APPALACHIAN POWER CO - 10-K Annual Report

229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant's knowledge, in
the definitive proxy statement of American Electric Power Company, Inc. or
definitive information statement of Appalachian Power Company incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K.

Indicate by check mark if disclosure of delinquent filers with respect to
Indiana Michigan Power Company or Ohio Power Company pursuant to Item 405 of
Regulation S-K (

229.405 of this chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in the definitive
information statement of Ohio Power Company incorporated by reference in Part
III of this Form 10-K or any amendment to this Form 10-K.

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:

REGISTRANT TITLE OF EACH CLASS

AEP Generating Company None

American Electric Power Company, Inc. None

Appalachian Power Company None

Columbus Southern Power Company None

Indiana Michigan Power Company None

Kentucky Power Company None

Ohio Power Company 4-1/2% Cumulative Preferred Stock,
Voting, $100 par value

AGGREGATE MARKET VALUE NUMBER OF SHARES
OF VOTING STOCK HELD OF COMMON STOCK
BY NON-AFFILIATES OF OUTSTANDING OF
THE REGISTRANTS AT THE REGISTRANTS AT
FEBRUARY 2, 1996 FEBRUARY 2, 1996

AEP Generating
Company None 1,000
($1,000 par value)

American Electric
Power Company, Inc. $8,164,000,000 186,635,000
($6.50 par value)

Appalachian Power
Company $43,000,000 13,499,500
(no par value)

Columbus Southern
Power Company None 16,410,426
(no par value)

Indiana Michigan
Power Company None 1,400,000
(no par value)

Kentucky Power
Company None 1,009,000
($50 par value)

Ohio Power
Company $68,000,000 27,952,473
(no par value)

NOTE ON MARKET VALUE OF VOTING STOCK HELD BY NON-AFFILIATES

All of the common stock of AEP Generating Company, Appalachian Power
Company, Columbus Southern Power Company, Indiana Michigan Power Company,
Kentucky Power Company and Ohio Power Company is owned by American Electric
Power Company, Inc. (see Item 12 herein). The voting stock owned by non-
affiliates of (i) Appalachian Power Company consists of 552,348 shares of
Cumulative Preferred Stock, no par value; and (ii) Ohio Power Company consists
of 862,403 shares of Cumulative Preferred Stock, $100 par value. Some of the
series of Cumulative Preferred Stock are not regularly traded. The aggregate
market value of the Cumulative Preferred Stock is based on the average of the
high and low prices on the closest trading date to February 2, 1996 for series
traded on the New York or Philadelphia Stock Exchange, or the most recent
reported bid prices for those series not recently traded. Where recent market
price information was not available with respect to a series, the market price
for such series is based on the price of a recently traded series with an
adjustment related to any difference in the current yields of the two series.

DOCUMENTS INCORPORATED BY REFERENCE

PART OF FORM 10-K
INTO WHICH DOCUMENT
DESCRIPTION IS INCORPORATED

Portions of Annual Reports of the following companies for the
fiscal year ended December 31, 1995: Part II

AEP Generating Company
American Electric Power Company, Inc.
Appalachian Power Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Ohio Power Company

Portions of Proxy Statement of American Electric Power
Company, Inc., dated March 9, 1996, for Annual
Meeting of Shareholders Part III

Portions of Information Statements of the following companies
for 1996 Annual Meeting of Shareholders, to be filed within
120 days after December 31, 1995: Part III

Appalachian Power Company
Ohio Power Company

THIS COMBINED FORM 10-K IS SEPARATELY FILED BY AEP GENERATING COMPANY,
AMERICAN ELECTRIC POWER COMPANY, INC., APPALACHIAN POWER COMPANY, COLUMBUS
SOUTHERN POWER COMPANY, INDIANA MICHIGAN POWER COMPANY, KENTUCKY POWER COMPANY
AND OHIO POWER COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY
INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EXCEPT
FOR AMERICAN ELECTRIC POWER COMPANY, INC., EACH REGISTRANT MAKES NO
REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS.

TABLE OF CONTENTS

PAGE
NUMBER

Glossary of Terms i

PART I
Item 1. Business 1
Item 2. Properties 29
Item 3. Legal Proceedings 33
Item 4. Submission of Matters to a Vote of Security
Holders 34
Executive Officers of the Registrants 34

PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 37
Item 6. Selected Financial Data 37
Item 7. Management's Discussion and Analysis of Results
of Operations and Financial Condition 37
Item 8. Financial Statements and Supplementary Data 38
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 38

PART III
Item 10. Directors and Executive Officers of the
Registrants 39
Item 11. Executive Compensation 40
Item 12. Security Ownership of Certain Beneficial
Owners and Management 44
Item 13. Certain Relationships and Related Transactions 45

PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 46

Signatures 48

Index to Financial Statement Schedules S-1

Independent Auditors' Report S-2

Exhibit Index E-1

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this
report, they have the meanings indicated below.

TERM MEANING

AEGCo AEP Generating Company, an electric utility subsidiary
of AEP.
AEP American Electric Power Company, Inc.
AEP System or
the System The American Electric Power System, an integrated
electric utility system, owned and operated by AEP's
electric utility subsidiaries.
AFUDC Allowance for funds used during construction. Defined
in regulatory systems of accounts as the net cost of
borrowed funds used for construction and a reasonable
rate of return on other funds when so used.
APCo Appalachian Power Company, an electric utility
subsidiary of AEP.
Buckeye Buckeye Power, Inc., an unaffiliated corporation.
CCD Group CSPCo, CG&E and DP&L.
CG&E The Cincinnati Gas & Electric Company, an unaffiliated
utility company.
Cook Plant The Donald C. Cook Nuclear Plant, owned by I&M.
CSPCo Columbus Southern Power Company, an electric utility
subsidiary of AEP.
DOE United States Department of Energy.
DP&L The Dayton Power and Light Company, an unaffiliated
utility company.
Federal EPA United States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission (an independent
commission within the DOE).
I&M Indiana Michigan Power Company, an electric utility
subsidiary of AEP.
IURC Indiana Utility Regulatory Commission.
KEPCo Kentucky Power Company, an electric utility subsidiary
of AEP.
KPSC Kentucky Public Service Commission.
MPSC Michigan Public Service Commission.
NEIL Nuclear Electric Insurance Limited.
NPDES National Pollutant Discharge Elimination System.
NRC Nuclear Regulatory Commission.
Ohio EPA Ohio Environmental Protection Agency.
OPCo Ohio Power Company, an electric utility subsidiary of
AEP.
OVEC Ohio Valley Electric Corporation, an electric utility
company in which AEP and CSPCo own a 44.2% equity
interest.
PCB's Polychlorinated biphenyls.
PUCO The Public Utilities Commission of Ohio.
PUHCA Public Utility Holding Company Act of 1935, as amended.
RCRA Resource Conservation and Recovery Act of 1976, as
amended.
Rockport Plant A generating plant, consisting of two 1,300,000-kilowatt
coal-fired generating units, near Rockport, Indiana.
SEC Securities and Exchange Commission.
Service Corporation American Electric Power Service Corporation, a service
subsidiary of AEP.
SO{2} Allowance An allowance to emit one ton of sulfur dioxide granted
under the Clean Air Act Amendments of 1990.
TVA Tennessee Valley Authority.
VEPCo Virginia Electric and Power Company, an unaffiliated
utility company.
Virginia SCC State Corporation Commission of Virginia.
West Virginia PSC Public Service Commission of West Virginia.
Zimmer or Zimmer Plant Wm. H. Zimmer Generating Station, commonly owned by
CSPCo, CG&E and DP&L.

i

[THIS PAGE INTENTIONALLY LEFT BLANK]

PART I

Item 1. BUSINESS

GENERAL

AEP was incorporated under the laws of the State of New York in 1906 and
reorganized in 1925. It is a public utility holding company which owns,
directly or indirectly, all of the outstanding common stock of its electric
utility and other subsidiaries. Substantially all of the operating revenues of
AEP and its subsidiaries are derived from the furnishing of electric service.

The service area of AEP's electric utility subsidiaries covers portions of
the states of Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia and West
Virginia. The generating and transmission facilities of AEP's subsidiaries are
physically interconnected, and their operations are coordinated, as a single
integrated electric utility system. Transmission networks are interconnected
with extensive distribution facilities in the territories served. The electric
utility subsidiaries of AEP have traditionally provided electric service,
consisting of generation, transmission and distribution, on an integrated basis
to their retail customers. As a result of the changing nature of the electric
business (see COMPETITION AND BUSINESS CHANGE), effective January 1, 1996,
AEP's subsidiaries realigned into four functional business units: Power
Generation; Nuclear Generation; Energy Delivery; and Corporate Development. In
addition, the electric utility subsidiaries began to do business as "American
Electric Power." The legal and financial structure of AEP and its
subsidiaries, however, did not change.

At December 31, 1995, the subsidiaries of AEP had a total of 18,502
employees. AEP, as such, has no employees. The operating subsidiaries of AEP
are:

APCO (organized in Virginia in 1926) is engaged in the generation,
purchase, transmission and distribution of electric power to approximately
859,000 retail customers in the southwestern portion of Virginia and
southern West Virginia, and in supplying electric power at wholesale to
other electric utility companies and municipalities in those states and in
Tennessee. At December 31, 1995, APCo and its wholly owned subsidiaries had
4,338 employees. Among the principal industries served by APCo are coal
mining, primary metals, chemicals, textiles, paper, stone, clay, glass and
concrete products, rubber, plastic products and furniture. In addition to
its AEP System interconnections, APCo also is interconnected with the
following unaffiliated utility companies: Carolina Power & Light Company,
Duke Power Company and VEPCo. A comparatively small part of the properties
and business of APCo is located in the northeastern end of the Tennessee
Valley. APCo has several points of interconnection with TVA and has entered
into agreements with TVA under which APCo and TVA interchange and transfer
electric power over portions of their respective systems.

