<PAGE>
<PAGE>
<TABLE>
  Selected Consolidated Financial Data
<CAPTION>
                                                                       Year Ended December 31,                         
                                               1996             1995            1994             1993              1992     
                                                                           (in thousands)
<S>                                       <C>              <C>             <C>              <C>               <C>
INCOME STATEMENTS DATA:
  Operating Revenues                      $1,624,869       $1,545,039      $1,535,500       $1,519,104        $1,410,778 
  Operating Expenses                       1,381,993        1,317,937       1,330,282        1,289,764         1,176,882 
  Operating Income                           242,876          227,102         205,218          229,340           233,896 
  Nonoperating Income (Loss)                     128           (4,699)         (4,716)          (3,353)            3,036 
  Income Before Interest Charges             243,004          222,403         200,502          225,987           236,932 
  Interest Charges                           109,315          106,503          98,157          100,855           105,513 
  Net Income                                 133,689          115,900         102,345          125,132           131,419 
  Preferred Stock Dividend Requirements       15,938           16,405          15,660           16,540            16,596 
  Earnings Applicable to Common Stock     $  117,751       $   99,495      $   86,685       $  108,592        $  114,823 
<CAPTION>                                                                                                                     
                                                                       December 31,                     
                                            1996             1995            1994             1993              1992     
                                                                        (in thousands)                   
<S>                                       <C>              <C>             <C>              <C>               <C>            
BALANCE SHEETS DATA:                                                                                                         
  Electric Utility Plant                  $4,717,132       $4,558,436      $4,398,727       $4,193,700        $4,038,735       
  Accumulated Depreciation and
     Amortization                          1,782,017        1,694,746       1,627,852        1,550,855         1,477,078 
  Net Electric Utility Plant              $2,935,115       $2,863,690      $2,770,875       $2,642,845        $2,561,657 
  Total Assets                            $3,811,380       $3,735,378      $3,647,795       $3,491,674        $3,094,091 
  Common Stock and Paid-in Capital        $  835,838       $  785,509      $  764,866       $  755,292        $  741,509 
  Retained Earnings                          208,472          199,021         206,361          227,816           229,920 
  Total Common Shareholder's Equity       $1,044,310       $  984,530      $  971,227       $  983,108        $  971,429 
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption   $   29,815       $   55,000      $   55,000       $   55,000         $ 105,000 
    Subject to Mandatory Redemption (a)      190,000          190,235         190,385          160,537           108,509 
      Total Cumulative Preferred Stock    $  219,815       $  245,235      $  245,385       $  215,537         $ 213,509 
  Long-term Debt (a)                      $1,365,842       $1,285,684      $1,228,911       $1,215,168        $1,200,272 

  Obligations Under Capital Leases (a)    $   51,969       $   48,937      $   43,138       $   29,973        $   24,269 

  Total Capitalization and Liabilities    $3,811,380       $3,735,378      $3,647,795       $3,491,674        $3,094,091 
                        
(a) Including portion due within one year.
</TABLE>

<PAGE>
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Business Outlook

  With the issuance of two Federal Energy Regulatory Commission (FERC) orders
and the commencement of planning for retail competition at the state level,
we are in a better position to identify and develop strategies for addressing
the issues that face the American Electric Power (AEP) System, Appalachian
Power Company and our changing industry.  The industry's adjustment to
greater competition in the generation and sale of electricity, customer
choice and the ability to fully recover costs will probably be the most
significant factors affecting the Company's future profitability.

  Although the Company, as a member of the AEP System, has the financial
strength, geographic reach, location and cost structure to be an able
competitor, no assurance can be given that this position can be maintained. 
However, we intend to make every effort to maintain and strengthen our
competitive position.  We see a link between a smooth transition to a
competitive marketplace and the maintaining of a strong financial position.

  The new FERC orders facilitate increased competition in both the generation
and sale of bulk power to wholesale customers.  They provide, among other
things, for open access to transmission facilities.  AEP's support of the
FERC's open access transmission rule is evidenced by our being among the
first to file a comparability tariff, offering access to the AEP transmission
grid at 143 interconnections to all parties under the same terms and
conditions available to AEP affiliates.  This has provided greater
opportunities for transmission service sales.

  Although customer choice proposals and discussions are under way in the
states in which we operate, it is difficult to predict their result and the
timing of changes, if any.  We are actively involved in discussions on the
state and federal level regarding whether to and how best to transition to
competition in order to represent the best interests of our customers,
shareholders and employees.  We favor an orderly and smooth transition to a
more competitive energy market because we believe that AEP will do better in
the long term if it is free to compete.

  If 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 the new FERC orders provide, under
certain conditions, for recovery of stranded costs at the wholesale level,
the issue of stranded cost recovery remains open at the much larger state
retail level.

Stranded Costs

  Stranded costs occur when a customer switches to a new supplier for its
electric energy needs or when a component of the business, for example
generation, is no longer subject to cost-based regulation, creating the issue
of who pays for plant investment, purchased power or fuel contracts both 
non-affiliated and affiliated, inventories, construction work in progress, plant
removal and shutdown costs, previously deferred costs (regulatory assets) and
other investments and commitments that are no longer needed, economic or
recoverable in a competitive market.  The amount of any stranded costs the
Company may experience depends on the timing of and the extent to which
direct competition is introduced to our business and the then-existing market
price of energy.

  Under the provisions of 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
revenues) are included in the consolidated financial statements in accordance
with regulatory actions to match expenses and revenues in cost-based rates. 
In the event a portion of the business no longer met the requirements of SFAS
71, net regulatory assets would have to be written off for that portion of
the business and assets tested for possible impairment.  Whether an
impairment exists would depend on how low the market price of energy is in
competition relative to the cost of energy.

