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


                                                     Year Ended December 31,                   
                                   1997         1996         1995         1994         1993
                                                         (in thousands)
<S>                             <C>          <C>          <C>          <C>          <C>
INCOME STATEMENTS DATA:

  Operating Revenues            $1,720,010   $1,624,869   $1,545,039   $1,535,500   $1,519,104
  Operating Expenses             1,480,016    1,381,993    1,317,937    1,330,282    1,289,764
  Operating Income                 239,994      242,876      227,102      205,218      229,340
  Nonoperating Income (Loss)          (222)         128       (4,699)      (4,716)      (3,353)
  Income Before Interest Charges   239,772      243,004      222,403      200,502      225,987
  Interest Charges                 119,258      109,315      106,503       98,157      100,855
  Net Income                       120,514      133,689      115,900      102,345      125,132
  Preferred Stock Dividend
    Requirements                     7,006       15,938       16,405       15,660       16,540
  Earnings Applicable to 
    Common Stock                $  113,508   $  117,751   $   99,495   $   86,685   $  108,592 



                                                     Year Ended December 31,                   
                                   1997         1996         1995         1994         1993
                                                         (in thousands)
<S>                             <C>          <C>          <C>          <C>          <C>
BALANCE SHEETS DATA:

  Electric Utility Plant        $4,901,046   $4,717,132   $4,558,436   $4,398,727   $4,193,700
  Accumulated Depreciation and
     Amortization                1,869,057    1,782,017    1,694,746    1,627,852    1,550,855
  Net Electric Utility Plant    $3,031,989   $2,935,115   $2,863,690   $2,770,875   $2,642,845
  Total Assets                  $3,883,430   $3,800,737   $3,723,975   $3,635,632   $3,478,751

  Common Stock and
    Paid-in Capital             $  873,506   $  835,838   $  785,509   $  764,866   $  755,292
  Retained Earnings                207,544      208,472      199,021      206,361      227,816
  Total Common Shareholder's
    Equity                      $1,081,050   $1,044,310   $  984,530   $  971,227   $  983,108

  Cumulative Preferred Stock:
    Not Subject to Mandatory
      Redemption                $   19,747   $   29,815   $   55,000   $   55,000   $   55,000
    Subject to Mandatory
      Redemption (a)                22,310      190,000      190,235      190,385      160,537
        Total Cumulative
          Preferred Stock       $   42,057   $  219,815   $  245,235   $  245,385   $  215,537

  Long-term Debt (a)            $1,494,535   $1,365,842   $1,285,684   $1,228,911   $1,215,168

  Obligations Under Capital 
    Leases (a)                  $   60,110   $   51,969   $   48,937   $   43,138   $   29,973

  Total Capitalization and
    Liabilities                 $3,883,430   $3,800,737   $3,723,975   $3,635,632   $3,478,751
</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 are: electric load and
customer growth; abnormal weather conditions; available sources and
costs of fuels and availability of generating capacity; the speed
and degree to which competition is introduced to our power
generation business, the terms of the transition to competition,
and its impact on rate structures; the ability to recover stranded
costs, new legislation and government regulations, the ability of
the Company to successfully reduce its costs; the economic climate
and growth in our service territory; inflationary trends, interest
rates and other risks.

Business Outlook

   The Company's ability to recover its costs as the industry
transitions to competition and as customer choice is more broadly
available is the most significant factor affecting the Company's
future.  Competition in the wholesale generation market continues
to intensify since the adoption of federal legislation in 1992
which gave wholesale customers the right to choose their energy
supplier.  The introduction of competition and customer choice for
retail customers has been slow although activity has been
increasing.  Federal legislation has been proposed to mandate
competition and customer choice at the retail level, and several
states have introduced or are considering similar legislation. 
Both West Virginia and Virginia are currently considering
legislative initiatives to move to customer choice, although the
timing is uncertain.  The Company supports customer choice and is
proactively involved in discussions at both the state and federal
levels regarding how best to structure and transition to a
competitive marketplace.

   As the electric energy market evolves from cost-of-service
ratemaking to market-based pricing, many complex issues must be
resolved, including the recovery of stranded costs.  While Federal
Energy Regulation Commission (FERC) orders No. 888 and 889 provide,
under certain conditions, for recovery of stranded cost at the
wholesale level, the issue of stranded cost recovery is unresolved
at the larger retail level.  The amount of any stranded costs the
Company may experience depends on the timing and extent to which
direct competition is introduced to our business and the then-existing market
price of electricity.

   Under the provisions of Statement of Financial Acccounting
Standards (SFAS) No. 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
with cost-based rates.  In order to maintain net regulatory assets
(net expense deferrals) on the balance sheet, SFAS No. 71 requires
that rates charged to customers be cost-based and the recovery of
regulatory assets must be probable.  In the event a portion of the
Company's business no longer meets the requirements of SFAS No. 71,
net regulatory assets would have to be written off for that portion
of the business.  The provisions of SFAS No. 71 and SFAS No. 101
"Accounting for the Discontinuance of Application of Statement No.
71" never anticipated that deregulation would include an extended
transition period or that it would provide for recovery after the
transition period of stranded costs.  In July 1997 the Emerging
Issues Task Force (EITF) of the Financial Accounting Standards
Board (FASB) reached a consensus that the application of SFAS No.
71 to a segment of a regulated electric utility which is subject to
a legislative plan to transition to competition in that segment
should cease when the legislation is passed, or an enabling rate
order is issued containing sufficient detail for the utility to
reasonably determine what the plan would entail.  The EITF
indicated that the cessation of application of SFAS No. 71 would
require that existing regulatory assets and impaired plant be
written off unless they are recoverable.

   Although FERC Orders No. 888 and 889 provide for competition in
the firm wholesale market, that market is a relatively small part
of our business and most of our firm wholesale sales are still
under cost-of-service contracts.  As a result the Company's
generation business is still cost-based regulated and should remain
so for the near future pending the passage of enabling state
legislation to deregulate the generation business.  We believe that
enabling state legislation should provide for the recovery of any
generation-related net regulatory assets and other reasonable
stranded costs from impaired generation assets.  We are working
with regulators, customers and legislators to provide for recovery
of these stranded costs during a transition period in which rates
are fixed or frozen and electric utilities would take steps to
achieve cost savings which would be used to reduce or eliminate
their stranded costs.  However, if in the future the Company's
generation business were to no longer be cost-based regulated and
if it were not possible to demonstrate probability of recovery of
resultant stranded costs including regulatory assets, results of
operations, cash flows and financial condition of the Company would be
adversely affected.

Cost Containment and Process Improvement

   Efforts continue to reduce the costs of products and services
in order to maintain our competitiveness.  Prior to 1997, reviews
of our major processes led to decisions to consolidate in the AEPSC
senior management and certain functions and operations.  Among the
functions consolidated in this restructuring were generation plant
maintenance, system operations, accounting and load research. 
While staff reductions and cost savings are presently being
achieved in these and other areas, expenses for new marketing and
customer services and modern efficient management information
systems are increasing to prepare the Company for competition.