CSPCO (organized in Ohio in 1937, the earliest direct predecessor company
having been organized in 1883) is engaged in the generation, purchase,
transmission and distribution of electric power to approximately 599,000
customers in Ohio, and in supplying electric power at wholesale to other
electric utilities and to municipally owned distribution systems within its
service area. At December 31, 1995, CSPCo had 2,174 employees. CSPCo's
service area is comprised of two areas in Ohio, which include portions of
twenty-five counties. One area includes the City of Columbus and the other
is a predominantly rural area in south central Ohio. Approximately 80% of
CSPCo's retail revenues are derived from the Columbus area. Among the
principal industries served are food processing, chemicals, primary metals,
electronic machinery and paper products. In addition to its AEP System
interconnections, CSPCo also is interconnected with the following
unaffiliated utility companies: CG&E, DP&L and Ohio Edison Company.

I&M (organized in Indiana in 1925) is engaged in the generation,
purchase, transmission and distribution of electric power to approximately
537,000 customers in northern and eastern Indiana and southwestern Michigan,
and in supplying electric power at wholesale to other electric utility
companies, rural electric cooperatives and municipalities. At December 31,
1995, I&M had 3,525 employees. Among the principal industries served are
primary metals, transportation equipment, fabricated metal products,
electrical and electronic machinery, rubber and miscellaneous plastic
products and chemicals and allied products. Since 1975, I&M has leased and
operated the assets of the municipal system of the City of Fort Wayne,
Indiana. In addition to its AEP System interconnections, I&M also is
interconnected with the following unaffiliated utility companies: Central
Illinois Public Service Company, CG&E, Commonwealth Edison Company,
Consumers Power Company, Illinois Power Company, Indianapolis Power & Light
Company, Louisville Gas and Electric Company, Northern Indiana Public
Service Company, PSI Energy Inc. and Richmond Power & Light Company.

KEPCO (organized in Kentucky in 1919) is engaged in the generation,
purchase, transmission and distribution of electric power to approximately
165,000 customers in an area in eastern Kentucky, and in supplying electric
power at wholesale to other utilities and municipalities in Kentucky. At
December 31, 1995, KEPCo had 748 employees. In addition to its AEP System
interconnections, KEPCo also is interconnected with the following
unaffiliated utility companies: Kentucky Utilities Company and East
Kentucky Power Cooperative Inc. KEPCo is also interconnected with TVA.

KINGSPORT POWER COMPANY (organized in Virginia in 1917) provides electric
service to approximately 42,000 customers in Kingsport and eight neighboring
communities in northeastern Tennessee. Kingsport Power Company has no
generating facilities of its own. It purchases electric power distributed
to its customers from APCo. At December 31, 1995, Kingsport Power Company
had 101 employees.

OPCO (organized in Ohio in 1907 and reincorporated in 1924) is engaged in
the generation, purchase, transmission and distribution of electric power to
approximately 668,000 customers in the northwestern, east central, eastern
and southern sections of Ohio, and in supplying electric power at wholesale
to other electric utility companies and municipalities. At December 31,
1995, OPCo and its wholly owned subsidiaries had 4,998 employees. Among the
principal industries served by OPCo are primary metals, rubber and plastic
products, stone, clay, glass and concrete products, petroleum refining,
chemicals and electrical and electronic machinery. In addition to its AEP
System interconnections, OPCo also is interconnected with the following
unaffiliated utility companies: CG&E, The Cleveland Electric Illuminating
Company, DP&L, Duquesne Light Company, Kentucky Utilities Company,
Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company
and West Penn Power Company.

WHEELING POWER COMPANY (organized in West Virginia in 1883 and
reincorporated in 1911) provides electric service to approximately 41,000
customers in northern West Virginia. Wheeling Power Company has no
generating facilities of its own. It purchases electric power distributed
to its customers from OPCo. At December 31, 1995, Wheeling Power Company
had 135 employees.

Another principal electric utility subsidiary of AEP is AEGCo, which was
organized in Ohio in 1982 as an electric generating company. AEGCo sells power
at wholesale to I&M, KEPCo and VEPCo. AEGCo has no employees.

See Item 2 for information concerning the properties of the subsidiaries of
AEP.

The Service Corporation provides accounting, administrative, information
systems, engineering, financial, legal, maintenance and other services at cost
to the AEP System companies. The executive officers of AEP and its public
utility subsidiaries are all employees of the Service Corporation.

REGULATION

GENERAL

AEP and its subsidiaries are subject to the broad regulatory provisions of
PUHCA administered by the SEC. The public utility subsidiaries' retail rates
and certain other matters are subject to regulation by the public utility
commissions of the states in which they operate. Such subsidiaries are also
subject to regulation by the FERC under the Federal Power Act in respect of
rates for interstate sale at wholesale and transmission of electric power,
accounting and other matters and construction and operation of hydroelectric
projects. I&M is subject to regulation by the NRC under the Atomic Energy Act
of 1954, as amended, with respect to the operation of the Cook Plant.

POSSIBLE CHANGE TO PUHCA

The provisions of PUHCA, administered by the SEC, regulate all aspects of a
registered holding company system, such as the AEP System. PUHCA requires that
the operations of a registered holding company system be limited to a single
integrated public utility system and such other businesses as are incidental or
necessary to the operations of the system. In addition, PUHCA governs, among
other things, financings, sales or acquisitions of assets and intra-system
transactions.

On June 20, 1995, the SEC released a report from its Division of Investment
Management recommending a conditional repeal of PUHCA, including its limits on
financing and on geographic and business diversification. Specific federal
authority, however, would be preserved over access to the books and records of
registered holding company systems, audit authority over registered holding
companies and their subsidiaries and oversight over affiliate transactions.
This authority would be transferred to the FERC. In October 1995, legislation
was introduced in the U.S. Senate to repeal PUHCA and transfer certain federal
authority to the FERC as recommended in the SEC report. If PUHCA is repealed,
registered holding company systems, including the AEP System, will be able to
compete in the changing industry without the constraints of PUHCA. Management
of AEP believes that removal of these constraints would be beneficial to the
AEP System.

PUHCA and the rules and orders of the SEC currently require that
transactions between associated companies in a registered holding company
system be performed at cost with limited exceptions. Over the years, the AEP
System has developed numerous affiliated service, sales and construction
relationships and, in some cases, invested significant capital and developed
significant operations in reliance upon the ability to recover its full costs
under these provisions. On December 28, 1994, the SEC proposed revisions to
its rules governing transactions between associated companies in a registered
holding company system. These proposed revisions to the rules would price
transactions governed by SEC rules at a market-based price if it is lower than
cost. In its June 1995 report, the Division of Investment Management
recommended that the proposed revisions to the rules be withdrawn.

In addition, proposals have been made for Congress to repeal PUHCA or modify
its provisions governing intra-system transactions. The effect of possible SEC
revisions of these cost provisions or the repeal or amendment of PUHCA on AEP's
intra-system transactions depends on whether the assurance of full cost
recovery is eliminated immediately or phased-in and whether it is eliminated
for all intra-system transactions or only some. If the cost recovery
assurance is eliminated immediately for all intra-system transactions,
it could have a material adverse effect on results of operations and
financial condition of AEP and OPCo.

CONFLICT OF REGULATION

Public utility subsidiaries of AEP can be subject to regulation of the same
subject matter by two or more jurisdictions. In such situations, it is
possible that the decisions of such regulatory bodies may conflict or that the
decision of one such body may affect the cost of providing service and so the
rates in another jurisdiction. In a case involving OPCo, the U.S. Court of
Appeals for the District of Columbia held that the determination of costs to be
charged to associated companies by the SEC under PUHCA precluded the FERC from
determining that such costs were unreasonable for ratemaking purposes. The
U.S. Supreme Court also has held that a state commission may not conclude that
a FERC approved wholesale power agreement is unreasonable for state ratemaking
purposes. Certain actions that would overturn these decisions or otherwise
affect the jurisdiction of the SEC and FERC are under consideration by the U.S.
Congress and these regulatory bodies. Such conflicts of jurisdiction often
result in litigation and, if resolved adversely to a public utility subsidiary
of AEP, could have a material adverse effect on the results of operations or
financial condition of such subsidiary or AEP.

CLASSES OF SERVICE

The principal classes of service from which the major electric utility
subsidiaries of AEP derive revenues and the amount of such revenues (from
kilowatt-hour sales) during the year ended December 31, 1995 are as follows:

AEGCO APCO CSPCO I&M KEPCO OPCO AEP SYSTEM (a)
(IN THOUSANDS)

Retail
Residential
Without Electric Heating $ -- $ 240,385 $ 329,881 $ 239,266 $ 43,938 $ 277,780 $1,151,981
With Electric Heating -- 331,445 115,386 109,504 63,609 145,688 801,956

Total Residential -- 571,830 445,267 348,770 107,547 423,468 1,953,937
Commercial -- 284,866 371,461 256,319 58,606 257,300 1,265,776
Industrial -- 366,329 143,162 298,256 96,647 639,177 1,606,451
Miscellaneous -- 32,270 16,041 6,482 847 8,065 67,047

Total Retail -- 1,255,295 975,931 909,827 263,647 1,328,010 4,893,211
Wholesale (sales for resale) 231,659 269,493 75,466 357,441 60,567 457,758 680,905

Total from KWH Sales 231,659 1,524,788 1,051,397 1,267,268 324,214 1,785,768 5,574,116
Provision for Revenue Refunds -- (1,100) -- -- -- -- (1,100)

Total Net of Provision for
Revenue Refunds 231,659 1,523,688 1,051,397 1,267,268 324,214 1,785,768 5,573,016
Other Operating Revenues 136 21,351 20,465 15,889 3,930 37,229 97,314

Total Electric Operating
Revenues $231,795 $1,545,039 $1,071,862 $1,283,157 $328,144 $1,822,997 $5,670,330

(a) Includes revenues of other subsidiaries not shown and reflects elimination
of intercompany transactions.

