and 1998 are $3 million and $(11)
million, respectively.  These activities were not material in 1997.

    In the first quarter of 1999 the Company adopted EITF 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk
Management Activities".  The EITF requires that all energy trading
contracts be marked-to-market.  The effect on the Consolidated
Statements of Income of marking open regulated trading contracts to
market is deferred as regulatory assets or liabilities for the
portion of those open trading transactions within the AEP Power
Pool's marketing area that are included in cost of service on a
settlement basis for ratemaking purposes in the Company's non-Virginia
jurisdictions.  A Virginia jurisdiction net mark-to-market
pre-tax gain of $5 million as of December 31, 1999 is included in
operating revenues as a result of an agreed prohibition against
establishing new regulatory assets in a February 1999 Virginia SCC
approved settlement agreement.  The unrealized mark-to-market gains
and losses from trading of financial instruments including forward
purchase contracts are reported as assets and liabilities,
respectively.  The adoption of the EITF did not have a material
effect on results of operations, cash flows or financial condition.

    The Company 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 39 years and an
average duration of eight years at December 31, 1999.  A near term
change in interest rates should not materially affect results of
operations or financial position since the Company would not expect
to liquidate its entire debt portfolio in a one year holding
period.

Market Valuation

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

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

                                1999                        1998
                       Book Value  Fair Value      Book Value  Fair Value
                           (in thousands)              (in thousands)
Non-Derivatives

Long-term Debt         $1,665,307  $1,580,600      $1,552,455  $1,638,700

Preferred Stock            20,310      19,700          22,310      23,400

Derivatives
                             1999                             1998
                Notional   Fair     Average      Notional   Fair     Average
                 Amount    Value   Fair Value     Amount    Value   Fair Value
                                   (Dollars in thousands)
Trading Assets

Electric          GWH                              GWH
 NYMEX Futures
  and Options        64  $    535  $    254         -      $  -       $  -
  Physicals      19,953   165,624   150,377       17,556    13,700     12,200
  Options         1,781    11,766    18,461        1,161    10,100     24,300
  Swaps              51       112        90           83     1,000        300

Trading Liabilities

Electric          GWH                              GWH
  NYMEX Futures
   and Options     -         -         -             212    (2,100)      (500)
  Physicals      21,461  (154,364) (144,876)      17,295   (14,800)   (13,900)
  Options         2,557   (12,375)  (16,811)         881    (8,900)   (23,700)
  Swaps              52      (103)      (85)         147    (2,300)      (600)

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.


10. 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.  The amount of severance benefits paid was not significantly
different from the amount accrued.


11. BENEFIT PLANS:

    The Company and its subsidiaries participate in the AEP System
qualified pension plan, a defined benefit plan which covers all
employees.  Net pension costs (credits) for the years ended
December 31, 1999, 1998 and 1997 were $(3.9) million, $0.8 million
and $1.9 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 $19.5 million in 1999,
$16.6 million in 1998 and $17.3 million in 1997.

    A defined contribution employee savings plan required that the
Company make contributions to the plan totaling $4.1 million in
1999, $4.3 million in 1998, and $4 million in 1997.

<TABLE>

<PAGE>
12. FEDERAL INCOME TAXES:

     The details of federal income taxes as reported are as
follows:
<CAPTION>
                                                               Year Ended December 31,
                                                       1999             1998               1997
                                                                   (in thousands)
<S>                                                  <C>              <C>                <C>
Charged (Credited) to Operating Expenses (net):
  Current                                            $64,603          $56,446            $66,810
  Deferred                                             8,981             (143)            (4,801)
  Deferred Investment Tax Credits                     (2,659)          (2,671)            (2,697)
           Total                                      70,925           53,632             59,312
Charged (Credited) to Nonoperating Income (net):
  Current                                             (1,714)          (4,902)            (1,677)
  Deferred                                             4,052           (2,195)              (316)
  Deferred Investment Tax Credits                     (2,313)          (2,594)            (2,484)
           Total                                          25           (9,691)            (4,477)
Total Federal Income Taxes as Reported               $70,950          $43,941            $54,835

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

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

Net Income                                      $120,492            $ 93,330            $120,514
Federal Income Taxes                              70,950              43,941              54,835
Pre-tax Book Income                             $191,442            $137,271            $175,349