   In February 1998, the Company began installing a new unified
customer service system which is designed to support the request
for service, billing, accounts receivable, credit and collection
functions.  The new unified customer service system replaces a 30-year-old
customer system and a nine-year-old transmission and
distribution work management system.  Process improvement efforts
and expenditures to develop and implement the new customer service
system and similar efforts and expenditures to acquire, install and
enhance new client server based accounting and budgeting/financial
planning software should produce further improvements and
efficiencies, enabling the Company to continue to offer its
customers excellent service at competitive prices.

Fuel Costs

   We recognize that we must continue to manage our coal costs to
maintain our competitive position.  Approximately 98% of the
Company's generation was coal fired and is supplied under long-term
contracts and purchases in the spot market.  As long-term contracts
expire we are negotiating with unaffiliated suppliers to lower coal
costs.  We intend to continue to prudently supplement our long-term
coal supplies with spot market purchases as long as favorable spot
market prices exist.

Environmental Concerns

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

   By-products from the generation of electricity include
materials such as ash, slag and sludge.  Coal combustion by-products
are typically disposed of or treated in captive disposal
facilities or are beneficially utilized.  In addition, our
generating plants and transmission and distribution facilities have
used asbestos, 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.

   Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA or Superfund) addresses clean-up of hazardous
substances at disposal sites and authorized the United States
Environmental Protection Agency (Federal EPA) to administer the
clean-up programs.  As of year-end 1997, there are two sites for
which the Company has received information requests which could
lead to "Potentially Responsible Parties" (PRP) designation.  The
Company's liability has been resolved for a number of sites with no
significant effect on results of operations and present estimates
do not anticipate material cleanup costs for identified sites in
which the Company is involved.  However, if for reasons not
currently identified significant costs are incurred for cleanup,
future results of operations, cash flows and possibly financial condition
would be adversely affected unless the costs can be recovered.

   Federal EPA is required by the Clean Air Act Amendments of 1990
(CAAA) to issue rules to implement the law.  In December 1996
Federal EPA issued final rules governing nitrogen oxide (NOx) that
must be met after January 1, 2000 (Phase II of the CAAA).  The
final rules will require substantial reductions in NOx emissions
from certain types of power plant boilers including those in AEP's
power plants.  On February 13, 1998, the United States Court of
Appeals for the District of Columbia Circuit, in an appeal in which
the AEP System operating companies participated, upheld the
emission limitations.  In addition in November 1997 the Federal EPA
published a proposed rulemaking requiring the revision of state
implementation plans in 22 eastern states, including West Virginia
and Virginia, states in which the Company has coal-fired generating
plants.  The proposed rule will require reductions in NOx emissions
from utility sources of approximately 85% below 1990 levels and
entail very substantial capital and operating expenditures by AEP
System operating companies.  Since the Company shares energy and
wholesales sales as a member of the AEP System power pool it is
affected by expenditures at the generating units of other
affiliated members of the AEP Pool.  Pollution controls to meet the
proposed revised NOx emission limits would have to be in place by
2002.  Also, the Federal EPA has been petitioned for a new
rulemaking by eight northeast states for the development of
controls for upwind sources.  The costs to comply with the emission
reductions required by these Federal EPA actions is expected to be
substantial and would have a material adverse impact on future
results of operations, cash flows and possibly financial condition if the
resultant costs are not recovered from customers.

   In 1997 the Federal EPA published a revised ambient air quality
standard for ozone and established a new ambient air quality
standard for fine particulate matter.  These standards are expected
to result in redesignation of a number of areas of the country
currently in compliance with the existing standard to nonattainment
which could ultimately dictate more stringent emission restrictions
for AEP generating units including those of the Company's.  Under
the new rules the states must first determine the attainment status
of their areas.  The states then have three years to submit a
compliance plan and up to ten years after designation to come into
compliance with the new standards.  The compliance deadline could
be as late as 2010 for the ozone standard and 2012-2015 for the
fine particulate standard.  Although we are reviewing the impact of
the new rules, we are unable to estimate compliance costs without
knowledge of the reductions that Virginia and West Virginia will
find necessary to meet the new standards.  If such reductions are
significant and the Company and its affiliates must bear a
significant portion of the cost of compliance in a region or county
that is in violation of the revised standards, it would have a
material adverse effect on results of operations, cash flows and possibly
financial condition unless such costs are recovered from customers.

   At the global climate conference in Kyoto, Japan in December
1997 more than 160 countries negotiated a treaty limiting emissions
of greenhouse gases, chiefly carbon dioxide, which may eventually
contribute to global warming.  Although there is no clear
scientific evidence that carbon dioxide contributes to global
warming and damages the environment, the treaty, which requires
Congressional approval, calls for a seven percent reduction below
emission levels of greenhouse gases in 1990.  We intend to work
with the Congress to ensure that science and reason are introduced
into the debate.  If approved by Congress, the cost to comply with
the emission reductions required by the Kyoto treaty is 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.

Results of Operations

   Although operating revenues increased significantly in 1997 due
to increased wholesale sales, net income decreased $13.2 million or
10% primarily due to increased operating expenses and interest
charges reflecting additional amounts of long-term debt
outstanding.  The increase in operating expenses was mainly due to
increased fuel and purchased power expense which virtually offset
the revenue increase from retail and wholesale customers.  In July
of 1997 AEP started a new power marketing business of buying and
selling power outside the AEP System which accounted for the
increases in purchased power and wholesale revenues.  The
significant increase in revenues was substantially offset by an
increase in the related purchased power expense.  In 1996 net
income increased by $17.8 million or 15% mainly due to increased
sales of energy and services.  The 1996 sales increase was
predominately due to greater demand for energy by wholesale
customers and increased transmission and other services provided to
power marketers and utilities.  Also contributing to the
improvement in net income in 1996 were the effects of severance pay
charges recorded in 1995 in connection with a management and
operations restructuring and gains recorded in 1996 from emission
allowance transactions.

<PAGE>
Operating Revenues and Energy Sales Increase

   Operating revenues increased 6% in 1997 and 5% in 1996
primarily due to increased wholesale energy sales.  The change in
operating revenues can be analyzed as follows:

                               Increase (Decrease)
                               From Previous Year     
(dollars in millions)       1997           1996       
                         Amount    %    Amount     %
Retail:
  Price variance         $(21.7)        $   1.4
  Volume variance           7.5            14.4
  Fuel and Purchased
   Power Recoveries        16.8           (13.6)
                            2.6    0.2      2.2   0.2
Wholesale:
  Price variance            7.5          (143.5)
  Volume variance          70.5           206.8
                           78.0   23.4     63.3  23.5 

Other Operating Revenues   14.5            14.3 
         Total           $ 95.1    5.9  $  79.8   5.2

   The increases in revenues was mainly due to increased lower
profit wholesale sales in both 1997 and 1996.  Wholesale revenues
and sales increased in 1997 primarily due to new power marketing
transactions which began in July 1997 and increased coal conversion
services.  The new power marketing transactions involve the
purchase and sale of electricity outside the AEP transmission
system.