  Among other requirements the application of SFAS 71 requires that the rates
charged to customers be cost based.  Our generation business is still 
cost-based regulated and should remain so for the foreseeable future.  Should
enabling state legislation be enacted we believe there should be at least a
three to five year transition to full competition.  Although the recent FERC
orders provide for competition in the firm wholesale market, that market is a
relatively small part of our business and our firm wholesale sales are still
under cost-of-service contracts.  We believe that enabling state legislation
if enacted should provide for a sufficient transition period to allow for the
recovery of any generation-related stranded costs and we are dedicating
ourselves to working with regulators, customers and legislators to accomplish
both an orderly transition and a reasonable and fair disposition of the
stranded cost issue.  However, if the Company were to no longer be cost-based
regulated and recovery of stranded costs were not possible, results of
operations and financial condition would be adversely affected.

  Since state commissions have jurisdiction over the sale and distribution of
electricity to retail customers, we believe that state legislation and
regulation should shape the future competitive market for electricity while
federal legislation should seek to ensure reciprocity among the states and a
level playing field for all power suppliers.  Presently states with higher
cost power, like California, are aggressively pursuing deregulation. 
However, the states the Company operates in are addressing the call for
customer choice more cautiously.

Restructuring/Functional Unbundling

  In 1996 we took some major steps to maintain and enhance the Company's
competitive strength.  We restructured our management and operations to allow
us to comply with the new FERC orders which required separation of generation
and energy sales operations from our energy transmission and delivery
operations.  This has achieved and should continue to achieve staffing,
managerial and operating efficiencies.  The generation and marketing business
units are preparing for the possibility of competition in an open market for
customers.  Our energy delivery business expects to remain regulated and
ultimately be subject to some form of incentive or performance-based
ratemaking.  If competition never replaces regulation we will be a more
efficient and productive business as a result of our preparations which
should benefit all concerned.


  Marketing and customer service efforts have been enhanced with programs
like the Key Accounts Program which strives to build strong partnerships with
key customers in order to build customer loyalty.  In 1996 we also launched a
series of new television commercials to inform our customers that we will be
operating under the name, American Electric Power.  The commercials are
intended to position AEP as more than just a supplier of electricity.  We
want to be the energy and energy services provider of choice; AEP: America's
Energy Partner.

Cost Containment

  In 1996 we continued our efforts to reduce costs in order to maintain our
competitiveness.  Reviews of our major processes led to decisions to
consolidate the management and operations of internal service functions
performed at multiple locations.  Among the functions being consolidated are
fossil generation plant maintenance, system operations, accounting and load
research.  A study of the Company's procurement and supply chain operations
led to cost reductions through better inventory management, just-in-time
delivery and the increased use of electronic purchasing.  Also in 1996 we
completed the installation of an activity based management budgeting system. 
This tool will enable managers to better analyze work and control costs. 
While staff reductions and cost savings are being achieved in these and other
areas, expenses for new marketing programs, customer services and modern
efficient management information systems are being increased to prepare for
competition.  These expenditures for the future should produce further
improvements and efficiencies, enabling the Company to maintain its position
as a low-cost producer.

  Coal is 50% of the production cost of electricity.  Although our average
coal costs per unit of electricity (per Kwh) have declined by 45% since 1986,
we recognize that we must continue to manage our coal costs to maintain our
competitive position.  As long-term coal supply contracts expire we are
negotiating with non-affiliated suppliers to lower purchased 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 Matters

  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 its 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.

Hazardous Material

  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, the generating plants and transmission and distribution facilities
have used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and
non-hazardous materials.  The Company is  currently incurring costs to safely
dispose of such substances, and additional costs could be incurred to comply
with new laws and regulations if enacted.

  The Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA or Superfund) addresses clean-up of hazardous substances at disposal
sites and authorizes the United States Environmental Protection Agency
(Federal EPA) to administer the clean-up programs.  As of year-end 1996,
there are two sites for which the Company has received information requests
which could lead to "Potentially Responsible Party" (PRP) designation.  The
Company's present estimates do not anticipate material cleanup costs for
identified  sites for which the Company is involved.  However, if for reasons
not currently identified significant costs are incurred for cleanup, future
results of operations and possibly financial condition would be adversely
affected unless the costs can be recovered.

Federal EPA Actions

  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 emissions that must be met after January 1,
2000 (Phase II of the CAAA).  The final rules will require substantial
reductions in nitrogen oxide emissions from certain types of  power  plant 
boilers  including those  in the Company's power plants.  In December 1996 a
group of utilities including the Company filed a petition for review of the
rules in a U.S. Court of Appeals and requested expedited consideration of the
appeal.  The cost to comply with the emission reductions required by the
final rules is expected to be substantial and could have a material adverse
impact on results of operations and possibly financial condition if not
recovered from customers.

  Federal EPA is considering proposals to revise the existing ambient air
quality standard for ozone and to establish a new ambient air quality
standard for fine particulate matter.  The rules being considered could
result in further requirements for reductions of nitrogen oxides and sulfur
dioxide emitted from coal fired power plants and could have a significant
impact on operations.  The proposals being considered are of particular
concern because they do not have a sound scientific basis.  The cost of
complying with any new emission reduction requirements imposed as a result of
the adoption of revised ambient air quality standards can not be precisely
determined but could be substantial.  If Federal EPA ultimately promulgates
stricter ambient air quality standards, they could have a material adverse
impact on results of operations and possibly financial condition if these
costs are not recovered from customers.

Results of Operations

  Net income increased by $17.8 million or 15% in 1996 mainly due to
increased sales of energy and services.  Sales increased 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 were the effect of severance
pay charges recorded in 1995 in connection with a management and operations
realignment and gains recorded in 1996 from emission allowance transactions. 
In 1995 net income increased by $13.6 million or 13% due to a reduction in
AEP System Power Pool (Power Pool) capacity charges.  The reduction in Power
Pool capacity charges resulted from a decrease in the Company's prior 
twelve-month peak demand relative to the total peak demand of all Power Pool
members.  Power Pool members like the Company whose internal demand exceeds
their capacity are allocated capacity costs by the Power Pool based on the
relative peak demands and generating reserves of all Power Pool members. 