SALE OF POWER

AEP's electric utility subsidiaries own or lease generating stations with
total generating capacity of 23,759 megawatts. See Item 2 for more information
regarding the generating stations. They operate their generating plants as a
single interconnected and coordinated electric utility system and share the
costs and benefits in the AEP System Power Pool. Most of the electric power
generated at these stations is sold, in combination with transmission and
distribution services, to retail customers of AEP's utility subsidiaries in
their service territories. These sales are made at rates that are established
by the public utility commissions of the state in which they operate. See
RATES. Some of the electric power is sold at wholesale to non-affiliated
companies.

AEP SYSTEM POWER POOL

APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Interconnection
Agreement, dated July 6, 1951, as amended (the Interconnection Agreement),
defining how they share the costs and benefits associated with the System's
generating plants. This sharing is based upon each company's "member-load-
ratio," which is calculated monthly on the basis of each company's maximum peak
demand in relation to the sum of the maximum peak demands of all five companies
during the preceding 12 months. In addition, since 1995, APCo, CSPCo, I&M,
KEPCo and OPCo have been parties to the AEP System Interim Allowance Agreement
which provides, among other things, for the transfer of SO{2} Allowances
associated with transactions under the Interconnection Agreement.

The following table shows the net credits or (charges) allocated among the
parties under the Interconnection Agreement and Interim Allowance Agreement
during the years ended December 31, 1993, 1994 and 1995:

1993 1994 1995(a)
(in thousands)

APCo $(260,000) $(254,000) $(252,000)
CSPCo (141,000) (105,000) (143,000)
I&M 183,000 107,000 118,000
KEPCo 1,000 12,000 23,000
OPCo 217,000 240,000 254,000

(a) Includes credits and charges from allowance transfers related to the
transactions.

In July 1994, APCo, CSPCo, I&M, KEPCo and OPCo entered into the AEP System
Interim Allowance Agreement (IAA). Reference is made to ENVIRONMENTAL AND
OTHER MATTERS - CLEAN AIR ACT AMENDMENTS OF 1990 for a discussion of SO{2}
Allowances. The IAA provides for and governs the terms of the following
allowance transactions among the parties which began January 1, 1995: (1) an
annual reallocation of certain SO{2} Allowances initially allocated by the
Federal EPA to OPCo's Gavin Plant; (2) transfer of SO{2} Allowances associated
with energy transactions among APCo, CSPCo, I&M, KEPCo and OPCo, (3) a monthly
cash settlement for SO{2} Allowances consumed in connection with power sales to
non-affiliated electric utilities; and (4) transfers of SO{2} Allowances for
current and future period compliance. The IAA does not provide for the
allocation of costs and proceeds related to the sale or purchase of SO{2}
Allowances to or from non-affiliated companies. The IAA was accepted by the
FERC on December 30, 1994.

WHOLESALE SALES OF POWER TO NON-AFFILIATES

AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo also sell electric power on a
wholesale basis to non-affiliated electric utilities and power marketers. Such
sales are either made by the AEP System and then allocated among APCo, CSPCo,
I&M, KEPCo and OPCo based on member-load-ratios or made by individual companies
pursuant to various long-term power agreements. The following table shows the
amounts contributed to operating income of the various companies from such
sales during the years ended December 31, 1993, 1994 and 1995:

1993(a) 1994(a) 1995(a)
(in thousands)

AEGCo(b) $ 32,500 $ 30,800 $ 29,200
APCo(c) 23,600 25,000 24,100
CSPCo(c) 12,000 11,700 12,000
I&M(c)(d) 35,300 34,600 34,700
KEPCo(c) 4,900 4,800 5,000
OPCo(c) 20,700 20,000 20,200

Total System $129,000 $126,900 $125,200

(a) Such sales do not include wholesale sales to full/partial requirement
customers of AEP System companies. See the discussion below.
(b) All amounts for AEGCo are from sales made pursuant to a long-term power
agreement. See AEGCO - UNIT POWER AGREEMENTS.
(c) All amounts, except for I&M, are from System sales which are allocated
among APCo, CSPCo, I&M, KEPCo and OPCo based upon member-load-ratio. All
System sales made in 1993, 1994 and 1995 were made on a short-term basis,
except that $16,800,000, $21,800,000 and $22,500,000, respectively, of the
contribution to operating income for the total System were from long-term
System sales.
(d) In addition to its allocation of System sales, the 1993, 1994 and 1995
amounts for I&M include $21,600,000, $21,600,000 and $21,000,000 from a
long-term agreement to sell 250 megawatts of power scheduled to terminate
in 2009.

The AEP System has long-term system agreements to sell 100 megawatts of
electric power through 1997 and to sell at times up to 200 megawatts of peaking
power through March 1997 to unaffiliated utilities. In addition, commencing
January 1996, the AEP System began supplying 205 megawatts of electric power to
an unaffiliated utility for 15 years and commencing September 1996, the AEP
System will begin supplying 50 megawatts of electric power to an unaffiliated
utility for five years.

In addition to long-term and short-term sales, APCo, CSPCo, I&M, KEPCo and
OPCo serve unaffiliated wholesale customers that are full/partial requirement
customers. The aggregate maximum demand for these customers in 1995 was 574,
112, 536, 17 and 138 megawatts for APCo, CSPCo, I&M, KEPCo and OPCo,
respectively. Although the terms of the contracts with these customers vary,
they generally can be terminated by the customer upon one to four years'
notice. In 1995, customers gave notices of termination, effective in 1998, for
419, 5 and 67 megawatts for APCo, I&M and OPCo, respectively.

In June 1993, certain municipal customers of APCo, who have since given APCo
notice to terminate their contracts in 1998, filed an application with the FERC
for transmission service in order to reduce by 50 megawatts the power these
customers purchase under existing Electric Service Agreements (ESAs) and to
purchase power from a third party. APCo maintains that its agreements with
these customers are full-requirements contracts which preclude the customers
from purchasing power from third parties. On February 10, 1994, the FERC
issued an order finding that the ESAs are not full requirements contracts and
that the ESAs give these municipal wholesale customers the option of
substituting alternative sources of power for energy purchased from APCo. On
May 24, 1994, APCo appealed the February 10, 1994 order of the FERC to the U.S.
Court of Appeals for the District of Columbia Circuit. On July 1, 1994, the
FERC ordered the requested transmission service and granted a complaint filed
by the municipal customers directing certain modifications to the ESAs in order
to accommodate their power purchases from the third party. Following FERC's
denial of APCo's requests for rehearing, on December 20, 1995, APCo appealed
the July 1, 1994 Orders to the U.S. Court of Appeals for the District of
Columbia. Effective August 1994, these municipal customers reduced their
purchases by 40 megawatts. Certain of these customers further reduced their
purchases by an additional 21 megawatts effective February 1996.

TRANSMISSION SERVICES

AEP's electric utility subsidiaries own and operate transmission and
distribution lines and other facilities to deliver electric power. See Item 2
for more information regarding the transmission and distribution lines. AEP's
electric utility subsidiaries operate their transmission lines as a single
interconnected and coordinated system and share the cost and benefits in the
AEP System Transmission Pool. Most of the transmission and distribution
services is sold, in combination with electric power, to retail customers of
AEP's utility subsidiaries in their service territories. These sales are made
at rates that are established by the public utility commissions of the state in
which they operate. See RATES. Some transmission services also are separately
sold to non-affiliated companies.

AEP SYSTEM TRANSMISSION POOL

APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Transmission Agreement,
dated April 1, 1984, as amended (the Transmission Agreement), defining how they
share the costs associated with their relative ownership of the extra-high-
voltage transmission system (facilities rated 345 kv and above) and certain
facilities operated at lower voltages (138 kv and above). Like the
Interconnection Agreement, this sharing is based upon each company's "member-
load-ratio." See SALE OF POWER.

The following table shows the net credits or (charges) allocated among the
parties to the Transmission Agreement during the years ended December 31, 1993,
1994 and 1995:

1993 1994 1995

(in thousands)

APCo $ (3,200) $(10,200) $ (5,400)
CSPCo (31,200) (30,100) (31,100)
I&M 47,400 50,300 46,700
KEPCo 3,800 4,300 3,500
OPCo (16,800) (14,300) (13,700)

TRANSMISSION SERVICES FOR NON-AFFILIATES

APCo, CSPCo, I&M, KEPCo, OPCo and other System companies also provide
transmission services for non-affiliated companies. The following table shows
the amounts contributed to operating income of the various companies from such
services during the years ended December 31, 1993, 1994 and 1995:

1993 1994 1995

(in thousands)

APCo $ 2,900 $ 4,100 $ 6,000
CSPCo 2,500 3,100 4,200
I&M 7,700 6,700 4,800
KEPCo 600 800 1,200
OPCo 9,900 15,700 17,800

Total System $23,600 $30,400 $34,000

The AEP System has long-term contracts with non-affiliated companies for
transmission of approximately 690 megawatts of electric power and contracts
with non-affiliated companies for transmission during 1996 of approximately
1,400 megawatts of electric power.