   In 1996 the increase in wholesale sales was due to a 38%
increase in the Company's share of Power Pool allocated sales and
a rise in sales to the Power Pool.  Sales of coal conversion
services which are made through the Power Pool resulted in 2.2
billion kilowatthours of electricity being provided to power
marketers and certain other utilities.  Coal conversion services
which began in 1996 are provided to power marketers and certain
non-affiliated utilities under a FERC approved interruptible tariff
for the conversion of customers' coal to electricity and do not
include any fuel cost.  Since these sales are for the service of
converting the customers' coal to electricity and do not include
any fuel cost, the average wholesale price per kilowatthour was
significantly less in 1996 than in 1995.  Energy sales to the Power
Pool increased in 1996 mainly due to increased demand for electric
energy by customers of the other affiliated Power Pool members. 
Energy sales to the Power Pool are priced to compensate the
supplying Power Pool member for its out-of-pocket costs.  An
increased level of activity in the wholesale energy markets
encouraged by the 1996 issuance of FERC open access transmission
rules and the Company's efforts to provide flexible and
competitively priced transmission services led to increases in
transmission service revenues in 1997 and 1996.  As a result
transmission revenues from the wheeling of non-affiliated power,
which are recorded as other operating revenues, increased by
approximately $6.5 million and $12 million in 1997 and 1996,
respectively.  Also contributing to the increase in other operating
revenues in 1997 was the favorable effect due to a provision
recorded in 1996 for the completion of rate refunds under a
settlement in the Virginia jurisdiction.

Operating Expenses Increase

   Operating expenses increased by 7% in 1997 and 5% in 1996.  The
increase in 1997 is mainly due to increased power purchases by
AEP's new power marketing business.  In 1996 all operating expenses
except maintenance increased.  Changes in the components of
operating expenses were as follows:

                               Increase (Decrease)
                               From Previous Year     
(dollars in millions)        1997             1996    
                       Amount      %    Amount     %

Fuel                   $ 36.1     9.8   $ 18.9    5.4
Purchased Power          70.0    21.0     32.9   11.0
Other Operation           6.5     2.7     18.5    8.3
Maintenance              (4.6)   (3.9)   (22.1) (15.8)
Depreciation and
  Amortization            4.6     3.5      0.1     -
Taxes Other Than 
  Federal Income Taxes   (3.7)   (3.1)     3.2    2.7
Federal Income Taxes    (10.9)  (15.5)    12.6   21.8
  Total                $ 98.0     7.1   $ 64.1    4.9

   Fuel expense increased 10% in 1997 primarily due to increased
generation and the operation of the West Virginia power supply cost
recovery mechanism which requires that overcollections of fuel
costs be deferred for future refund to customers through a charge
to fuel expense in accordance with a rate order.  The level of
generation increased primarily in the fourth quarter of 1997 when
both units of an affiliate's nuclear plant were unavailable.  The
5% increase in fuel expense in 1996 was mainly due to increased
generation to meet the increased demand of wholesale customers and
increased availability of generating capacity.

   The significant increase in purchased power expense in 1997 was
mainly due to purchases of electricity for the new power marketing
transactions partially offset by decreased purchases from the Power
Pool due to the unavailability of the affiliate's nuclear units. 
The rise in purchased power in 1996 was attributable to increased
purchases of energy from the Power Pool to meet the increased
demand for energy and an increase in Power Pool capacity charges. 
An increase in the Company's prior twelve-month peak demand
relative to the total peak demand of all Power Pool members caused
the increase in Power Pool capacity charges which are included in
purchased power.
   The increase in other operation expense in 1996 was due to an
increase in expenditures for customer service and management
information software systems; recognition of deferred software
development costs as a result of a final rate order from the State
Corporation Commission of Virginia (Virginia SCC); an increase in
employee benefit costs; and higher costs related to new coal
conversion and transmission services to power marketers and other
utilities.  These items more than offset the recognition of gains
on the sale of emission allowances and the effect of a provision
for severance pay recorded in 1995 related mainly to the functional
restructuring of AEP's management and operations.

   Maintenance expense declined in 1996 primarily as a result of
accounting for incremental storm damage expense in accordance with
directions of the Virginia SCC.

   The decrease in federal income taxes attributable to operations
in 1997 was primarily due to a decline in pre-tax operating income. 
An increase in pre-tax operating income in 1996 accounted for the
increase in federal income taxes attributable to operations.

Nonoperating Income

   Nonoperating income increased in 1996 due to the effect of a
loss recorded in 1995 that resulted from the sale of coal-mining
assets owned by the Company.

Interest Charges and Preferred Stock Dividends

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

Financial Condition

   In 1997 the Company maintained its strong financial condition. 
We redeemed 1,777,585 shares of cumulative preferred stock with
rates ranging from 4.50% to 7.8% at a total cost of $184 million. 
Part of the reacquired shares were reacquired under terms of a
tender offer in conjunction with a special shareholders' meeting at
which the articles of incorporation were revised to remove certain
capitalization ratio requirements that constrained the Company's
issuance of unsecured and short-term debt.  The restrictions
limited our financial flexibility and could have placed us at a
competitive disadvantage in the future.  We used short-term debt
and junior subordinated deferrable interest debentures to pay for
the preferred stock tendered and to benefit from the tax
deductibility of interest.


   The Company issued $186 million principal amount of long-term
obligations in 1997 at interest rates ranging from 6.35% to 8.0%. 
We continued to reduce financing costs by retiring higher-cost
bonds and restructuring the long-term debt from senior
secured/first mortgage bonds to senior unsecured debt/junior
debentures.  The principal amount of long-term debt retirements,
including maturities, totaled $56 million with interest rates
ranging from 8.75% to 9.35%.  Our senior secured debt/first
mortgage bond ratings which were reaffirmed and improved in 1997,
are: Moody's, A3; Standard and Poor's (S&P), A; Fitch, A; and Duff
& Phelps, LLC (D & P), A.  The Company's good bond ratings meet and
often exceed the required rating of bond investors.  With higher
bond ratings, the Company attracts a wider investor base, a bigger
share of capital in the bond market and lower interest rates.

   Gross plant and property additions were $233 million in 1997
and $207 million in 1996.  Management estimates construction
expenditures for the next three years to be $660 million which
includes the cost of transmission and distribution projects for the
improvement of and addition to electric energy delivery facilities. 
The funds for construction of new facilities and improvement of
existing facilities can come from a combination of internally
generated funds, short-term and long-term borrowings, preferred
stock issuances and investments in common equity by the Company's
parent, AEP Co., Inc.  However, all of the construction
expenditures for the next three years are expected to be financed
with internally generated funds.  Inflation affects the Company's
cost of replacing utility plant and the cost of operating and
maintaining plant.  The rate-making process generally limits our
recovery to the historical cost of assets resulting in economic
losses when the effects of inflation are not recovered from
customers on a timely basis.  However, economic gains that result
from the repayment of long-term debt with inflated dollars partly
offset such losses.