Operating Revenues and Energy Sales Increase

  Operating revenues increased 5% in 1996 and 1% in 1995.  Increased
wholesale energy sales,  transmission and coal conversion service revenues
were the primary reasons for the increase in 1996 revenues.  Increased energy
usage by retail customers and growth in the number of retail customers
increased revenues in 1995.  The following is a price/volume analysis of
revenues:

                               Increase (Decrease)
                               From Previous Year     
(dollars in millions)       1996           1995       
                         Amount    %    Amount     %
Retail:
  Price variance         $  1.4         $ 20.2
  Volume variance          14.4           39.3
  Fuel and Purchased
   Power Recoveries       (13.6)         (23.5)
                            2.2   0.2     36.0    3.0
Wholesale:
  Price variance         (145.8)         (17.4)
  Volume variance         211.8           (1.8)
  Fuel Cost Recoveries     (2.7)          (2.7)
                           63.3  23.5    (21.9)  (7.5)

Other Operating Revenues   14.3           (4.6)
         Total           $ 79.8   5.2   $  9.5    0.6

  Wholesale revenues increased 23% in 1996 reflecting a 77% increase in
wholesale sales.  The Company's share of Power Pool sales increased 38% as a
result of increased transactions with power marketers and other utilities. 
The Company through the Power Pool shared in sales of a new product, coal
conversion services which resulted in 2.2 billion kilowatthours of
electricity being provided to power marketers and certain other utilities
under a new Federal Energy Regulatory Commission approved interruptible
tariff.  Since these new sales are for the service of converting the
customers' coal to electricity and do not include recovery of a fuel cost,
the average wholesale price per kilowatthour was significantly less in 1996
than in 1995.  Energy sales to the Power Pool increased mainly due to
increased demand for electric energy by customers of the other affiliated
Power Pool members.

  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 an increase in transmission service revenues.  As a result
transmission revenues, which are recorded as other operating revenues,
increased by approximately $12 million.

  The modest increase in 1995 operating revenues resulted from a 5% increase
in sales to retail customers and the effect of a rate increase in the
Virginia jurisdiction partly offset by a reduction in revenues from wholesale
customers.  Energy sales to residential customers, which is the most weather-
sensitive customer class, rose over 6% in 1995 mainly as a result of
increased weather related usage in the last half of the year reflecting
unseasonably warm summer weather in 1995 and colder weather in the fourth
quarter of 1995 compared with the weather in the prior year. Sales to
commercial and industrial customers rose 6% and 2%, respectively, in 1995,
reflecting the addition of 2,531 new customers, the effects of weather and
economic growth in the Company's service area.

  Revenues from wholesale customers declined 7.5% in 1995 reflecting the
effect of increased competition on the price of wholesale energy while sales
were relatively flat.

Operating Expenses

  Operating expense increased by approximately 5% in 1996 reflecting
increases in all expense categories except for maintenance expense while the
decrease of 1% in 1995 was  largely due to a decline in fuel and purchased
power expenses.  Changes in the components of operating expenses were as
follows:

                               Increase (Decrease)
                               From Previous Year
(dollars in millions)        1996             1995    
                       Amount      %    Amount     %

Fuel                   $ 18.9     5.4   $(42.1) (10.8)
Purchased Power          32.9    11.0    (15.7)  (5.0)
Other Operation          18.5     8.3     25.7   13.1
Maintenance             (22.1)  (15.8)     5.5    4.1
Depreciation and
  Amortization            0.1      -       4.8    3.7
Taxes Other Than 
  Federal Income Taxes    3.2     2.7     (2.4)  (2.0)
Federal Income Taxes     12.6    21.8     11.9   25.9
  Total                $ 64.1     4.9   $(12.3)  (0.9)

  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 substantial decrease in 1995 fuel expense was due
to a decrease in coal-fired generation.  The decrease in generation generally
resulted from the increased availability of an affiliate's low cost nuclear
powered units.  When the availability of the affiliate's lower cost nuclear
units is increased, the Company decreases its generation for delivery to the
Power Pool.  Also contributing to the decrease in 1995 fuel expense was a lower
average cost of fuel.  Coal prices declined in 1995 primarily due to the
renegotiation of certain long-term coal contracts.

  Increased purchases of energy from the Power Pool in 1996 to meet the
increased demand for energy and an increase in Power Pool capacity charges
accounted for the rise in purchased power expense. 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.  Purchased
power expense declined in 1995 due to a reduction in Power Pool capacity charges
and reduced purchases from unaffiliated utilities for pass-through sales to
other unaffiliated utilities.  Capacity charges declined due to a decrease in
the Company's prior twelve-month peak demand relative to the total peak demand
of all Power Pool members.

  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 Virginia State Corporation Commission (Virginia SCC); an increase
in employee benefit costs; and higher costs relating 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 realignment of AEP's operations.

  The increase in other operation expense in 1995 was due to the provisions for
severance pay; costs associated with the development of a new activity based
budgeting system; increased employee benefit costs; and the effect of a $4.6
million favorable adjustment in 1994 which capitalized previously expensed
software costs in accordance with an order of the Virginia SCC.

  Maintenance expense declined in 1996 after increasing in 1995.  These
fluctuations are primarily the result of accounting for incremental storm damage
expense in accordance with directions of the Virginia SCC.

  Federal income taxes attributable to operations increased in 1996 and 1995
primarily due to an increase in pre-tax operating income.

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

  Interest charges increased in 1995 primarily as a result of an increase in the
balance of long-term debt outstanding. 

Construction Spending

  Total plant and property additions were $207  million in 1996 and $232 million
in 1995.  Management estimates construction expenditures for the next three
years to be $596 million.  Funds for construction of new facilities and
improvement of existing facilities come from a combination of internally
generated funds, short-term and long-term borrowings and equity investments by
the Company's parent, American Electric Power Company, Inc. (AEP  Co., Inc.). 
Approximately 86% of the construction expenditures for the next three years are
expected to be financed with internally generated funds.

Capital Resources

  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, 1996, $409 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 Public Utility Holding Company Act
of 1935 to $250 million.  Periodic reductions of outstanding short-term debt are
made through issuances of  long-term debt and preferred stock and additional
capital contributions by the parent company.