On April 12, 1993, APCo, CSPCo, I&M, KEPCo and OPCo and two other AEP System
companies filed a transmission tariff with the FERC under which these AEP
System companies would provide limited transmission service to certain
companies. The tariff covered the terms and conditions of the service, as well
as the price which the companies pay for transmission services, regardless of
the source of electric power generation. On September 3, 1993, the FERC issued
an order accepting the transmission service tariff for filing, with the tariff
becoming effective on September 7, 1993, subject to refund. On May 11, 1994,
the FERC issued an order on rehearing and indicated that an open access tariff
should offer third parties access to the transmission system on the same or
comparable basis, and under the same or comparable terms and conditions, as the
transmission provider's access to its system.

On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking ("Mega-
NOPR"). The Mega-NOPR proposes to require each public utility that owns or
controls interstate transmission facilities to file open access network and
point-to-point transmission tariffs that offer services comparable to the
utility's own uses of its transmission system. The Mega-NOPR also proposes to
require utilities to functionally unbundle their services, by requiring them to
use their own tariffs in making off-system and third-party sales. As part of
the proposed rule, the FERC issued recommended PRO-FORMA tariffs which reflect
the Commission's preliminary views on the minimum non-price terms and
conditions for non-discriminatory transmission service. In connection with the
Mega-NOPR, the Commission offered certain waivers of its regulations to
utilities willing to adopt the PRO-FORMA tariffs prior to issuance of the final
rule. The Mega-NOPR also would allow a utility to seek recovery of certain
prudently-incurred stranded costs that result from unbundled transmission
service.

On July 18, 1995, the AEP System companies filed an Offer of Settlement in
their transmission tariff case, in which the companies proposed to adopt the
FERC's PRO-FORMA transmission tariffs at certain stated rates that were lower
than those requested in their initial tariff filing. The Offer of Settlement
was approved by the FERC on February 14, 1996, except for certain pricing
issues, which are still pending resolution by FERC.

AEP has proposed creation of an independent system operator to operate the
transmission system in a region of the United States. See COMPETITION AND
BUSINESS CHANGE - AEP POSITION ON COMPETITION.

OVEC

AEP, CSPCo and several unaffiliated utility companies jointly own OVEC,
which supplies the power requirements of a uranium enrichment plant near
Portsmouth, Ohio owned by the DOE. The aggregate equity participation of AEP
and CSPCo in OVEC is 44.2%. The DOE demand under OVEC's power agreement, which
is subject to change from time to time, is 1,305,000 kilowatts. On October 1,
1996, it is scheduled to increase to approximately 1,905,000 kilowatts and to
remain at about that level through the remaining term of the contract. The
proceeds from the sale of power by OVEC, aggregating $299,000,000 in 1995, are
designed to be sufficient for OVEC to meet its operating expenses and fixed
costs and to provide a return on its equity capital. APCo, CSPCo, I&M and
OPCo, as sponsoring companies, are entitled to receive from OVEC, and are
obligated to pay for, the power not required by DOE in proportion to their
power participation ratios, which averaged 42.1% in 1995. The power agreement
with DOE terminates on December 31, 2005, subject to early termination by DOE
on not less than three years notice. The power agreement among OVEC and the
sponsoring companies expires by its terms on March 12, 2006.

BUCKEYE

Contractual arrangements among OPCo, Buckeye and other investor-owned
electric utility companies in Ohio provide for the transmission and delivery,
over facilities of OPCo and of other investor-owned utility companies, of power
generated by the two units at the Cardinal Station owned by Buckeye and back-up
power to which Buckeye is entitled from OPCo under such contractual
arrangements, to facilities owned by 27 of the rural electric cooperatives
which operate in the State of Ohio at 301 delivery points. Buckeye is entitled
under such arrangements to receive, and is obligated to pay for, the excess of
its maximum one-hour coincident peak demand plus a 15% reserve margin over the
1,226,500 kilowatts of capacity of the generating units which Buckeye currently
owns in the Cardinal Station. Such demand, which occurred on January 18, 1994,
was recorded at 1,146,933 kilowatts.

CERTAIN INDUSTRIAL CUSTOMERS

Ravenswood Aluminum Corporation and Ormet Corporation operate major aluminum
reduction plants in the Ohio River Valley at Ravenswood, West Virginia, and in
the vicinity of Hannibal, Ohio, respectively. OPCo supplies all of the power
requirements of these plants pursuant to long-term contracts with such
companies which, subject to certain curtailment provisions, terminate in 1997
in the case of Ormet and 1998 in the case of Ravenswood. The power
requirements of such plants presently aggregate approximately 890,000
kilowatts. OPCo is currently negotiating with Ormet and Ravenswood regarding
the extension of their contracts. See LEGAL PROCEEDINGS for a discussion of
litigation involving Ormet.

AEGCO

Since its formation in 1982, AEGCo's business has consisted of the ownership
and financing of its 50% interest in the Rockport Plant and, since 1989,
leasing of its 50% interest in Unit 2 of the Rockport Plant. The operating
revenues of AEGCo are derived from the sale of capacity and energy associated
with its interest in the Rockport Plant to I&M, KEPCo and VEPCo, pursuant to
unit power agreements. Pursuant to these unit power agreements, AEGCo is
entitled to recover its full cost of service from the purchasers and will be
entitled to recover future increases in such costs, including increases in fuel
and capital costs. See UNIT POWER AGREEMENTS. Pursuant to a capital funds
agreement, AEP has agreed to provide cash capital contributions, or in certain
circumstances subordinated loans, to AEGCo, to the extent necessary to enable
AEGCo, among other things, to provide its proportionate share of funds required
to permit continuation of the commercial operation of the Rockport Plant and to
perform all of its obligations, covenants and agreements under, among other
things, all loan agreements, leases and related documents to which AEGCo is or
becomes a party. See CAPITAL FUNDS AGREEMENT.

UNIT POWER AGREEMENTS

A unit power agreement between AEGCo and I&M (the I&M Power Agreement)
provides for the sale by AEGCo to I&M of all the power (and the energy
associated therewith) available to AEGCo at the Rockport Plant. I&M is
obligated, whether or not power is available from AEGCo, to pay as a demand
charge for the right to receive such power (and as an energy charge for any
associated energy taken by I&M) such amounts, as when added to amounts received
by AEGCo from any other sources, will be at least sufficient to enable AEGCo to
pay all its operating and other expenses, including a rate of return on the
common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power
Agreement will continue in effect until the date that the last of the lease
terms of Unit 2 of the Rockport Plant has expired unless extended in specified
circumstances.

Pursuant to an assignment between I&M and KEPCo, and a unit power agreement
between KEPCo and AEGCo, AEGCo sells KEPCo 30% of the power (and the energy
associated therewith) available to AEGCo from both units of the Rockport Plant.
KEPCo has agreed to pay to AEGCo in consideration for the right to receive such
power the same amounts which I&M would have paid AEGCo under the terms of the
I&M Power Agreement for such entitlement. The KEPCo unit power agreement
expires on December 31, 1999, unless extended.

A unit power agreement among AEGCo, I&M, VEPCo, and APCo provides for, among
other things, the sale of 70% of the power and energy available to AEGCo from
Unit 1 of the Rockport Plant to VEPCo by AEGCo from January 1, 1987 through
December 31, 1999. VEPCo has agreed to pay to AEGCo in consideration for the
right to receive such power those amounts which I&M would have paid AEGCo under
the terms of the I&M Power Agreement for such entitlement. Approximately 34%
of AEGCo's operating revenue in 1995 was derived from its sales to VEPCo.

CAPITAL FUNDS AGREEMENT

AEGCo and AEP have entered into a capital funds agreement pursuant to which,
among other things, AEP has unconditionally agreed to make cash capital
contributions, or in certain circumstances subordinated loans, to AEGCo to the
extent necessary to enable AEGCo to (i) maintain such an equity component of
capitalization as required by governmental regulatory authorities, (ii) provide
its proportionate share of the funds required to permit commercial operation of
the Rockport Plant, (iii) enable AEGCo to perform all of its obligations,
covenants and agreements under, among other things, all loan agreements, leases
and related documents to which AEGCo is or becomes a party (AEGCo Agreements),
and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo
Obligations) under the AEGCo Agreements, other than indebtedness, obligations
or liabilities owing to AEP. The Capital Funds Agreement will terminate after
all AEGCo Obligations have been paid in full.

INDUSTRY PROBLEMS

The electric utility industry, including the operating subsidiaries of AEP,
has encountered at various times in the last 15 years significant problems in a
number of areas, including: delays in and limitations on the recovery of fuel
costs from customers; proposed legislation, initiative measures and other
actions designed to prohibit construction and operation of certain types of
power plants under certain conditions and to eliminate or reduce the extent of
the coverage of fuel adjustment clauses; inadequate rate increases and delays
in obtaining rate increases; jurisdictional disputes with state public
utilities commissions regarding the interstate operations of integrated
electric systems; requirements for additional expenditures for pollution
control facilities; increased capital and operating costs; construction delays
due, among other factors, to pollution control and environmental considerations
and to material, equipment and fuel shortages; the economic effects on net
income (which when combined with other factors may be immediate and adverse)
associated with placing large generating units and related facilities in
commercial operation, including the commencement at that time of substantial
charges for depreciation, taxes, maintenance and other operating expenses, and
the cessation of AFUDC with respect to such units; uncertainties as to
conservation efforts by customers and the effects of such efforts on load
growth; depressed economic conditions in certain regions of the United States;
increasingly competitive conditions in the wholesale and retail markets;
proposals to deregulate certain portions of the industry and revise the rules
and responsibilities under which new generating capacity is supplied; and
substantial increases in construction costs and difficulties in financing due
to high costs of capital, uncertain capital markets, charter and indenture
limitations restricting conventional financing, and shortages of cash for
construction and other purposes.