   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, 1997, $442 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 $250 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 ratios are 2.0 for mortgage
bonds and 1.5 for preferred stock.  At December 31, 1997, the
mortgage bonds and preferred stock coverage ratios were 3.72 and
1.92, respectively.



Other Matters

Corporate Owned Life Insurance

   In connection with the audit of AEP's consolidated federal
income tax returns for the United States Internal Revenue Service
(IRS) agents sought a ruling from the IRS National Office that
certain interest deductions relating to a COLI program should not
be allowed.  The Company established the COLI program in 1990 as
part of its strategy to fund and reduce the cost of medical
benefits for retired employees.  AEP filed a brief with the IRS
National Office refuting the agents' position.  No adjustments have
been proposed by the IRS.  However should, a disallowance of the
COLI interest deductions be proposed it would, if sustained, reduce
earnings by approximately $72 million (including interest). 
Management believes it has meritorious defenses and will vigorously
contest any proposed adjustments.  No provisions for this amount
have been recorded.  In the event the Company is unsuccessful it
could have a material adverse impact on results of operations
and cash flows.

Computer Software - Year 2000 Compliance

   Many existing computer hardware and software programs will not
properly recognize calendar dates beginning in the year 2000. 
Unless corrected, this "Year 2000" problem may cause computer
malfunctions, such as system shutdowns or incorrect calculations
and system output.  The Company is addressing the problem
internally by modifying or replacing its computer hardware and
software programs.  The problem is also being addressed externally
with entities that interact electronically with the Company,
including but not limited to, suppliers, service providers,
government agencies, customers, creditors and financial service
organizations.  However, due to the complexity of the problem and
the interdependent nature of computer systems, if the Company's
corrective actions, and/or the actions of other interdependent
entities, fail for critical applications, the Company may be
adversely impacted in the year 2000.  Although significant, the
cost of correcting the "Year 2000" problem is not expected to have
a material impact on results of operations, cash flows or financial condition.

New Accounting Standards

   In June 1997 the FASB issued SFAS No. 130 "Reporting
Comprehensive Income" and SFAS No. 131 "Disclosures About Segments
of an Enterprise and Related Information."  SFAS No. 130
establishes the standards for reporting and displaying components
of "comprehensive income," which is the total of net income and all
other changes in equity except those resulting from investments by
shareholders and dispositions to shareholders.  SFAS No. 131
initiates standards for reporting information about operating
segments in annual and interim financial statements as well as
related disclosures about products and services, geographic areas
and major customers.  APCo's adoption of these new reporting
standards in 1998 is not expected to have a material effect on the
results of operations, cash flows and/or financial condition.

Litigation

   The Company is involved in a number of legal proceedings and
claims.  While we are unable to predict the outcome of such
litigation, it is not expected that the ultimate resolution of
these matters will have a material adverse effect on the results of
operations, cash flows and/or financial condition.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income


                                                               Year Ended December 31,        
                                                         1997           1996           1995
                                                                   (in thousands)
<S>                                                   <C>            <C>            <C>
OPERATING REVENUES                                    $1,720,010     $1,624,869     $1,545,039

OPERATING EXPENSES:
 Fuel                                                    403,777        367,651        348,776
 Purchased Power                                         403,009        333,014        300,086
 Other Operation                                         246,785        240,249        221,783
 Maintenance                                             112,873        117,483        139,566
 Depreciation and Amortization                           137,670        133,074        132,999
 Taxes Other Than Federal Income Taxes                   116,590        120,307        117,093
 Federal Income Taxes                                     59,312         70,215         57,634
          Total Operating Expenses                     1,480,016      1,381,993      1,317,937

OPERATING INCOME                                         239,994        242,876        227,102

NONOPERATING INCOME (LOSS)                                  (222)           128         (4,699)

INCOME BEFORE INTEREST CHARGES                           239,772        243,004        222,403

INTEREST CHARGES                                         119,258        109,315        106,503

NET INCOME                                               120,514        133,689        115,900
 
PREFERRED STOCK DIVIDEND REQUIREMENTS                      7,006         15,938         16,405

EARNINGS APPLICABLE TO COMMON STOCK                   $  113,508     $  117,751     $   99,495
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets


                                                                           December 31,       
                                                                      1997             1996
                                                                          (in thousands)
ASSETS
<S>                                                                <C>              <C>
ELECTRIC UTILITY PLANT:
   Production                                                      $1,942,325       $1,883,271
   Transmission                                                     1,079,919        1,054,207
   Distribution                                                     1,583,161        1,495,445
   General                                                            207,380          188,740
   Construction Work in Progress                                       88,261           95,469
                 Total Electric Utility Plant                       4,901,046        4,717,132
   Accumulated Depreciation and Amortization                        1,869,057        1,782,017
                 NET ELECTRIC UTILITY PLANT                         3,031,989        2,935,115


OTHER PROPERTY AND INVESTMENTS                                         35,467           29,621


CURRENT ASSETS:
   Cash and Cash Equivalents                                            6,947            7,260
   Accounts Receivable:
      Customers                                                       129,924          122,969
      Affiliated Companies                                             24,502           15,017
      Miscellaneous                                                    10,231           22,035
      Allowance for Uncollectible Accounts                             (1,333)            (687)
   Fuel - at average cost                                              47,901           52,605
   Materials and Supplies - at average cost                            57,359           56,605
   Accrued Utility Revenues                                            51,208           51,843
   Prepayments                                                          6,037           10,797
                 TOTAL CURRENT ASSETS                                 332,776          338,444   


REGULATORY ASSETS                                                     441,223          451,272

DEFERRED CHARGES                                                       41,975           46,285
                     TOTAL                                         $3,883,430       $3,800,737
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES


                                                                           December 31,       
                                                                      1997             1996
                                                                          (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                                                    613,048          575,380
   Retained Earnings                                                  207,544          208,472
                Total Common Shareholder's Equity                   1,081,050        1,044,310
   Cumulative Preferred Stock:
       Not Subject to Mandatory Redemption                             19,747           29,815
       Subject to Mandatory Redemption                                 22,310          190,000
   Long-term Debt                                                   1,415,026        1,365,834
                TOTAL CAPITALIZATION                                2,538,133        2,629,959

OTHER NONCURRENT LIABILITIES                                          137,371          109,203

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                                  79,509                8
   Short-term Debt                                                    130,300           60,700
   Accounts Payable - General                                          52,683           34,714
   Accounts Payable - Affiliated Companies                             44,133           51,178
   Taxes Accrued                                                       41,549           40,935
   Customer Deposits                                                   13,713           13,750
   Interest Accrued                                                    20,949           20,938
   Other                                                               71,394           80,352
                TOTAL CURRENT LIABILITIES                             454,230          302,575