  The Company's earnings coverage presently exceeds 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, 1996, the mortgage bonds and preferred stock coverage ratios 
were 3.98 and 1.99, respectively.

  In January 1997 a tender offer was announced for all of the Company's
preferred stock in conjunction with a special meeting scheduled to be held on
February 28, 1997.  The special meeting's purpose is to consider amendments to
the Company's articles of incorporation to remove certain capitalization ratio
requirements.  These restrictions limit the Company's financial flexibility and
could place it at a competitive disadvantage in the future.  The amount paid 
to redeem the preferred stock that is tendered could total as much as $219 
million. A combination of short-term debt and unsecured long-term debt is 
expected to be used to pay for the preferred stock tendered.

Litigation

  The Company is involved in a number of 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 and/or financial condition.

Effects of Inflation

  Inflation affects the Company s cost of replacing utility plant and the cost
of operating and maintaining 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 the negative impact of inflation.

Corporate Owned Life Insurance

  In connection with the audit of the AEP System s  1991, 1992 and 1993
consolidated federal income tax returns the Internal Revenue Service (IRS)
agents sought a ruling from the IRS National Office that certain interest
deductions relating to a corporate owned life insurance (COLI) program should
not be allowed.  The Company established the COLI program in 1990 as a 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.  Although no adjustments have been proposed, a disallowance of the
COLI interest deductions through December 31, 1996 would reduce earnings by
approximately $62 million (including interest).  Management believes it will
ultimately prevail on this issue and will vigorously contest any disallowance
that may be assessed.

  In 1996 Congress enacted legislation that prospectively phases out the tax
benefits for COLI interest deductions over a three-year period beginning in
1996.  As a result the Company intends to restructure its COLI program.  The
restructuring of the COLI program is not expected to have a material impact on
results of operations.

New Accounting Rule

  In 1996 the Financial Accounting Standards Board (FASB) issued an exposure
draft "Accounting for Certain Liabilities Related to Closure or Removal of 
Long-Lived Assets."  The Company generally records such liabilities over the 
life of its plant commensurate with rate recovery.  The exposure draft proposes 
that the present value of certain closure or removal obligations be recorded as 
a liability when the obligation is incurred.  A corresponding asset would be
recorded in the plant investment account and recovered through depreciation
charges over the asset's life.  A proposed transition rule would require that
an entity report in income the cumulative effect of initially applying the new
standard.  However, as a cost-based rate-regulated entity, the Company would
expect to record a corresponding regulatory asset for the cumulative effect of
initially applying the new standard.  The FASB is reconsidering several aspects
of the exposure draft.  It is unclear at this time what, if any, changes the
FASB will make to the proposal.  Until it becomes apparent what the FASB will
decide and how certain questions raised by the exposure draft are resolved the
Company cannot determine its ultimate impact.


<PAGE>
<PAGE>
<TABLE>
  Consolidated Statements of Income
<CAPTION>
                                                                             Year Ended December 31,               
                                                                1996                1995                  1994     
                                                                              (in thousands)                       
  <S>                                                         <C>                 <C>                   <C>                    
  OPERATING REVENUES                                          $1,624,869          $1,545,039            $1,535,500             
  
  OPERATING EXPENSES:                                                                                                          
     Fuel                                                        367,651             348,776               390,864       
     Purchased Power                                             333,014             300,086               315,818 
     Other Operation                                             240,249             221,783               196,097 
     Maintenance                                                 117,483             139,566               134,092 
     Depreciation and Amortization                               133,074             132,999               128,192 
     Taxes Other Than Federal Income Taxes                       120,307             117,093               119,458 
     Federal Income Taxes                                         70,215              57,634                45,761 
                  Total Operating Expenses                     1,381,993           1,317,937             1,330,282 

  OPERATING INCOME                                               242,876             227,102               205,218 

  NONOPERATING INCOME (LOSS)                                         128              (4,699)               (4,716)

  INCOME BEFORE INTEREST CHARGES                                 243,004             222,403               200,502 

  INTEREST CHARGES                                               109,315             106,503                98,157 

  NET INCOME                                                     133,689             115,900               102,345 
                                                                                                                   
  PREFERRED STOCK DIVIDEND REQUIREMENTS                           15,938              16,405                15,660 

  EARNINGS APPLICABLE TO COMMON STOCK                         $  117,751          $   99,495            $   86,685 


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

                                                             December 31,          
                                                          1996            1995     
                                                           (in thousands)          
ASSETS
<S>                                                     <C>             <C>          
ELECTRIC UTILITY PLANT:
   Production                                           $1,883,271      $1,857,621 
   Transmission                                          1,054,207       1,041,415 
   Distribution                                          1,495,445       1,409,407 
   General                                                 188,740         169,602 
   Construction Work in Progress                            95,469          80,391 
                 Total Electric Utility Plant            4,717,132       4,558,436 
   Accumulated Depreciation and Amortization             1,782,017       1,694,746 

                 NET ELECTRIC UTILITY PLANT              2,935,115       2,863,690 

OTHER PROPERTY AND INVESTMENTS                              29,621          31,523 

CURRENT ASSETS:
   Cash and Cash Equivalents                                 7,260           8,664 
   Accounts Receivable:
      Customers                                            122,969         126,613 
      Affiliated Companies                                  15,017           7,721 
      Miscellaneous                                         22,035           8,077 
      Allowance for Uncollectible Accounts                    (687)         (2,253)
   Fuel - at average cost                                   52,605          69,037 

   Materials and Supplies - at average cost                 56,605          55,756 
   Accrued Utility Revenues                                 51,843          65,078 
   Prepayments                                              10,797           8,579 
                 TOTAL CURRENT ASSETS                      338,444         347,272 

REGULATORY ASSETS                                          451,272         435,352 

DEFERRED CHARGES                                            56,928          57,541 

                     TOTAL                              $3,811,380      $3,735,378 

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

                                                              December 31,         
                                                          1996             1995     
                                                             (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                                        575,380          525,051 
   Retained Earnings                                      208,472          199,021 
                Total Common Shareholder's Equity       1,044,310          984,530 
   Cumulative Preferred Stock:
       Not Subject to Mandatory Redemption                 29,815           55,000 
       Subject to Mandatory Redemption                    190,000          190,085 
   Long-term Debt                                       1,365,834        1,278,433 
                TOTAL CAPITALIZATION                    2,629,959        2,508,048 