SEASONALITY

Sales of electricity by the AEP System tend to increase and decrease because
of the use of electricity by residential and commercial customers for cooling
and heating and relative changes in temperature.

FRANCHISES

The operating companies of the AEP System hold franchises to provide
electric service in various municipalities in their service areas. These
franchises have varying provisions and expiration dates. In general, the
operating companies consider their franchises to be adequate for the conduct of
their business.

COMPETITION AND BUSINESS CHANGE

GENERAL

The public utility subsidiaries of AEP, like other electric utilities, have
traditionally provided electric generation and energy delivery, consisting of
transmission and distribution services, as a single product to their retail
customers. FERC has proposed that utilities be required, and the public
utility subsidiaries of AEP have agreed, to sell transmission services
separately from their other services. Proposals are being made that would also
require electric utilities to sell distribution services separately. These
proposals generally allow competition in the generation and sale of electric
power, but not in its transmission and distribution.

Competition in the generation and sale of electric power will require
resolution of complex issues, including who will pay for the unused generating
plant of, and other stranded costs incurred by, the utility when a customer
stops buying power from the utility; will all customers have access to the
benefits of competition; how will the rules of competition be established; what
will happen to conservation and other regulatory-imposed programs; how will the
reliability of the transmission system be ensured; and how will the utility's
obligation to serve be changed. As a result, it is not clear how or when
competition in generation and sale of electric power will be instituted.
However, if competition in generation and sale of electric power is instituted,
the public utility subsidiaries of AEP believe that they have a favorable
competitive position because of their relatively low costs. If stranded costs
are not recovered from customers, however, the public utility subsidiaries of
AEP, like all electric utilities, will be required by existing accounting
standards to recognize stranded investment losses.

WHOLESALE

The public utility subsidiaries of AEP, like the electric industry
generally, face increasing competition to sell available power on a wholesale
basis, primarily to other public utilities and also to power marketers. The
Energy Policy Act of 1992 was designed, among other things, to foster
competition in the wholesale market (a) through amendments to PUHCA,
facilitating the ownership and operation of generating facilities by "exempt
wholesale generators" (which may include independent power producers as well as
affiliates of electric utilities) and (b) through amendments to the Federal
Power Act, authorizing the FERC under certain conditions to order utilities
which own transmission facilities to provide wholesale transmission services
for other utilities and entities generating electric power. The principal
factors in competing for such sales are price (including fuel costs),
availability of capacity and reliability of service. The public utility
subsidiaries of AEP believe that they maintain a favorable competitive position
on the basis of all of these factors. However, because of the availability of
capacity of other utilities and the lower fuel prices in recent years, price
competition has been, and is expected for the next few years to be,
particularly important.

The Mega-NOPR proposes that utilities be required to functionally unbundle
their transmission services, by requiring them to use their own tariffs in
making off-system and third-party sales. See TRANSMISSION SERVICES. The Mega-
NOPR also would allow a utility to seek recovery of certain prudently-incurred
stranded costs that result from unbundled transmission service. The public
utility subsidiaries of AEP are preparing to functionally separate their
wholesale power sales from their transmission functions, as proposed in the
Mega-NOPR and required by their transmission tariffs.

RETAIL

The public utility subsidiaries of AEP generally have the exclusive right to
sell electric power at retail within their service areas. However, they do
compete with self-generation and with distributors of other energy sources,
such as natural gas, fuel oil and coal, within their service areas. The
primary factors in such competition are price, reliability of service and the
capability of customers to utilize sources of energy other than electric power.
With respect to self-generation, the public utility subsidiaries of AEP believe
that they maintain a favorable competitive position on the basis of all of
these factors. With respect to alternative sources of energy, the public
utility subsidiaries of AEP believe that the reliability of their service and
the limited ability of customers to substitute other cost-effective sources for
electric power place them in a favorable competitive position, even though
their prices may be higher than the costs of some other sources of energy.

Significant changes in the global economy in recent years have led to
increased price competition for industrial companies in the United States,
including those served by the AEP System. Such industrial companies have
requested price reductions from their suppliers, including their suppliers of
electric power. In addition, industrial companies which are downsizing or
reorganizing often close a facility based upon its costs, which may include,
among other things, the cost of electric power. The public utility
subsidiaries of AEP cooperate with such customers to meet their business needs
through, for example, various off-peak or interruptible supply options and
believe that, as low cost suppliers of electric power, they should be less
likely to be materially adversely affected by this competition and may be
benefitted by attracting new industrial customers to their service territories.

The legislatures and/or the regulatory commissions in several states are
considering "retail customer choice" which, in general terms, means the
transmission by an electric utility of electric power generated by an entity of
the customer's choice over its transmission and distribution system to a retail
customer in such utility's service territory. A requirement to transmit
directly to retail customers would have the result of permitting retail
customers to purchase electric power, at the election of such customers, not
only from the electric utility in whose service area they are located but from
another electric utility, an independent power producer or an intermediary,
such as a power marketer. Although AEP's power generation would have
competitors under some of these proposals, its transmission and distribution
would not. If competition develops in retail power generation, the public
utility subsidiaries of AEP believe that they have a favorable competitive
position because of their relatively low costs.

MICHIGAN: On June 19, 1995, the MPSC approved an experimental five-year
retail wheeling program and ordered Consumers Power Company and Detroit Edison
Company, unaffiliated utilities, to make retail delivery services available to
a group of industrial customers, in the amount of 60 megawatts and 90
megawatts, respectively. The experiment will commence when each utility needs
new capacity. The experiment seeks, as its goal, to determine whether a retail
wheeling program best serves the public interest in a manner that promotes
retail competition in a non-discriminatory fashion. During the experiment, the
MPSC will collect information regarding the effects of retail wheeling.

In January 1996, the Governor of Michigan endorsed a proposal of the
Michigan Jobs Commission to promote competition and customer choice in energy.
Under the proposal, by January 1997, industrial and commercial customers would
be permitted to choose suppliers for new electrical load and tariffs would be
unbundled. By January 1998, an independent wholesale power pool with an
independent operator would be formed. By 2001, power generation for industrial
and commercial would not be subject to rate regulation and franchise
territories would be eliminated.

OHIO: On April 15, 1994, the Ohio Energy Strategy Task Force released its
final report. The report contained seven broad implementation strategies along
with 53 specific initiatives to be undertaken by government and the private
sector. One strategy recommended continuing to encourage competition in the
electric utility industry in a manner which maximizes benefits and efficiencies
for all customers. An initiative under this strategy recommends facilitating
informal roundtable discussions on issues concerning competition in the
electric utility industry and promoting increased competitive options for Ohio
businesses that do not unduly harm the interests of utility company
shareholders or ratepayers. The PUCO has begun such discussions. As a result,
on February 15, 1996, the PUCO adopted guidelines for interruptible electric
service, including a buy-through provision that will enable customers to avoid
being interrupted during utility capacity deficiencies by having the utility
purchase off-system replacement power for the customer.

In March 1996, H.B. 653 was introduced in the Ohio House of Representatives.
The bill proposes that all customers be permitted to select their electricity
suppliers effective January 1, 1998. The bill eliminates price regulation of
electricity generation functions in favor of market based prices. Service area
rights for Ohio's electricity suppliers would be confined to distribution
service. Transmission and distribution services would continue to be regulated
at the federal and state levels, respectively. The bill would require Ohio's
electric utilities to functionally unbundle their generation, transmission and
distribution services. Electric utilities would be permitted to recover
transition costs provided that such recovery does not cause prices to exceed
those in effect on the effective date of the legislation.

VIRGINIA: In September 1995, the Virginia SCC instituted a proceeding to
review and consider policy regarding restructuring and the role of competition
in the electric utility industry in Virginia. The Virginia SCC has directed
its staff to conduct an investigation of current issues in the electric utility
industry and to file a report of its observation and recommendations on issues
identified in the Virginia SCC order. In addition, the Virginia legislature
has adopted a resolution establishing a subcommittee to study, in consultation
with the Virginia SCC, restructuring and potential changes in the electric
utility industry in Virginia and determine the need for legislative changes.

AEP POSITION ON COMPETITION

In October 1995, AEP announced that it favored freedom for customers to
purchase electric power from anyone that they choose. Generation and sale of
electric power would be in the competitive marketplace. To facilitate
reliable, safe and efficient service, AEP supports creation of independent
system operators to operate the transmission system in a region of the United
States. In addition, AEP supports the evolution of regional power exchanges
which would establish a competitve marketplace for the sale of electric power.
Transmission and distribution would remain monopolies and subject to regulation
with respect to terms and price. Regulators would be able to establish
distribution service charges which would provide, as appropriate, for recovery
of stranded costs and regulatory assets. Implementation of this proposal would
require legislative changes and regulatory approvals.

POSSIBLE STRATEGIC RESPONSES

In response to the competitive forces and regulatory changes being faced by
AEP and its public utility subsidiaries, as discussed under this heading and
under REGULATION, AEP and its public utility subsidiaries have from time to
time considered, and expect to continue to consider, various strategies
designed to enhance their competitive position and to increase their ability to
adapt to and anticipate changes in their utility business. These strategies
may include business combinations with other companies, internal restructurings
involving the complete or partial separation of their generation, transmission
and distribution businesses, acquisitions of related or unrelated businesses,
and additions to or dispositions of portions of their franchised service
territories. AEP and its public utility subsidiaries may from time to time be
engaged in preliminary discussions, either internally or with third parties,
regarding one or more of these potential strategies. No assurances can be
given as to whether any potential transaction of the type described above may
actually occur, or as to its ultimate effect on the financial condition or
competitive position of AEP and its public utility subsidiaries.