DEFERRED INCOME TAXES                                                 658,655          669,964

DEFERRED INVESTMENT TAX CREDITS                                        67,496           72,677

DEFERRED CREDITS                                                       27,545           16,359 

COMMITMENTS AND CONTINGENCIES (Note 4)

                    TOTAL                                          $3,883,430       $3,800,737

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,       
                                                            1997          1996          1995
                                                                     (in thousands)
<S>                                                      <C>           <C>           <C>
OPERATING ACTIVITIES:
   Net Income                                            $ 120,514     $ 133,689     $ 115,900 
   Adjustments for Noncash Items:
      Depreciation and Amortization                        138,975       134,381       134,485
      Deferred Federal Income Taxes                         (5,117)          592           647
      Deferred Investment Tax Credits                       (5,181)       (5,602)       (5,465)
      Deferred Power Supply Costs (net)                     12,310           293        (3,721)
      Provision for Rate Refunds                             7,601        (2,626)       15,224
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                             (3,990)      (19,176)      (16,896)
      Fuel, Materials and Supplies                           3,950        15,583        (9,761)
      Accrued Utility Revenues                                 635        13,235       (13,392)
      Accounts Payable                                      10,924         3,668       (11,488)
      Taxes Accrued                                            614        (7,731)       14,043
   Other (net)                                                (722)        9,437        28,324
        Net Cash Flows From Operating Activities           280,513       275,743       247,900

INVESTING ACTIVITIES:
   Construction Expenditures                              (218,074)     (191,815)     (216,200)
   Proceeds from Sales of Property                           4,971         1,933         7,793
        Net Cash Flows Used For Investing Activities      (213,103)     (189,882)     (208,407)

FINANCING ACTIVITIES:
   Capital Contributions from Parent Company                40,000        50,000        30,000
   Issuance of Long-term Debt                              183,257       273,340       128,785
   Retirement of Cumulative Preferred Stock               (183,875)      (25,904)         (150)
   Retirement of Long-term Debt                            (56,379)     (195,910)      (74,950)
   Change in Short-term Debt (net)                          69,600       (64,825)        2,700
   Dividends Paid on Common Stock                         (114,436)     (108,300)     (106,836)
   Dividends Paid on Cumulative Preferred Stock             (5,890)      (15,666)      (15,675)
        Net Cash Flows Used For Financing Activities       (67,723)      (87,265)      (36,126)

Net Increase (Decrease) in Cash and Cash Equivalents          (313)       (1,404)        3,367
Cash and Cash Equivalents January 1                          7,260         8,664         5,297
Cash and Cash Equivalents December 31                    $   6,947     $   7,260     $   8,664
</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,     
                                                               1997         1996         1995
                                                                       (in thousands)
<S>                                                          <C>          <C>          <C>
Retained Earnings January 1                                  $208,472     $199,021     $206,361
Net Income                                                    120,514      133,689      115,900 
                                                              328,986      332,710      322,261
Deductions:
   Cash Dividends Declared:
     Common Stock                                             114,436      108,300      106,836
     Cumulative Preferred Stock:
        4-1/2% Series                                             892        1,348        1,350
        4.50%  Series                                            -               9           16
        5.90%  Series                                             455        2,950        2,950
        5.92%  Series                                             364        3,552        3,552
        6.85%  Series                                             579        2,055        2,055
        7.40%  Series                                            -           1,385        1,850
        7.80%  Series                                             931        3,900        3,900
                Total Cash Dividends Declared                 117,657      123,499      122,509

   Capital Stock Expense                                        3,785          739          731
                Total Deductions                              121,442      124,238      123,240

Retained Earnings December 31                                $207,544     $208,472     $199,021
</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, sale, purchase, transmission and distribution of
electric power to 877,000 retail customers in southwestern Virginia
and southern West Virginia.  Wholesale electric power is supplied
to neighboring utility systems, power marketers and the American
Electric Power (AEP) System Power Pool (Power Pool).  As a member
of the American Electric Power System (AEP System) Power Pool and
a signatory company to the AEP System Transmission Equalization
Agreement, APCo's facilities are operated in conjunction with the
facilities of certain other AEP affiliated utilities as an integrated
utility system.

    The Company has four wholly-owned subsidiaries which are
consolidated in these financial statements: Cedar Coal Co., Central
Appalachian Coal Company and Southern Appalachian Coal Company
(which were formerly engaged in coal mining and now lease their
coal reserves to unaffiliated companies) and West Virginia Power
Company (which is inactive).

Regulation

    As a subsidiary of AEP Co., Inc., APCo 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 wholesale rates.

Principles of Consolidation

    The consolidated financial statements include 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) No. 71,
"Accounting for the Effects of Certain Types of Regulation,"
regulatory assets (deferred expenses) and regulatory liabilities
(deferred income) are recorded to reflect the economic effects of
regulation and to match expenses with regulated revenues.

Use of Estimates

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

Utility Plant

    Electric utility plant is stated at original cost and is
generally subject to first mortgage liens.  Additions, major
replacements and betterments are added to the plant accounts. 
Retirements of plant are deducted from the electric 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 1997, 1996 and 1995 were not
significant.

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.

<PAGE>
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 as follows:

                   Annual Composite
Functional Class   Depreciation
of Property        Rates           

Production:
  Steam            3.4%
  Hydro            2.9%
Transmission       2.2%
Distribution       3.3%
General            3.1%

    Amounts to be used for demolition and removal of plant are
recovered through depreciation charges included in rates.

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 regulatory commission'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 annually by the Virginia SCC.  In the West Virginia
jurisdiction, under the terms of a 1996 settlement agreement,
deferral accounting will be practiced for the over and under
collection of fuel, Power Pool capacity charges and certain
transmission revenue for the period November 1996 through December
1999.  Although a cumulative over and under recovery balance will
be maintained, ratepayers will not be responsible for any
cumulative underrecovery balance at December 31, 1999. 
Overrecoveries during the annual periods through December 31, 1999
in excess of $10 million per period would be accumulated and shared
equally between the Company and its ratepayers.  Overrecoveries
under $10 million are included in operating income annually.

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

Income Taxes

    The Company follows the liability method of accounting for
income taxes as prescribed by SFAS 109, "Accounting for Income
Taxes."  Under the liability method, deferred income taxes are
provided for all temporary differences between book cost and tax
basis of assets and liabilities which will result in a future tax
consequence.  Where the flow-through method of accounting for
temporary differences is reflected in rates, deferred income taxes
are recorded with related regulatory assets and liabilities in
accordance with SFAS 71.

Investment Tax Credits

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

Debt and Preferred Stock

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

    Debt discount or premium and expenses of debt issuances are
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.