OTHER NONCURRENT LIABILITIES                              109,203          102,178 

CURRENT LIABILITIES:                                                               
   Long-term Debt Due Within One Year                            8           7,251 
   Short-term Debt                                         60,700          125,525 
   Accounts Payable - General                              34,714           36,424 
   Accounts Payable - Affiliated Companies                 51,178           45,800 
   Taxes Accrued                                           40,935           48,666 
   Customer Deposits                                       13,750           14,411 
   Interest Accrued                                        20,938           19,057 
   Other                                                   80,352           75,303 
                TOTAL CURRENT LIABILITIES                 302,575          372,437 

DEFERRED INCOME TAXES                                     669,964          656,006 

DEFERRED INVESTMENT TAX CREDITS                            83,320           89,682 

DEFERRED CREDITS                                           16,359            7,027 

COMMITMENTS AND CONTINGENCIES (Note 4)

                    TOTAL                              $3,811,380       $3,735,378 
</TABLE>
<PAGE>
<PAGE>
<TABLE>
  Consolidated Statements of Cash Flows
<CAPTION> 
                                                                              Year Ended December 31,               
                                                                   1996                1995                  1994     
                                                                                 (in thousands)                       
  <S>                                                            <C>                  <C>                   <C>             
  OPERATING ACTIVITIES:
     Net Income                                                  $ 133,689            $ 115,900             $ 102,345 
     Adjustments for Noncash Items:
        Depreciation and Amortization                              134,381              134,485               130,694 
        Deferred Federal Income Taxes                                  592                  647                17,355 
        Deferred Investment Tax Credits                             (5,602)              (5,465)               (5,492)
        Deferred Power Supply Costs (net)                              293               (3,721)                9,356 
        Provision for Rate Refunds                                  (2,626)              15,224                (8,780)
     Changes in Certain Current Assets and Liabilities:
        Accounts Receivable (net)                                  (19,176)             (16,896)                7,600 
        Fuel, Materials and Supplies                                15,583               (9,761)              (24,800)
        Accrued Utility Revenues                                    13,235              (13,392)                6,608 
        Accounts Payable                                             3,668              (11,488)               25,554 
        Taxes Accrued                                               (7,731)              14,043               (17,505)
     Other (net)                                                     9,437               28,324               (24,933)
          Net Cash Flows From Operating Activities                 275,743              247,900               218,002 

  INVESTING ACTIVITIES:
     Construction Expenditures                                    (191,815)            (216,200)             (230,531)
     Proceeds from Sales of Property                                 1,933                7,793                   948 
          Net Cash Flows Used For Investing Activities            (189,882)            (208,407)             (229,583)

  FINANCING ACTIVITIES:                                                                         
     Capital Contributions from Parent Company                      50,000               30,000                10,000 
     Issuance of Cumulative Preferred Stock                        -                    -                      29,574 
     Issuance of Long-term Debt                                    273,340              128,785                70,443 
     Retirement of Cumulative Preferred Stock                      (25,904)                (150)                 (152)
     Retirement of Long-term Debt                                 (195,910)             (74,950)              (58,236)
     Change in Short-term Debt (net)                               (64,825)               2,700                83,325 
     Dividends Paid on Common Stock                               (108,300)            (106,836)             (108,140)
     Dividends Paid on Cumulative Preferred Stock                  (15,666)             (15,675)              (14,562)
          Net Cash Flows From (Used For)
            Financing Activities                                   (87,265)             (36,126)               12,252 
  Net Increase (Decrease) in Cash and Cash Equivalents              (1,404)               3,367                   671 

  Cash and Cash Equivalents January 1                                8,664                5,297                 4,626 
  Cash and Cash Equivalents December 31                        $     7,260           $    8,664           $     5,297 

  See Notes to Consolidated Financial Statements.
  </TABLE>
  <PAGE>
  <PAGE>        
  <TABLE>                                                              
  Consolidated Statements of Retained Earnings                                                              
                                                                          
  <CAPTION>                                                                        
                                                                          Year Ended December 31,                     
                                                      1996                         1995                        1994    
                                                                              (in thousands)                               
  <S>                                                <C>                          <C>                         <C>        
  Retained Earnings January 1                        $199,021                     $206,361                    $227,816 
  Net Income                                          133,689                      115,900                     102,345 
                                                      332,710                      322,261                     330,161 
  Deductions:
     Cash Dividends Declared:
       Common Stock                                   108,300                      106,836                     108,140 
       Cumulative Preferred Stock:
          4-1/2% Series                                 1,348                        1,350                       1,350 
          4.50%  Series                                     9                           16                          22 
          5.90%  Series                                 2,950                        2,950                       2,950 
          5.92%  Series                                 3,552                        3,552                       3,552 
          6.85%  Series                                 2,055                        2,055                       1,296 
          7.40%  Series                                 1,385                        1,850                       1,850 
          7.80%  Series                                 3,900                        3,900                       3,900 
                 Total Cash Dividends Declared        123,499                      122,509                     123,060 
     Capital Stock Expense                                739                          731                         740 
                 Total Deductions                     124,238                      123,240                     123,800 
  Retained Earnings December 31                      $208,472                     $199,021                    $206,361 


  See Notes to Consolidated Financial Statements.

  </TABLE>
<PAGE>
<PAGE>
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,
transmission and distribution of electric power to 867,000 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 Power Pool and a signatory company to the AEP 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 Virginia
State Corporation Commission (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.

Use of Estimates

  The preparation of these financial statements in conformity with generally
accepted accounting principles requires in certain instances the use of
management's 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 from the plant accounts and
associated removal costs, net of salvage, are deducted from accumulated
depreciation.  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 recovered with
regulator approval over the service life of utility plant through
depreciation and 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 1996,
1995 and 1994 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.