NEW BUSINESS DEVELOPMENT

AEP continues to consider new business opportunities, particularly those
which allow use of its expertise. These endeavors began in 1982 and are
conducted through AEP Energy Services, Inc. (AEPES) and AEP Resources, Inc.
(Resources).

Resources' primary business is development of, and investment in, exempt
wholesale generators, foreign utility companies, qualifying cogeneration
facilities and other power projects. Resources currently does not have an
interest in any power projects. Resources, however, has entered into a
strategic alliance with Cogentrix Energy, Inc. and Zurn Industries, Inc. to
develop, own and operate industrial power projects in the United States and
Canada. In addition, Resources is investigating opportunities to develop and
invest in new, and invest in existing, generation projects in China, Australia,
Mexico and India.

In 1994, AEP Resources International, Limited (AEPRI), a wholly owned
subsidiary of Resources, signed an agreement of intent with Northeast China
Electric Power Group Corp. (NEPG) to design two 1,300-megawatt, coal-fired
electric generating units in Suizhong, Liaoning Province, China. The
feasibility study for this project has been approved by the Chinese Ministry of
Electric Power and is awaiting approval by the State Planning Commission.
AEPRI is also involved in the advanced stages of negotiations to establish a
joint venture with two Chinese partners to develop and own two 125-megawatt,
coal-fired units in Henan Province, China.

AEPES offers engineering, construction, project management and other
consulting services for projects involving transmission, distribution or
generation of electric power both domestically and internationally.

AEP has received approval from the SEC under PUHCA to finance up to
$300,000,000, and has requested approval to finance up to 50% of its
consolidated retained earnings (approximately $700,000,000), for investment in
exempt wholesale generators and foreign utility companies. AEP also has
requested authority from the SEC under PUHCA to invest up to $100,000,000 in
subsidiaries engaged in the business of marketing energy commodities, including
electricity and gas.

These continuing efforts to invest in and develop new business opportunities
offer the potential of earning returns which may exceed those of rate-regulated
operations. However, they also involve a higher degree of risk which must be
carefully considered and assessed. AEP may make substantial investments in
these and other new businesses.

CONSTRUCTION PROGRAM

NEW GENERATION

The AEP System companies are engaged in a continuing construction program,
involving assessment of needs, selection of sites, design and acquisition of
equipment, and installation of the generating, transmission, distribution and
other facilities necessary to provide for generation, transmission and
distribution of electric power. At the present time, there are no specific
commitments for additions of new generating stations on the AEP System. Size,
technology, type, ownership (among AEP operating companies), means of
acquisition and precise timing of future capacity additions on the AEP System
have not yet been determined. However, the resource plan filed by AEP's
electric utility subsidiaries with various state commissions indicates no need
for new generation until sometime after the year 2000. Initial future capacity
additions will most likely be short lead time, simple-cycle, gas-fired
combustion turbines. The current resource plan indicates no need for new coal-
fired baseload generation until sometime after the year 2010. The size of any
new coal-fired generation will most likely be significantly smaller than the
1,300-megawatt units last added to the AEP System, to better match projected
load growth.

Proposals have been made, some of which have been adopted, that require the
public utility subsidiaries of AEP to file with state commissions resource
plans, indicating their plans to satisfy expected demand for electric power in
their service territory. When the AEP System needs new generation, some of
these proposals also require the public utility subsidiaries of AEP which wish
to provide the new generation to compete with exempt wholesale generators,
independent power producers and other utilities. Although the specific
guidelines for such competition have not yet been developed and may vary from
jurisdiction to jurisdiction (see the discussion below), significant factors
will include price and reliability.

For some years, the AEP System has put in place a series of customer
programs for encouraging electric conservation and load management (CLM). The
CLM programs also are referred to in the electric utility industry as "demand-
side management" programs (DSM) since they affect the demand for electric power
as opposed to its supply. The AEP System utilizes integrated resource planning
and has in place a detailed analysis procedure in which effective demand-side
and supply-side options are both considered in order to determine the least
cost approach to provide reliable electric service for its customers, taking
into account environmental and other considerations.

INDIANA: In May 1995, the IURC adopted rules for integrated resource
planning guidelines, including consideration of resource bidding and
independent power producers, and for demand-side management. I&M filed its
first integrated resource plan in November 1995.

MICHIGAN: The MPSC has adopted guidelines governing the acquisition of new
capacity by large Michigan electric utilities. The guidelines do not apply to
I&M.

OHIO: On December 17, 1992, the PUCO issued an order proposing rules for
competitive bidding for new generating capacity, including transmission access
for winning bidders. The proposed rules would establish a rebuttable
presumption of prudence where new generating capacity is acquired through
competitive bidding and provide other incentives to use competitive bidding.
The proposed rules also contain procedures to ensure that bidders for a
utility's new capacity will have open access to certain transmission facilities
and prohibit the utility acquiring new capacity from withholding SO{2}
Allowances from potential bidders. CSPCo and OPCo filed comments on the
proposed rules generally supporting promulgation of rules governing competitive
bidding but stating that the rules should not address access to transmission
facilities or SO{2} Allowances, because existing federal laws address such
concerns.

VIRGINIA: On October 24, 1994, the Virginia SCC began a proceeding to
consider whether to adopt standards related to integrated resource planning,
conservation, demand-side management and energy efficiency in power generation
and supply for jurisdictional electric utilities. On September 27, 1995, the
Virginia SCC declined to adopt the proposed standards, but reaffirmed its goals
for integrated resource planning, investment in cost-effective conservation and
demand management programs. Virginia electric utilities are to continue to
file biennial twenty-year resource plans. The Virginia SCC also has adopted
minimum requirements for any electric utility that elects to acquire new
generation through a bidding program. An electric utility is not required to
use the bidding process and may participate in the bidding process.

WEST VIRGINIA: On October 8, 1993, the West Virginia PSC issued an order
proposing rules that generally require electric utilities to procure
competitively all new sources of generation. APCo and Wheeling Power Company
filed comments stating that the rules should not require competitive bidding
and should permit the utility to participate in the bidding process.

PROPOSED TRANSMISSION FACILITIES

APCO: On March 23, 1990, APCo and VEPCo announced plans, subject to
regulatory approval, for major new transmission facilities. APCo will
construct approximately 115 miles of 765,000-volt line from APCo's Wyoming
station in southern West Virginia to APCo's Cloverdale station near Roanoke,
Virginia. VEPCo will construct approximately 102 miles of 500,000-volt line
from APCo's Joshua Falls station east of Lynchburg, Virginia to VEPCo's
Ladysmith station north of Richmond, Virginia. The construction of the
transmission lines and related station improvements will provide needed
reinforcement for APCo's internal load, reinforce the ability to exchange
electric power between the two companies and relieve present constraints on the
transmission of electric power from potential independent power producers in
the APCo service area to VEPCo. APCo's cost is estimated at $245,000,000 while
VEPCo's cost is estimated at $164,000,000. Completion of the project is
presently scheduled for 2000 but the actual service date will be dependent upon
the time necessary to meet various regulatory requirements.

Hearings before the Virginia SCC were concluded in September 1993. A report
was issued by the hearing examiner in December 1993 which recommended that the
Virginia SCC grant APCo approval to construct the proposed 765,000-volt line.
In an interim order issued on December 13, 1995, the Virginia SCC found that
major additional transmission capacity was needed to serve APCo's native load
customers. The Virginia SCC further asked that APCo provide additional
information on possible routing modifications and utilization of the additional
transmission capacity prior to a final ruling.

APCo refiled with the West Virginia PSC in February 1993 its application for
certification. An application filed in June 1992 was withdrawn at the request
of the West Virginia PSC to permit additional time for review by the West
Virginia PSC. The West Virginia PSC rejected APCo's application for
certification in May 1993, directing APCo to supplement its line siting
information. APCo intends to refile its application with the West Virginia
PSC. Hearings are expected to be held in late 1996 or early 1997, with a
decision expected in late 1997 or early 1998.

The Jefferson National Forest (JNF) is directing the preparation of an
Environmental Impact Statement (EIS) which will be required prior to the
granting of special use permits for crossing Federal lands. The present
schedule of the JNF calls for completion of the draft EIS in June 1996 and the
final EIS in early 1998.

APCO AND KEPCO: APCo and KEPCo have announced an improvement plan to be
implemented during a four-year period (1996-1999) to reinforce their 138,000-
volt transmission system. Included in this plan is a new transmission line to
link KEPCo's Big Sandy Plant to communities in eastern Kentucky. APCo's and
KEPCo's estimated project costs are $5,115,000 and $84,184,000, respectively.
Work on the project is scheduled to begin later in 1996, pending approval from
the KPSC.