Reclassification

    Certain prior period amounts have been reclassified to agree
with current period presentation.


2. EFFECTS OF REGULATION:

    In accordance with SFAS No. 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.  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.  The Company has reviewed all the evidence currently
available and concluded that it continues to meet the requirements
to apply SFAS No. 71.  Among other things  application of SFAS No.
71 requires that the Company's rates be cost-based regulated.  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 investment.

    Recognized regulatory assets and liabilities are comprised of
the following:
                                    December 31,      
                                 1997          1996
                                   (in thousands)
Regulatory Assets:
  Amounts Due From Customers
    For Future Income Taxes    $386,127      $392,372
  Unamortized Loss On
    Reacquired Debt              23,561        25,567
  Deferred Storm Damage           8,542        10,990
  Other                          22,993        22,343
  Total Regulatory Assets      $441,223      $451,272

Regulatory Liabilities:
  Deferred Investment Tax
    Credits                     $67,496       $72,677
  Other*                         21,121        10,384
  Total Regulatory Liabilities  $88,617       $83,061

* Included in Deferred Credits on Consolidated Balance
  Sheets.


3. RATE MATTERS:

    On June 13, 1997, the Company filed an application with the
Virginia SCC for approval of an alternative regulatory plan (Plan)
which proposed, among other things, an increase of $30.5 million in
base rates on an annual basis to be effective July 13, 1997.  The
Company's Plan would institute a moratorium period during which no
changes from the proposed rates would be made prior to January 1,
2001, (including the Company's current 1.482 cents/kwh fuel
factor).  In addition, it includes a sharing of earnings above
certain levels between the Company and its customers, and
acceleration of the recovery of certain regulatory assets.  On July
10, 1997, the Virginia SCC issued an order suspending
implementation of the proposed rates until November 11, 1997 when
rates were placed into effect subject to refund.  A hearing has
been scheduled for July 6, 1998 to consider the Company's proposal.

    In 1992 the FERC authorized the Company to implement, subject
to refund, an $8.7 million annual rate increase.  The revenues
collected subject to refund in the FERC jurisdiction total $46.7
million through December 31, 1997.  A refund liability, including
interest, of $28.1 million at December 31, 1997 has been accrued.


<PAGE>
4. COMMITMENTS AND CONTINGENCIES:

Construction and Other Commitments

    Substantial construction commitments have been made to support
utility operations.  Such commitments do not include any
expenditures for new generating capacity.  Aggregate construction
expenditures for 1998-2000 are estimated to be $660 million.

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

Revised Air Quality Standards

    On July 18, 1997, the United States Environmental Protection
Agency (Federal EPA) published a revised National Ambient Air
Quality Standard (NAAQS) for ozone and a new NAAQS for fine
particulate matter (less than 2.5 microns in size).  The new ozone
standard is expected to result in redesignation of a number of
areas of the country that are currently in compliance with the
existing standard to nonattainment status which could ultimately
dictate more stringent emission restrictions for AEP System
generating units. New stringent emission restrictions on AEP System
generating units to achieve attainment of the fine particulate
matter standard could also be imposed.  The AEP System operating
companies joined with other utilities to appeal the revised NAAQS
and filed petitions for review in August and September 1997 in the
U.S. Court of Appeals for the District of Columbia Circuit. 
Management is unable to estimate compliance costs without knowledge
of the reductions that may be necessary to meet the new standards. 
If such costs are significant, they could have a material adverse
effect on results of operations, cash flows and possibly financial condition
unless recovered.

Litigation

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


5. RELATED PARTY TRANSACTIONS:

    Benefits and costs of the AEP System's generating plants are
shared by members of the Power Pool.  The Company is a member of
the Power Pool.  Under terms of the System Interconnection
Agreement, capacity charges and credits are designed to allocate
the cost of the System's capacity among the Power Pool members
based on their relative peak demands and generating reserves. 
Power Pool members are also compensated for the out-of-pocket costs
of energy delivered to the Power Pool and charged for energy
received from the Power Pool.

    Operating revenues include $40.1 million in 1997, $54.8 million
in 1996 and $26.3 million in 1995 for energy supplied to the Power
Pool.

    Since the Company's internal peak demand exceeds its generating
capacity, charges for Power Pool capacity reservation and energy
received were included in purchased power expense as follows:

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

Capacity Charges      $128,680   $125,456    $116,821
Energy Charges         149,113    187,754     161,531

     Total            $277,793   $313,210    $278,352

    Power Pool members share in wholesale sales to unaffiliated
entities made by the Power Pool.  The Company's share of these
wholesale Power Pool sales included in operating revenues were $220
million in 1997, $127 million in 1996 and $92 million in 1995. 

    In addition, the Power Pool purchases power from unaffiliated
companies for immediate resale to other unaffiliated utilities. 
The Company's share of these purchases was included in purchased
power expense and totaled $118.8 million (including new power
marketing transactions) in 1997, $14.7 million in 1996 and $18.8
million in 1995.  Revenues from these transactions including a
transmission fee are included in the above Power Pool wholesale
operating revenues.

    Energy sold directly to Kingsport Power Company (KGPCo), an
affiliated distribution utility that is not a member of the Power
Pool, was included in operating revenues in the amounts of $57.9
million in 1997, $59.5 million in 1996 and $58.7 million in 1995.

    Purchased power expense includes $6.4 million in 1997, $5.1
million in 1996 and $2.9 million in 1995 of energy bought from the
Ohio Valley Electric Corporation, an affiliated company that is not
a member of the Power Pool.

    AEP System companies participate in a transmission equalization
agreement.  This agreement combines certain AEP System companies'
investments in transmission facilities and shares the costs of
ownership in proportion to the System companies' respective peak
demands.  Pursuant to the terms of the agreement since the
Company's relative investment in transmission facilities is greater
than its relative peak demands, other operation expense includes
equalization charges of $8.4 million, $6.5 million and $5.4 million
in 1997, 1996 and 1995, respectively.

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

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


6. BENEFIT PLANS:

    The Company and its subsidiaries participate in the AEP System
pension plan, a trusteed, noncontributory defined benefit plan
covering all employees meeting eligibility requirements.  Benefits
are based on service years and compensation levels.  Pension costs
are allocated by first charging each System company with its
service cost and then allocating the remaining pension cost in
proportion to its share of the projected benefit obligation.  The
funding policy is to make annual trust fund contributions equal to
the net periodic pension cost up to the maximum amount deductible
for federal income taxes, but not less than the minimum required
contribution in accordance with the Employee Retirement Income
Security Act of 1974.  Net pension costs for the years ended
December 31, 1997, 1996 and 1995 were $1.9 million, $4.2 million
and $2.7 million, respectively.