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:

                          Composite
Functional Class          Depreciation
of Property               Annual Rates

Production:
  Steam                       3.4%
  Hydro                       2.8%
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 the over and
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 reviewed annually by the Virginia SCC.  In the West
Virginia jurisdiction, deferral accounting for the over and under collection
of fuel and Power Pool capacity charges which are described in Note 5
incurred from November 1993 through October 1996 was suspended as a result of
a three-year freeze on fuel rates.  For the period November 1996 through
December 1999 deferral accounting will be practiced for the over and under
collection of fuel, Power Pool capacitiy charges and certain transmission
revenue.  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.  Over-recoveries 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.  See Note 3.

   Wholesale jurisdictional fuel cost changes are expensed and billed as
incurred.

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

   The Company's policy was to account for investment tax credits under the
flow-through method except where regulatory commissions reflected investment
tax credits in the rate-making process on a deferral basis.  Deferred
investment tax credits, which represent a regulatory liability, are being
amortized over the life of the related plant investment commensurate with
recovery in rates.

Debt and Preferred Stock

   Gains and losses on reacquired 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.

   Commensurate with ratemaking, 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 deferred,
debited to paid-in capital and amortized to retained earnings in accordance
with rate-making treatment.  The excess of par value over costs 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.


2. EFFECTS OF REGULATION:

   In accordance with SFAS 71 the consolidated financial statements include
assets (deferred expenses) and liabilities (deferred income) recorded in
accordance with regulatory actions to match expenses and revenues in cost-based 
rates.  Regulatory assets are expected to be recovered in future
periods through the rate-making process and the 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 71.  Among other things  application of SFAS 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 would have to be tested for possible impairment.

   Regulatory assets and liabilities are comprised of the following:
                                    December 31,      
                                 1996          1995
                                   (in thousands)
Regulatory Assets:
  Amounts Due From Customers
    For Future Income Taxes    $392,372      $379,104
  Unamortized Loss On
    Reacquired Debt              25,567        26,075
  Deferred Storm Damage          10,990        10,308
  Other                          22,343        19,865
  Total Regulatory Assets      $451,272      $435,352

Regulatory Liabilities:
  Deferred Investment Tax
    Credits                     $83,320       $89,682
  Other*                         10,384         2,645
  Total Regulatory Liabilities  $93,704       $92,327

* Included in Deferred Credits on Consolidated Balance Sheets.


3. RATE MATTERS:

    On May 24, 1996 the Virginia SCC issued a final order related to a 1994
base rate request for an increase of $15.7 million annually and denied the
Company's request.  The request included, among other things, recovery over
three years of $23.9 million of incremental storm damage expenses deferred in
1994.  The Virginia SCC had authorized the Company to collect the rate
increase subject to refund beginning in November 1994.  The Order concluded
that the Company had recovered $11.9 million of the 1994 deferred incremental
storm damage expenses through existing rates with the remaining net deferred
storm damage expenses to be amortized commensurate with recovery over a five-
year period effective July 1, 1996.  The revenue refund liability of $26.5
million, including interest of $1.9 million, was completed in September 1996.

     Under the terms of a 1993 settlement agreement in the West Virginia
jurisdiction, the Company agreed to a 3-year base rate freeze and suspension
of the WVPSC Expanded Net Energy Cost (ENEC) recovery mechanism until October
31, 1996.  Under the terms of a 1996 settlement agreement which was approved
by the WVPSC on December 27, 1996, the Company agreed to reduce base rates by
$5 million annually, reduce the ENEC rates by $28 million annually and not
request a rate increase to become effective prior to January 1, 2000.  The
approved rate reductions were retroactive to November 1, 1996.  During the
period rates are fixed, ENEC cost variances would be subject to deferral
accounting and a cumulative ENEC recovery balance would be maintained.  The
parties agreed that regardless of the actual balance in this cumulative
recovery balance at December 31, 1999, ratepayers will not be responsible for
any cumulative underrecovery.  ENEC over-recoveries 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.


4. COMMITMENTS AND CONTINGENCIES:

Construction and Other Commitments

   Substantial construction commitments have been made.  Such commitments do
not include any expenditures for new generating capacity.  The aggregate
construction program expenditures for 1997-1999 are estimated to be $596
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.

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 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 $54.8 million in 1996, $26.3 million in 1995
and $32.3 million in 1994 for energy supplied to the Power Pool.

<PAGE>
   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,    
                       1996        1995        1994
                              (in thousands)

Capacity Charges      $125,456   $116,821    $138,517
Energy Charges         187,754    161,531     147,655

     Total            $313,210   $278,352    $286,172

   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 $127 million in 1996, $92 million in 1995
and $103.8 million in 1994. 

     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 $14.7
million in 1996, $18.8 million in 1995 and $27.5 million in 1994.   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, an affiliated
distribution utility that is not a member of the Power Pool, was included in
operating revenues in the amounts of $59.5 million in 1996, $58.7 million in
1995 and $61.1 million in 1994.

  Purchased power expense includes $5.1 million in 1996, $2.9 million in 1995
and $2.1 million in 1994 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, other operation expense includes equalization charges of $6.5
million, $5.4 million and $10.2 million in 1996, 1995 and 1994, respectively.

  The Company and an affiliate, Ohio Power Company, 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.

<PAGE>
   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, 1996, 1995 and 1994 were $4.2
million, $2.7 million and $5.3 million, respectively.

     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 $4.1 million in 1996, $4.3
million in 1995, and $4.2 million in 1994.

     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 $19 million in 1996, $19.5 million in 1995 and $19.4
million in 1994.  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 $8.4 million in 1996, $9.5 million in 1995 and
$11.6 million in 1994.