Federal Income Taxes on Pre-tax Book Income at
  Statutory Rate (35%)                           $67,005             $48,045             $61,372
Increase (Decrease) in Federal Income Taxes
  Resulting From the Following Items:
    Depreciation                                  12,593              11,667              10,945
    Corporate Owned Life Insurance                  -                 (4,212)             (3,974)
    Removal Costs                                 (3,220)             (4,200)             (4,200)
    Investment Tax Credits (net)                  (4,972)             (5,265)             (5,181)
    Other                                           (456)             (2,094)             (4,127)
Total Federal Income Taxes as Reported           $70,950             $43,941             $54,835

Effective Federal Income Tax Rate                   37.1%               32.0%               31.3%
</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,
                                    1999       1998
                                    (in thousands)

Deferred Tax Assets              $ 173,038  $ 168,898
Deferred Tax Liabilities          (844,955)  (812,609)
  Net Deferred Tax Liabilities   $(671,917) $(643,711)

Property Related Temporary
  Differences                    $(510,143) $(496,464)
Amounts Due From Customers For
  Future Federal Income Taxes     (109,846)  (106,436)
Deferred State Income Taxes        (76,073)   (70,644)
All Other (net)                     24,145     29,833
  Net Deferred Tax Liabilities   $(671,917) $(643,711)


     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 5, management is not aware of any issues for
open tax years that upon final resolution are expected to have a
material adverse effect on results of operations.


13.  COMMON SHAREHOLDER'S EQUITY:

     The Company received from AEP Co., Inc. cash capital
contributions of $50 million in 1999 and 1998, and $40 million in
1997 which were credited to paid-in capital.  In 1999, 1998 and
1997 net changes in paid-in capital of $626,000, $585,000 and
$(2,332,000), 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 1999, 1998 and 1997.  At December 31,
1999 there were no dividend restrictions on retained earnings.  To
pay dividends out of paid-in capital, the Company needs regulatory
approval.

<TABLE>
14.  CUMULATIVE PREFERRED STOCK:
<CAPTION>
     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.


<PAGE>
     The Company redeemed and canceled 500,000 shares of the 7.80%
series subject to mandatory redemption in 1997.

Cumulative Preferred Stock Not Subject to Mandatory Redemption:

            Call Price                                             Shares               Amount
           December 31,      Number of Shares Redeemed          Outstanding          December 31,
Series         1999            Year Ended December 31,       December 31, 1999     1999        1998
                              1999      1998      1997                               (in thousands)
<S>          <C>              <C>       <C>     <C>                <C>           <C>         <C>
4-1/2%       $110.00          8,671     3,878   100,685            184,916       $18,491     $19,359

Cumulative Preferred Stock Subject to Mandatory Redemption:

           Call Price
          December 31,      Number of Shares Redeemed           Outstanding          December 31,
Series(a)     1999            Year Ended December 31,        December 31, 1999      1999       1998
                             1999      1998      1997                                (in thousands)

5.90% (b)   $  (d)          20,000      -      422,900             57,100         $ 5,710    $ 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
                                                                                  $20,310    $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 1999 and 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>
15.  LONG-TERM DEBT AND LINES OF CREDIT:

     Long-term debt by major category was outstanding as follows:

                                    December 31,
                                1999           1998
                                   (in thousands)

First Mortgage Bonds         $  844,472    $  960,597
Installment Purchase
  Contracts                     264,217       234,262
Senior Unsecured Notes          392,844       193,959
Junior Debentures               161,228       161,087
Other Long-term Debt              2,546         2,550
                              1,665,307     1,552,455
Less Portion Due Within
  One Year                      126,005        80,004
   Total                     $1,539,302    $1,472,451

     First mortgage bonds outstanding were as follows:

                                   December 31,
                                 1999         1998
                                  (in thousands)
% Rate  Due
7.00    1999 - December 1    $     -      $   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
7.38    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        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
8.43    2022 - June 1              -          37,471
8.50    2022 - December 1        70,000       70,000
7.80    2023 - May 1             30,237       40,000
7.90    2023 - June 1              -          30,000
7.15    2023 - November 1        20,000       30,000
7.125   2024 - May 1             50,000       50,000
8.00    2025 - June 1            50,000       50,000
Unamortized Discount             (2,765)      (3,874)
                                844,472      960,597
Less Portion Due Within
 One Year                        96,000       80,000
  Total                      $  748,472   $  880,597