CONSTRUCTION EXPENDITURES

The following table shows the construction expenditures by AEGCo, APCo,
CSPCo, I&M, KEPCo, OPCo and the AEP System and their respective consolidated
subsidiaries during 1993, 1994 and 1995 and their current estimate of 1996
construction expenditures, in each case including AFUDC but excluding nuclear
fuel and other assets acquired under leases. The construction expenditures for
the years 1993-1995 were applied, and it is anticipated that the estimated
construction expenditures for 1996 will be applied, approximately as follows to
construction of the following classes of assets:

1993 1994 1995 1996
ACTUAL ACTUAL ACTUAL ESTIMATE
(in thousands)

AEGCO
Generating plant and facilities $ 3,100 $ 3,900 $ 4,000 $ 1,900

TOTAL $ 3,100 $ 3,900 $ 4,000 $ 1,900

APCO
Generating plant and facilities $ 51,200 $ 65,600 $ 42,400 $ 55,700
Transmission lines and facilities 36,700 38,700 35,200 31,300
Distribution lines and facilities 98,200 116,500 121,400 102,900
General plant and other facilities 4,800 9,500 18,600 13,900

TOTAL $190,900 $230,300 $217,600 $203,800

CSPCO
Generating plant and facilities $ 33,300 $ 24,800 $ 30,500 $ 20,400
Transmission lines and facilities 10,100 3,600 10,700 10,800
Distribution lines and facilities 40,700 50,800 56,600 50,800
General plant and other facilities 2,200 2,300 1,700 12,500

TOTAL $ 86,300 $ 81,500 $ 99,500 $ 94,500

1993 1994 1995 1996
ACTUAL ACTUAL ACTUAL ESTIMATE
(in thousands)

I&M
Generating plant and facilities $ 50,200 $ 49,700 $ 46,200 $ 33,600
Transmission lines and facilities 10,100 20,300 22,600 17,600
Distribution lines and facilities 41,300 42,300 41,500 40,900
General plant and other facilities 6,700 2,200 2,700 18,500

TOTAL $108,300 $114,500 $113,000 $110,600

KEPCO
Generating plant and facilities $ 8,100 $ 22,600 $ 6,200 $ 25,400
Transmission lines and facilities 6,700 6,400 7,900 33,000
Distribution lines and facilities 20,300 23,700 23,900 23,200
General plant and other facilities 0 500 1,300 3,400

TOTAL $ 35,100 $ 53,200 $ 39,300 $ 85,000

OPCO
Generating plant and facilities (a) $112,700 $ 83,800 $ 40,000 $ 36,200
Transmission lines and facilities 28,600 15,300 23,500 22,000
Distribution lines and facilities 46,000 45,200 51,400 52,200
General plant and other facilities 10,500 4,700 2,000 12,700

TOTAL $197,800 $149,000 $116,900 $123,100

AEP SYSTEM (b)
Generating plant and facilities (a) $258,600 $250,400 $169,300 $173,200
Transmission lines and facilities 92,800 85,400 102,500 115,400
Distribution lines and facilities 252,300 286,900 302,800 277,000
General plant and other facilities 24,400 19,400 26,600 61,400

TOTAL $628,100 $642,100 $601,200 $627,000

(a) Excludes expenditures associated with flue-gas desulfurization system which
was constructed by a non-affiliate at the Gavin Plant and is being leased
by OPCo. Actual expenditures for such system for 1993, 1994 and 1995 and
the current estimate for 1996 are $256,673,000, $176,220,000, $48,804,000
and $12,915,000, respectively. See ENVIRONMENTAL AND OTHER MATTERS - ACID
RAIN PROGRAM - AEP SYSTEM COMPLIANCE PLAN.
(b) Includes expenditures of other subsidiaries not shown.

Reference is made to the footnotes to the financial statements entitled
COMMITMENTS AND CONTINGENCIES incorporated by reference in Item 8, for further
information with respect to the construction plans of AEP and its operating
subsidiaries for the next three years.

The System construction program is reviewed continuously and is revised from
time to time in response to changes in estimates of customer demand, business
and economic conditions, the cost and availability of capital, environmental
requirements and other factors. Changes in construction schedules and costs,
and in estimates and projections of needs for additional facilities, as well as
variations from currently anticipated levels of net earnings, Federal income
and other taxes, and other factors affecting cash requirements, may increase or
decrease the estimates of capital requirements for the System's construction
program.

From time to time, as the System companies have encountered the industry
problems described above, such companies also have encountered limitations on
their ability to secure the capital necessary to finance construction
expenditures.

ENVIRONMENTAL EXPENDITURES: Expenditures related to compliance with air and
water quality standards, included in the gross additions to plant of the
System, during 1993, 1994 and 1995 and the current estimate for 1996 are shown
below. Substantial expenditures in addition to the amounts set forth below may
be required by the System in future years in connection with the modification
and addition of facilities at generating plants for environmental quality
controls in order to comply with air and water quality standards which have
been or may be adopted.

1993 1994 1995 1996
ACTUAL ACTUAL ACTUAL ESTIMATE
(in thousands)

AEGCo $ 0 $ 0 $ 0 $ 0
APCo 16,800 32,000 7,800 8,500
CSPCo 15,800 13,700 10,000 1,300
I&M 0 0 0 400
KEPCo 1,000 9,500 600 600
OPCo (a) 31,600 22,400 3,100 0

AEP System (a) $65,200 $77,600 $21,500 $10,800

(a)Excludes expenditures associated with flue-gas desulfurization system which
was constructed by a non-affiliate at the Gavin Plant and is being leased by
OPCo. Actual expenditures for such system for 1993, 1994 and 1995 and the
current estimate for 1996 are $256,673,000, $176,220,000, $48,804,000 and
$12,915,000, respectively. See ENVIRONMENTAL AND OTHER MATTERS - ACID RAIN
PROGRAM - AEP SYSTEM COMPLIANCE PLAN.

FINANCING

It has been the practice of AEP's operating subsidiaries to finance current
construction expenditures in excess of available internally generated funds by
initially issuing unsecured short-term debt, principally commercial paper and
bank loans, at times up to levels authorized by regulatory agencies, and then
to reduce the short-term debt with the proceeds of subsequent sales by such
subsidiaries of long-term debt securities and preferred stock, and cash capital
contributions by AEP. It has been the practice of AEP, in turn, to finance
cash capital contributions to the common stock equities of the operating
subsidiaries by issuing unsecured short-term debt, principally commercial
paper, and then to sell additional shares of Common Stock of AEP for the
purpose of retiring the short-term debt previously incurred. In 1995, AEP
issued 1,400,000 shares of Common Stock pursuant to its Dividend Reinvestment
and Stock Purchase Plan. Although prevailing interest costs of short-term bank
debt and commercial paper generally have been lower than prevailing interest
costs of long-term debt securities, whenever interest costs of short-term debt
exceed costs of long-term debt, the companies might be adversely affected by
reliance on the use of short-term debt to finance their construction and other
apital requirements.

During the period 1993-1995, external funds from financings and capital
contributions by AEP amounted, with respect to APCo and KEPCo to approximately
31% and 53%, respectively, of the aggregate construction expenditures shown
above. During this same period, the amount of funds used to retire long-term
and short-term debt and preferred stock of AEGCo, CSPCo, I&M and OPCo exceeded
the amount of funds from financings and capital contributions by AEP.

The ability of AEP and its operating subsidiaries to issue short-term debt is
limited by regulatory restrictions and, in the case of most of the operating
subsidiaries, by provisions contained in their charters and in certain debt and
other instruments. The approximate amounts of short-term debt which the
companies estimate that they were permitted to issue under the most restrictive
such restriction, at January 1, 1996, and the respective amounts of short-term
debt outstanding on that date, on a corporate basis, are shown in the following
tabulation:

TOTAL AEP
SHORT-TERM DEBT AEP AEGCO APCO CSPCO I&M KEPCO OPCO SYSTEM(a)
(in millions)

Amount authorized $150 $80 $228 $175 $175 $150 $223 $1,256

Amount outstanding:
Notes payable $ 18 $22 $ -- $ 13 $ 52 $ 16 $ -- $ 128
Commercial paper 32 -- 126 21 38 11 9 237

$ 50 $22 $126 $ 34 $ 90 $ 27 $ 9 $ 365

(a) Includes short-term debt of other subsidiaries not shown.

Reference is made to the footnotes to the financial statements incorporated
by reference in Item 8 for further information with respect to unused short-
term bank lines of credit.

In order to issue additional first mortgage bonds and preferred stock, it is
necessary for APCo, CSPCo, I&M, KEPCo and OPCo to comply with earnings coverage
requirements contained in their respective mortgages and charters. The most
restrictive of these provisions in each instance generally requires (1) for the
issuance of first mortgage bonds for purposes other than the refunding of
outstanding first mortgage bonds, a minimum, before income tax, earnings
coverage of twice the pro forma annual interest charges on first mortgage bonds
and (2) for the issuance of additional preferred stock by APCo, I&M and OPCo, a
minimum, after income tax, gross income coverage of one and one-half times pro
forma annual interest charges and preferred stock dividends, in each case for a
period of twelve consecutive calendar months within the fifteen calendar months
immediately preceding the proposed new issue. In computing such coverages, the
companies include as a component of earnings revenues collected subject to
refund (where applicable) and, to the extent not limited by the instrument
under which the computation is made, AFUDC, including amounts positioned and
classified as an allowance for borrowed funds used during construction. These
coverage provisions have from time to time restricted the ability of one or
more of the above subsidiaries of AEP to issue senior securities.

The respective mortgage and preferred stock coverages of APCo, CSPCo, I&M,
KEPCo and OPCo under their respective mortgage and charter provisions,
calculated on the foregoing basis and in accordance with the respective amounts
then recorded in the accounts of the companies, assuming the respective short-
term debt of the companies at those dates were to remain outstanding for a
twelve-month period at the respective rates of interest prevailing at those
dates, were at least those stated in the following table:

DECEMBER 31,
1993 1994 1995

APCo
Mortgage coverage 3.64 3.12 3.47
Preferred stock coverage 2.04 1.65 1.78

CSPCo
Mortgage coverage 2.91 3.64 3.90

I&M
Mortgage coverage 5.49 6.23 6.25
Preferred stock coverage 2.48 2.74 2.63

KEPCo
Mortgage coverage 2.19 2.60 2.86

OPCo
Mortgage coverage 5.24 5.04 6.17
Preferred stock coverage 2.88 2.58 3.04

Although certain other subsidiaries of AEP either are not subject to any
coverage restrictions or are not subject to restrictions as constraining as
those to which APCo, CSPCo, I&M, KEPCo and OPCo are subject, their ability to
finance substantial portions of their construction programs may be subject to
market limitations and other constraints unless other assurances are furnished.