<PAGE>
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, 
                               1996     1995     1994
                                   (in thousands)

Operating Leases              $ 9,567  $ 8,600  $ 9,490
Amortization of 
  Capital Leases               12,175   11,003    8,878
Interest on Capital Leases      3,416    4,120    4,585
Total Rental Costs            $25,158  $23,723  $22,953

  Properties under capital leases and related obligations recorded on the
Consolidated Balance Sheets are as follows:
                                     December 31,    
                                   1996        1995
                                    (in thousands)
Electric Utility Plant:
  Production                     $ 9,366      $ 8,455
  General                         73,420       66,281
      Total Electric Utility 
         Plant                    82,786       74,736
  Accumulated Amortization        30,817       25,799
      Net Properties under
          Capital Leases         $51,969      $48,937

Capital Lease Obligations:
  Noncurrent Liability           $36,857      $36,739
  Liability Due Within One Year   15,112       12,198
    Total Capital Lease 
      Obligations                $51,969      $48,937

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

<PAGE>
   Future minimum lease payments consisted of the following at
December 31, 1996:
                                                          Non-    
                                                      Cancelable  
                                          Capital      Operating  
                                          Leases         Leases   
                                              (in thousands)      

     1997                                     $18,029    $ 6,335  
     1998                                      13,654      4,920  
     1999                                      12,822      4,354  
     2000                                      11,037      3,616  
     2001                                       9,762      1,803  
     Later Years                               22,629      8,786  

     Total Future Minimum Lease Rentals        87,933    $29,814  

     Less Estimated Interest Element           35,964             

     Estimated Present Value of Future
       Minimum Lease Payments                 $51,969             



8.  CUMULATIVE PREFERRED STOCK:

   The authorized shares of no par value cumulative preferred stock is
8,000,000 shares.  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.

   In January 1997 a tender offer for all outstanding preferred stock was
announced.  In conjunction with the tender offer a special shareholders
meeting is scheduled to be held on February 28, 1997 for the purpose of
considering amendments to the Company's articles of incorporation to remove
certain capitalization ratio requirements.

<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                1996                   Year Ended December 31,        December 31, 1996      1996       1995 
                                            1996      1995      1994                                (in thousands)
<S>                 <C>                   <C>         <C>       <C>             <C>             <C>         <C>
4-1/2%              $110.00                 1,850      -         -              298,150         $29,815     $30,000
7.40%                   -                 250,000      -         -                 -               -         25,000
                                                                                                $29,815     $55,000

Cumulative Preferred Stock Subject to Mandatory Redemption:
<CAPTION>
                   Call Price                                                     Shares               Amount       
                  December 31,             Number of Shares Redeemed           Outstanding          December 31,    
Series(a)             1996                   Year Ended December 31,        December 31, 1996      1996       1995 
                                            1996      1995      1994                                (in thousands)
<S>                 <C>                     <C>       <C>       <C>              <C>            <C>        <C>         
4.50%                                       2,348     1,500     1,517               -           $   -      $    235
7.80% (b)           $107.80                  -         -         -               500,000          50,000     50,000
5.90% (c)              (f)                   -         -         -               500,000          50,000     50,000
5.92% (d)              (f)                   -         -         -               600,000          60,000     60,000
6.85% (e)              (g)                   -         -        N/A              300,000          30,000     30,000

                                                                                                $190,000   $190,235

N/A - Not applicable, shares were issued in a subsequent year.
(a) The sinking fund provisions of series subject to mandatory redemption
aggregate $2,500,000 in 1998, $2,500,000 in 1999, $8,500,000 in 2000 and
$8,500,000 in 2001.
(b) Commencing in 1998, a sinking fund for the 7.80% cumulative preferred
stock will require the redemption of 25,000 shares at $100 a share on or
before May 1 in each year.  The Company has the non-cumulative option to
redeem up to 25,000 additional shares on any sinking fund date at a
redemption price of $100 per share.
(c) Commencing in 2003 and continuing through the year 2007, a sinking fund
for the 5.90% cumulative preferred stock will require the redemption of
25,000 shares each year and the redemption of the remaining outstanding
shares on November 1, 2008, in each case at $100 per share.
(d) Commencing in 2003 and continuing through the year 2007, a sinking fund
for the 5.92% cumulative preferred stock will require the redemption of
30,000 shares each year and the redemption of the remaining shares
outstanding on November 1, 2008, in each case at $100 per share.
(e) Shares issued June 1994.  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.
(f) Not callable until after 2002.
(g) Not callable until after 1999.
</TABLE>
<PAGE>
9. FEDERAL INCOME TAXES:
  The details of federal income taxes as reported are as follows:
<TABLE>                                                                   
<CAPTION>                                                                   
                                                                   Year Ended December 31,          
                                                            1996             1995             1994
                                                                        (in thousands)
<S>                                                       <C>               <C>              <C>
Charged (Credited) to Operating Expenses (net):
  Current                                                 $71,648           $58,676          $28,779
  Deferred                                                  1,283             1,715           19,763 
  Deferred Investment Tax Credits                          (2,716)           (2,757)          (2,781)
           Total                                           70,215            57,634           45,761 
Charged (Credited) to Nonoperating Income (net):
  Current                                                    (837)             (503)          (1,043)
  Deferred                                                   (691)           (1,068)          (2,408)
  Deferred Investment Tax Credits                          (2,886)           (2,708)          (2,711)
           Total                                           (4,414)           (4,279)          (6,162)
Total Federal Income Taxes as Reported                    $65,801           $53,355          $39,599 
</TABLE>
  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.
<TABLE>
<CAPTION>
                                                                    Year Ended December 31,           
                                                            1996             1995             1994
                                                                        (in thousands)
<S>                                                       <C>              <C>              <C>
Net Income                                                $133,689         $115,900         $102,345 
Federal Income Taxes                                        65,801           53,355           39,599 
Pre-tax Book Income                                       $199,490         $169,255         $141,944 

Federal Income Taxes on Pre-tax Book Income at 
  Statutory Rate (35%)                                     $69,822         $ 59,239         $ 49,680 
Increase (Decrease) in Federal Income Taxes
  Resulting From the Following Items:
    Depreciation                                            11,932           14,184           11,103 
    Corporate Owned Life Insurance                          (2,298)          (5,304)          (5,050)
    Removal Costs                                           (5,460)          (5,040)          (4,200)
    Percentage Repair Allowance                             (1,797)          (2,945)          (2,813)
    Federal Income Tax Accrual Adjustments                    -                -              (3,100)
    Investment Tax Credits (net)                            (5,602)          (5,465)          (5,492)
    Other                                                     (796)          (1,314)            (529)
Total Federal Income Taxes as Reported                     $65,801         $ 53,355         $ 39,599 