    Postretirement Benefits Other Than Pensions (OPEB) are provided
for retired employees under an AEP System plan.  Substantially all
employees are eligible for postretirement health care and life
insurance if they retire from active service after reaching age 55
and have at least 10 service years.  OPEB costs are determined by
the application of AEP System actuarial assumptions to each
operating company's employee complement.  The annual accrued costs
were $17.3 million in 1997, $19 million in 1996 and $19.5 million
in 1995.  The funding policy for AEP's OPEB plan is to make
contributions to an external Voluntary Employees Beneficiary
Association trust fund equal to the incremental OPEB costs (i.e.,
the amount that the total postretirement benefits cost under SFAS
106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," exceeds the pay-as-you-go amount).  Contributions were
$6.4 million in 1997, $8.4 million in 1996 and $9.5 million in
1995.

    An employee savings plan is offered which allows participants
to contribute up to 17% of their salaries into various investment
alternatives, including AEP Co., Inc. common stock.  An employer
matching contribution, equaling one-half of the employees'
contribution to the plan up to a maximum of 3% of the employees'
base salary, is invested in AEP Co., Inc. common stock.  The
Company's annual contributions totaled $4 million in 1997, $4.1
million in 1996, and $4.3 million in 1995.


7. 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, 
                               1997     1996     1995
                                   (in thousands)

Operating Leases              $ 8,016  $ 9,567  $ 8,600
Amortization of 
  Capital Leases               11,771   12,175   11,003
Interest on Capital Leases      3,290    3,416    4,120
Total Rental Costs            $23,077  $25,158  $23,723

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

                                     December 31,    
                                   1997        1996
                                    (in thousands)
Electric Utility Plant:
  Production                     $10,553      $ 9,366
  General                         77,980       73,420
      Total Electric Utility 
         Plant                    88,533       82,786
  Accumulated Amortization        28,423       30,817
      Net Properties under
          Capital Leases         $60,110      $51,969

Capital Lease Obligations:
  Noncurrent Liability           $48,552      $36,857
  Liability Due Within One Year   11,558       15,112
    Total Capital Lease 
      Obligations                $60,110      $51,969

<PAGE>
    Capital lease obligations are included in other non-current 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, 1997:
                                        Non-
                                     Cancelable
                        Capital      Operating
                        Leases          Leases 
                           (in thousands)      

1998                    $15,599      $ 8,693
1999                     13,751        2,244  
2000                     11,315        2,007  
2001                      9,347          936  
2002                      8,227          415  
Later Years              17,214        4,125  

Total Future Minimum 
  Lease Rentals          75,453      $18,420

Less Estimated Interest
  Element                15,343

Estimated Present Value 
  of Future Minimum 
  Lease Payments        $60,110


8.  CUMULATIVE PREFERRED STOCK:

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

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

    The Company redeemed and canceled 2,348 and 1,500 shares of the
4.50% series subject to mandatory redemption in 1996 and 1995,
respectively.  The Company redeemed and canceled 250,000 shares of
the 7.40% series not subject to mandatory redemption in 1996.

<PAGE>
Cumulative Preferred Stock Not Subject to Mandatory Redemption:
<TABLE>
<CAPTION>
            Call Price                                             Shares               Amount       
           December 31,      Number of Shares Redeemed          Outstanding          December 31,    
Series         1997            Year Ended December 31,       December 31, 1997     1997        1996 
                              1997      1996      1995                               (in thousands)
<S>          <C>            <C>         <C>       <C>              <C>           <C>         <C>       
4-1/2%       $110.00        100,685     1,850      -               197,465       $19,747     $29,815

Cumulative Preferred Stock Subject to Mandatory Redemption:

           Call Price
          December 31,      Number of Shares Redeemed           Outstanding          December 31,    
Series(a)     1997            Year Ended December 31,        December 31, 1997      1997       1996 
                             1997      1996      1995                                (in thousands)

7.80%       $   -          500,000      -         -                  -            $  -      $ 50,000
5.90% (b)      (d)         422,900      -         -                77,100           7,710     50,000
5.92% (b)      (d)         538,500      -         -                61,500           6,150     60,000
6.85% (c)      (e)         215,500      -         -                84,500           8,450     30,000
                                                                                  $22,310   $190,000

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

9. FEDERAL INCOME TAXES:
<TABLE>
     The details of federal income taxes as reported are as follows:
<CAPTION>
                                                                 Year Ended December 31,           
                                                        1997             1996                1995
                                                                     (in thousands)
<S>                                                    <C>              <C>                 <C>   
Charged (Credited) to Operating Expenses (net):
  Current                                              $66,810          $71,648             $58,676
  Deferred                                              (4,801)           1,283               1,715
  Deferred Investment Tax Credits                       (2,697)          (2,716)             (2,757)
           Total                                        59,312           70,215              57,634
Charged (Credited) to Nonoperating Income (net):
  Current                                               (1,677)            (837)               (503)
  Deferred                                                (316)            (691)             (1,068)
  Deferred Investment Tax Credits                       (2,484)          (2,886)             (2,708)
           Total                                        (4,477)          (4,414)             (4,279)
Total Federal Income Taxes as Reported                 $54,835          $65,801             $53,355

<PAGE>
     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,              
                                                    1997                1996                 1995
                                                                   (in thousands)

Net Income                                        $120,514            $133,689             $115,900 
Federal Income Taxes                                54,835              65,801               53,355 
Pre-tax Book Income                               $175,349            $199,490             $169,255 

Federal Income Taxes on Pre-tax Book Income at 
  Statutory Rate (35%)                             $61,372             $69,822             $ 59,239 
Increase (Decrease) in Federal Income Taxes
  Resulting From the Following Items:
    Depreciation                                    10,945              11,932               14,184
    Corporate Owned Life Insurance                  (3,974)             (2,298)              (5,304)
    Removal Costs                                   (4,200)             (5,460)              (5,040)
    Investment Tax Credits (net)                    (5,181)             (5,602)              (5,465)
    Other                                           (4,127)             (2,593)              (4,259)
Total Federal Income Taxes as Reported             $54,835             $65,801             $ 53,355 

Effective Federal Income Tax Rate                     31.3%               33.0%                31.5%
</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,    
                                    1997       1996
                                    (in thousands)

Deferred Tax Assets              $ 144,869  $ 137,932
Deferred Tax Liabilities          (803,524)  (807,896)
  Net Deferred Tax Liabilities   $(658,655) $(669,964)

Property Related Temporary
  Differences                    $(491,904) $(487,316)
Amounts Due From Customers For
  Future Federal Income Taxes     (108,727)  (109,259)
Deferred State Income Taxes        (75,476)   (80,201)
All Other (net)                     17,452      6,812 
    Total Net Deferred
      Tax Liabilities            $(658,655) $(669,964)

     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.