<PAGE>
     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,
                                    1999       1998
                                     (in thousands)
% Rate   Due
Industrial Development Authority of
 Russell County, Virginia:

7.70     2007 - November 1       $ 17,500      17,500
5.00     2021 - November 1         19,500      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
6.05     2024 - December 1         30,000        -
Unamortized Discount               (2,783)     (2,738)
                                  264,217     234,262
Less Portion Due Within
 One Year                          30,000        -
  Total                          $234,217    $234,262

     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,
                                    1999       1998
                                     (in thousands)
% Rate   Due
7.45     2004 - November 1        $ 50,000   $   -
6.60     2009 - May 1              150,000       -
7.20     2038 - March 31           100,000    100,000
7.30     2038 - June 30            100,000    100,000
Unamortized Discount                (7,156)    (6,041)
  Total                           $392,844   $193,959

     Junior debentures outstanding were as follows:

                                     December 31,
                                1999            1998
                                   (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             (3,772)        (3,913)
  Total                        $161,228       $161,087

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

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

  2000                               $  126,005
  2001                                  100,006
  2002                                   80,006
  2003                                  100,007
  2004                                  121,008
  Later Years                         1,154,751
    Total Principal Amount            1,681,783
  Unamortized Discount                  (16,476)
      Total                          $1,665,307

     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, 1999 and 1998 were available in
the amounts of $1,056 million and $763 million, respectively.  The
short-term bank lines of credit require the payment of facility fees
and do not require compensating balances.


<PAGE>
     Outstanding short-term debt consisted of:

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

December 31, 1999:
  Commercial Paper             $123,480         6.3%

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


16. 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.

     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,
                               1999     1998     1997
                                   (in thousands)

Operating Leases              $ 5,647  $ 7,047  $ 8,016
Amortization of
  Capital Leases               13,749   13,561   11,771
Interest on Capital Leases      4,267    3,541    3,290
Total Rental Costs            $23,663  $24,149  $23,077

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

                                             December 31,
                                           1999        1998
                                           (in thousands)
Electric Utility Plant Under Capital Leases:
  Production Plant                       $  8,354     $ 9,463
  General Plant                            93,053      87,776
Total Electric Utility Plant
  Under Capital Leases                    101,407      97,239
  Accumulated Amortization                 36,762      32,064
Net Properties Under Capital Leases      $ 64,645     $65,175

Capital Lease Obligations*:
  Noncurrent Liability                    $52,009     $52,429
  Liability Due Within One Year            12,636      12,746
Total Capital Lease Obligations           $64,645     $65,175

*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.

     Future minimum lease payments consisted of the following at
December 31, 1999:
                                        Non-
                                     Cancelable
                        Capital      Operating
                        Leases          Leases
                           (in thousands)

2000                    $16,451        $2,032
2001                     14,464           999
2002                     13,327           427
2003                     10,793           412
2004                      8,443           412
Later Years              14,777         3,301

Total Future Minimum
  Lease Rentals          78,255        $7,583

Less Estimated Interest
  Element                13,610

Estimated Present Value
  of Future Minimum
  Lease Payments        $64,645


17.  SUPPLEMENTARY INFORMATION:

                             Year Ended December 31,
                             1999      1998      1997
                                  (in thousands)
Cash was paid for:
  Interest (net of
   capitalized amounts)    $125,900  $124,027 $115,508
  Income Taxes              $55,157   $65,102  $71,749

Noncash Acquisitions Under
   Capital Leases           $13,868   $21,146  $15,266



<PAGE>
18. UNAUDITED QUARTERLY FINANCIAL INFORMATION:

Quarterly Periods       Operating  Operating     Net
     Ended               Revenues   Income     Income
                                (in thousands)
1999
 March 31               $427,702    $71,607    $39,261
 June 30                 373,766     43,099     11,036
 September 30            441,435     66,309     35,661
 December 31             408,034     60,221     34,534

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

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.

In connection with the sale of coal lands and mining assets, the
Company will receive cash payments from the buyer of $17.5 million
over an 8 year period which has been recorded at a net present value
of $14.7 million.


<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, 1999
and 1998, and the related consolidated statements of income, retained
earnings, and cash flows for each of the three years in the period
ended December 31, 1999.  These financial statements are the
responsibility of the Company's management.  Our responsibility is to
express an opinion on these financial statements based on our audits.

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

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


/s/ Deloitte & Touche LLP


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