Effective Federal Income Tax Rate                             33.0%            31.5%            27.9%

  The following tables show the elements of the net deferred tax liability
and the significant temporary differences giving rise to such deferrals:
                                     December 31,    
                                    1996       1995
                                    (in thousands)

Deferred Tax Assets              $ 137,932  $ 127,710
Deferred Tax Liabilities          (807,896)  (783,716)
  Net Deferred Tax Liabilities   $(669,964) $(656,006)

Property Related Temporary
  Differences                    $(487,316) $(482,003)
Amounts Due From Customers For
  Future Federal Income Taxes     (109,259)  (110,529)
Deferred State Income Taxes        (80,201)   (63,307)
All Other (net)                      6,812       (167)
    Total Net Deferred
      Tax Liabilities            $(669,964) $(656,006)
<PAGE>
   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 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 1993 are presently
being audited 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 for 1991 through
1993 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, 1996 would
reduce earnings by approximately $62 million (including interest). 
Management believes it will ultimately prevail on this issue and will
vigorously contest any adjustments that may be assessed.  Accordingly, no
provision for this amount has been recorded.  In the opinion of management,
the final settlement of open years will not have a material effect on results
of operations.


10.  COMMON SHAREHOLDER'S EQUITY:

  The Company received from AEP Co., Inc. cash capital contributions of $50
million, $30 million and $10 million in 1996, 1995 and 1994, respectively,
which were credited to paid-in capital.  In 1996, 1995 and 1994 net changes
in paid-in capital of $(416,000), $9,357,000 and $426,000, respectively,
represented gains and expenses of cumulative preferred stock transactions. 
There were no other material transactions affecting common stock and paid-in
capital accounts in 1996, 1995 and 1994.  At December 31, 1996 there were no
dividend restrictions on retained earnings.  To pay dividends out of paid-in
capital, the Company needs regulatory approval.


<PAGE>
11.  SUPPLEMENTARY INFORMATION:

                             Year Ended December 31,   
                             1996      1995      1994
                                  (in thousands)
Cash was paid for:
  Interest (net of 
   capitalized amounts)    $104,156  $102,145  $96,667
  Income Taxes               82,194    59,412   48,872

Noncash Acquisitions Under
   Capital Leases were       15,308    16,209   22,883


12.  LONG-TERM DEBT AND LINES OF CREDIT:

   Long-term debt by major category was outstanding as follows:
                                    December 31,     
                                1996           1995
                                   (in thousands)

First Mortgage Bonds         $1,056,495    $1,044,555
Installment Purchase 
  Contracts                     234,047       233,877
Debentures                       72,733         7,252
Other Long-term Debt              2,567          -   
                              1,365,842     1,285,684
Less Portion Due Within
  One Year                            8         7,251
  Total                      $1,365,834    $1,278,433

<PAGE>
   First mortgage bonds outstanding were as follows:

                                   December 31,     
                                 1996       1995
                                  (in thousands)

% Rate  Due                 
7-1/2   1998 - December 1    $     -      $   45,000 
7.00    1999 - December 1        30,000       30,000 
6-3/8   2001   March 1          100,000         -
7-5/8   2002 - February 1          -          43,350 
7.95    2002 - March 1           60,000       60,000 
7.38    2002 - August 15         50,000       50,000 
7-1/2   2002 - December 1          -          59,760 
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         -    
9-7/8   2020 - December 1          -          20,584 
9.35    2021 - August 1          43,250       50,000 
8.75    2022 - February 1        43,000       50,000 
8.70    2022 - May 22            35,000       40,000 
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 (net)       (5,755)      (5,139)

  Total                      $1,056,495   $1,044,555 

   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.

<PAGE>
  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,    
                                    1996       1995
                                     (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                (2,953)    (3,123)

  Total                           $234,047   $233,877 

   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.

   Debentures outstanding were as follows:

                                     December 31,     
                                1996            1995
                                   (in thousands)

8-1/4% Series A Deferrable
  Interest due 2026
  - September 30               $75,000         $ -
6% due 1996 - March 1            -              7,251
Unamortized Premium 
    (Discount) net              (2,267)             1
  Total                        $72,733         $7,252

<PAGE>
   At December 31, 1996, future annual long-term debt payments, excluding
premium or discount, are as follows:
                       Principal Amount
                        (in thousands) 
  1997                    $        8   
  1998                        19,509
  1999                        80,004
  2000                             5
  2001                       100,006
  Later Years              1,177,285   
    Total                 $1,376,817   

   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, 1996 and 1995 were available in the amounts of $409 million
and $372 million, respectively.  Commitment fees of approximately 1/8 of 1%
of the unused 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, 1996:
  Commercial Paper             $60,700          7.3%

December 31, 1995:
  Commercial Paper            $125,525          6.1%


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, 1996 and 1995
fair values for preferred stock subject to mandatory redemption were $192
million and $198 million and for long-term debt were $1,400 million and
$1,350 million, respectively.  The carrying amounts for preferred stock
subject to mandatory redemption were $190 million at December 31, 1996 and
1995 and for long-term debt were $1,366 million and $1,286 million at
December 31, 1996 and 1995, 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.


<PAGE>
14. UNAUDITED QUARTERLY FINANCIAL INFORMATION:

Quarterly Periods       Operating  Operating     Net
     Ended               Revenues   Income     Income  

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

1995
 March 31                407,516     69,144    41,937
 June 30                 339,957     38,839     8,486
 September 30            403,786     55,361    28,378
 December 31             393,780     63,758    37,099

<PAGE>
<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, 1996 and 1995, and the
related consolidated statements of income, retained earnings, and cash flows
for each of the three years in the period ended December 31, 1996.  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, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1996 in conformity with generally accepted accounting
principles.


/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP
Columbus, Ohio
February 25, 1997




</TABLE>