<PAGE>
     The AEP System has settled with the United States Internal
Revenue Service(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 open and under audit by the
IRS.  During the audit the IRS agents requested a ruling from their
National Office that certain interest deductions relating to corporate
owned life insurance (COLI) claimed by the Company should not be
allowed.  The COLI program was established in 1990 as part of the
Company's strategy to fund and reduce the cost of medical benefits for
retired employees.  AEP filed a brief with the IRS National Office
refuting the agents' position.  Although no adjustments have been
proposed, a disallowance of the COLI interest deductions through
December 31, 1997 would reduce earnings by approximately $72 million
(including interest).  Management believes it has meritorious defenses
and will vigorously contest any proposed adjustments.  No provisions
for this amount have been recorded.  In the event the Company is
unsuccessful it could have a material adverse impact on results of
operations and cash flows.


10.  COMMON SHAREHOLDER'S EQUITY:

     The Company received from AEP Co., Inc. cash capital
contributions of $40 million, $50 million and $30 million in 1997,
1996 and 1995, respectively, which were credited to paid-in capital. 
In 1997, 1996 and 1995 net changes in paid-in capital of $(2,332,000),
$329,000 and $(9,357,000), 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 1997, 1996 and 1995.  At December 31, 1997
there were no dividend restrictions on retained earnings.  To pay
dividends out of paid-in capital, the Company needs regulatory
approval.


11.  SUPPLEMENTARY INFORMATION:

                             Year Ended December 31,  
                             1997      1996      1995
                                  (in thousands)
Cash was paid for:
  Interest (net of 
   capitalized amounts)    $115,508  $104,156 $102,145
  Income Taxes              $71,749   $82,194  $59,412

Noncash Acquisitions Under
   Capital Leases           $15,266   $15,308  $16,209


<PAGE>
12.  LONG-TERM DEBT AND LINES OF CREDIT:

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

                                    December 31,     
                                1997           1996
                                   (in thousands)

First Mortgage Bonds         $1,096,811    $1,056,495
Installment Purchase 
  Contracts                     234,217       234,047
Junior Debentures               160,948        72,733
Other Long-term Debt              2,559         2,567
                              1,494,535     1,365,842
Less Portion Due Within
  One Year                       79,509             8
  Total                      $1,415,026    $1,365,834

     First mortgage bonds outstanding were as follows:

                                   December 31,     
                                 1997       1996
                                  (in thousands)
% Rate  Due                 
7.00    1999 - December 1    $   30,000   $   30,000 
6.35    2000 - March 1           48,000         -
6.71    2000 - June 1            48,000         -
6-3/8   2001   March 1          100,000      100,000
7.95    2002 - March 1 (a)       60,000       60,000 
7.38    2002 - August 15         50,000       50,000 
7.40    2002 - December 1        30,000       30,000 
6.65    2003 - May 1             40,000       40,000 
6.85    2003 - June 1            30,000       30,000 
6.00    2003 - November 1        30,000       30,000 
7.70    2004 - September 1       21,000       21,000
7.85    2004 - November 1 (b)    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 
9.35    2021 - August 1            -          43,250
8.75    2022 - February 1        29,919       43,000 
8.70    2022 - May 22            35,000       35,000 
8.43    2022 - June 1            50,000       50,000 
8.50    2022 - December 1        70,000       70,000 
7.80    2023 - May 1             40,000       40,000 
7.90    2023 - June 1            30,000       30,000 
7.15    2023 - November 1        30,000       30,000 
7.125   2024 - May 1             50,000       50,000
8.00    2025 - June 1            50,000       50,000
Unamortized Discount             (5,108)      (5,755)
                              1,096,811    1,056,495
Less Portion Due Within
 One Year                        60,000         -   
  Total                      $1,036,811   $1,056,495 

(a)  Called for early redemption on March 1, 1998.
(b)  A one time put feature allows this series of bonds to be put
     back to the Company on November 1, 1999.  Consequently the bonds
     are classified as due in 1999.

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

     Installment purchase contracts have been entered into, in
connection with the issuance of pollution control revenue bonds by
governmental authorities as follows:

% Rate   Due                          December 31,    
                                    1997       1996
                                     (in thousands)
Industrial Development Authority of
 Russell County, Virginia:

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

Putnam County, West Virginia:

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

Mason County, West Virginia:

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

Unamortized Discount                (2,783)    (2,953)
                                   234,217    234,047
Less Portion Due Within
 One Year                           19,500       -   
  Total                           $214,717   $234,047 

     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>
     Junior debentures outstanding were as follows:

                                     December 31,     
                                1997            1996
                                   (in thousands)
8-1/4% Series A due 2026
  - September 30               $ 75,000       $75,000
8% Series B due 2027 
  - March 31                     90,000          -   
Unamortized Discount             (4,052)       (2,267)
  Total                        $160,948       $72,733

     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, 1997, future annual long-term debt payments are
as follows:

                                       Amount
                                   (in thousands)
 
  1998                               $   79,509   
  1999                                   80,004
  2000                                   96,005
  2001                                  100,006
  2002                                   80,006
  Later Years                         1,070,948   
    Total Principal Amount            1,506,478
  Unamortized Discount                   11,943
      Total                          $1,494,535

     Short-term debt borrowings are limited by provisions of the 1935
Act to $250 million.  Lines of credit are shared with other AEP System
companies and at December 31, 1997 and 1996 were available in the
amounts of $442 million and $409 million, respectively.  Facility fees
of approximately 1/10 of 1% of the short-term line of credit are
required to maintain the lines of credit.  Outstanding short-term debt
consisted of:
                                              Year-end
                               Balance        Weighted
                             Outstanding      Average
                           (in thousands)  Interest Rate

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

December 31, 1996:
  Commercial Paper             $60,700          7.3%

<PAGE>
13.  FAIR VALUE OF FINANCIAL INSTRUMENTS

     The carrying amounts 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.  At
December 31, 1997 and 1996 fair values for preferred stock subject to
mandatory redemption were $23 million and $192 million and for long-term
debt were $1.57 billion and $1.4 billion, respectively.  The
carrying amounts for preferred stock subject to mandatory redemption
were $22 million and $190 million and for long-term debt were $1,495
million and $1,366 million at December 31, 1997 and 1996,
respectively.  Fair values 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.


14. UNAUDITED QUARTERLY FINANCIAL INFORMATION:

Quarterly Periods       Operating  Operating     Net
     Ended               Revenues   Income     Income  
                                (in thousands)
1997
 March 31               $416,450    $64,334   $36,484
 June 30                 373,084     45,397    15,378
 September 30            438,510     64,780    34,753
 December 31             491,966     65,483    33,899

1996
 March 31               $440,972    $83,637   $55,624
 June 30                 379,887     43,219    16,106
 September 30            393,797     61,259    34,639
 December 31             410,213     54,761    27,320
<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, 1997
and 1996, and the related consolidated statements of income, retained
earnings, and cash flows for each of the three years in the period
ended December 31, 1997.  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, 1997 and 1996, and the
results of their operations and their cash flows for each of the three
years in the period ended December 31, 1997 in conformity with
generally accepted accounting principles.


/s/ Deloitte & Touche LLP


DELOITTE & TOUCHE LLP
Columbus, Ohio
February 24, 1998