AEP believes that the ability of its operating subsidiaries to issue short-
and long-term debt securities and preferred stock in the amounts required to
finance their business may depend upon the timely approval of rate increase
applications. If one or more of the operating subsidiaries are unable to
continue the issuance and sale of securities on an orderly basis, such company
or companies will be required to consider the use of alternative financing
arrangements, if available, which may be more costly or the curtailment of
construction and other outlays.

AEP's subsidiaries have also utilized, and expect to continue to utilize,
additional financing arrangements, such as leasing arrangements, including the
leasing of utility assets, coal mining and transportation equipment and
facilities and nuclear fuel. Pollution control revenue bonds have been used in
the past and may be used in the future in connection with the construction of
pollution control facilities; however, Federal tax law has limited the
utilization of this type of financing except for purposes of certain financing
of solid waste disposal facilities and of certain refunding of outstanding
pollution control revenue bonds issued before August 16, 1986.

Shares of AEP Common Stock may be sold by AEP from time to time at prices
below the then current book value per share and repurchased by AEP at prices
above book value. Such sales or purchases, if any, would have a dilutive
effect on the book value of then outstanding shares but are not expected to
have a material adverse effect on AEP's business including its future financing
plans or capabilities and pending construction projects.

RATES

GENERAL

The rates charged by the electric utility subsidiaries of AEP are approved
by the FERC or one of the state utility commissions as applicable. The FERC
regulates wholesale rates and the state commissions regulate retail rates. In
recent years the number of rate increase applications filed by the operating
subsidiaries of AEP with their respective state commissions and the FERC has
decreased. If increases in operating, construction and capital costs exceed
increases in revenues resulting from previously granted rate increases and
increased customer demand, then it may be appropriate for certain of AEP's
electric utility subsidiaries to file rate increase applications in the future.

Generally the rates of AEP's operating subsidiaries are determined based
upon the cost of providing service including a reasonable return on investment.
Certain states served by the AEP System allow alternative forms of rate
regulation in addition to the traditional cost-of-service approach. In April
1995, Indiana enacted into law legislation providing that the IURC may approve
alternative regulatory plans which could include setting customer rates based
on market or average prices, price caps, index-based prices and prices based on
performance and efficiency. In March 1996, Virginia enacted into law
legislation which provides that the Virginia SCC may approve (i) special rates,
contracts or incentives to individual customers or classes of customers and
(ii) alternative forms of regulation including, but not limited to, the use of
price regulation, ranges of authorized returns, categories of services and
price indexing.

All of the seven states served by the AEP System, as well as the FERC,
either permit the incorporation of fuel adjustment clauses in a utility
company's rates and tariffs, which are designed to permit upward or downward
adjustments in revenues to reflect increases or decreases in fuel costs above
or below the designated base cost of fuel set forth in the particular rate or
tariff, or permit the inclusion of specified levels of fuel costs as part of
such rate or tariff.

AEP cannot predict the timing or probability of approvals regarding
applications for additional rate changes, the outcome of action by regulatory
commissions or courts with respect to such matters, or the effect thereof on
the earnings and business of the AEP System.

APCO

FERC: On February 14, 1992, APCo filed with the FERC applications for an
increase in its wholesale rates to Kingsport Power Company and non-affiliated
customers in the amounts of approximately $3,933,000 and $4,759,000,
respectively. APCo began collecting the rate increases, subject to refund, on
September 15, 1992. In addition, the Financial Accounting Standards Board has
issued Statement of Financial Accounting Standards No. 106, EMPLOYERS'
ACCOUNTING FOR POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (SFAS 106), which
requires employers, beginning in 1993, to accrue for the costs of retiree
benefits other than pensions. These rates include the higher level of SFAS 106
costs. On November 9, 1993, the administrative law judge issued an initial
decision recommending, among other things, the higher level of postretirement
benefits other than pensions under SFAS 106. FERC action on APCo's
applications is pending.

VIRGINIA: On June 27, 1994, the Virginia SCC issued a final order granting
APCo an increase in annual revenues of $17,900,000. APCo had requested to
increase its Virginia retail rates by $31,400,000 annually and, on May 4, 1993,
implemented the rates, subject to refund, based on an interim order. As a
result of the final order, APCo made a revenue refund including interest to its
Virginia customers in August 1994 of $15,800,000.

As a result of certain significant fuel cost reductions, on November 15,
1994, APCo implemented a net decrease in rates charged to its Virginia retail
customers of $13,200,000, subject to final approval by the Virginia SCC. The
net decrease consisted of a $28,900,000 decrease in the fuel component of its
rates offset, in part, by an increase of $15,700,000 in base rates. On
December 19, 1994, the Virginia SCC issued an order approving the decrease in
the fuel factor component of rates. APCo proposes in the base rate proceeding
to amortize Virginia deferred storm damage expenses of $23,900,000 related to
two major ice storms in February and March 1994 over a three-year period,
consistent with the amortization of previous storm damage expense deferrals
approved in a 1992 rate case. The ultimate recovery of the entire deferred
storm damage costs is subject to Virginia SCC approval. If not approved,
results of operations could be adversely affected. The Virginia SCC Staff has
recommended that approximately $12,000,000 of the $23,900,000 in storm damage
expenses be treated as if they have previously been recovered in earnings
(based on the results of the Staff's earnings test) and the remainder be
deferred for future recovery over a five-year period. A hearing examiner's
report is pending.

CSPCO

ZIMMER PLANT: The Zimmer Plant was placed in commercial operation as a
1,300-megawatt coal-fired plant on March 30, 1991. CSPCo owns 25.4% of the
Zimmer Plant with the remainder owned by two unaffiliated companies, CG&E
(46.5%) and DP&L (28.1%).

ZIMMER PLANT - RATE RECOVERY: In May 1992, the PUCO issued an order
providing for a phased-in rate increase of $123,000,000 for the Zimmer Plant to
be implemented in three steps over a two-year period and disallowed
$165,000,000 of Zimmer Plant investment. CSPCo appealed the PUCO ordered
Zimmer disallowance and phase-in plan to the Ohio Supreme Court. In November
1993, the Supreme Court issued a decision on CSPCo's appeal affirming the
disallowance and finding that the PUCO did not have statutory authority to
order phased-in rates. The court instructed the PUCO to fix rates to provide
gross annual revenue in accordance with the law and to provide a mechanism to
recover the revenues deferred under the phase-in order.

As a result of the ruling, 1993 net income was reduced by $144,500,000 after
tax to reflect the disallowance and in January 1994, the PUCO approved a 7.11%
or $57,167,000 rate increase effective February 1, 1994. The increase is
comprised of a 3.72% base rate increase and a temporary 3.39% surcharge, which
will be in effect until the phase-in plan deferrals are recovered, currently
estimated to be mid-1997. In 1995, $28,500,000 of net phase-in deferrals were
collected through the surcharge which reduced the deferrals from $75,400,000 at
December 31, 1994 to $46,900,000 at December 31, 1995. In 1993 and 1992,
$47,900,000 and $46,000,000, respectively, were deferred under the phase-in
plan. The recovery of amounts deferred under the phase-in plan and the
increase in rates to the full rate level did not affect net income.

From the in-service date of March 1991 until rates went into effect in May
1992, deferred carrying charges of $43,000,000 were recorded on the Zimmer
Plant investment. Recovery of the deferred carrying charges will be sought in
the next PUCO base rate proceeding in accordance with the PUCO accounting order
that authorized the deferral.

Reference is made to the caption ENVIRONMENTAL AND OTHER MATTERS - ACID RAIN
PROGRAM - AEP SYSTEM COMPLIANCE PLAN for information regarding AEP's compliance
plan which was approved by the PUCO.

KEPCO

In September 1995, KEPCo, the Kentucky Attorney General and other interested
parties filed an application with the KPSC to implement KEPCo's DSM Three-Year
Experimental Plan which consisted of DSM programs for residential, commercial
and industrial sectors. Under the plan, program costs, as well as net lost
revenues and incentives, would be recovered by sector under an annual surcharge
tariff. In December 1995, the KPSC issued an order approving the three-year
plan for the period ending December 31, 1998.

OPCO

An application was filed by OPCo in July 1994 with the PUCO seeking a
$152,500,000 annual base retail rate increase to recover, among other things,
the costs associated with the Gavin Plant's flue gas desulfurization systems
(scrubbers). In February 1995, OPCo and certain other parties to the
proceeding entered into a settlement agreement to resolve, among other issues,
the pending base rate case and the current electric fuel component (EFC)
proceeding. On March 23, 1995, the PUCO issued an order approving the
settlement agreement, with certain minor exceptions. Under the terms of the
settlement agreement, effective March 23, 1995, base rates increase by
$66,000,000 annually which includes recovery of the annual cost of the
scrubbers; the EFC rate is fixed at 1.465 cents per kwh from June 1, 1995
through November 30, 1998; OPCo is provided with the opportunity to recover its
Ohio jurisdictional share of the investment in, and the liabilities and future
shutdown costs of, all affiliated mines as well as any fuel costs incurred
above the fixed rate; and OPCo may proceed with its Clean Air Act Amendments of
1990 compliance plan as filed with the PUCO (discussed under ENVIRONMENTAL AND
OTHER MATTERS - ACID RAIN PROGRAM - AEP SYSTEM COMPLIANCE PLAN). The
settlement agreement allows OPCo to continue to operate its Muskingum and
Windsor mines.

Based on a stipulation agreement approved by the PUCO in November 1992,
beginning December 1, 1994, the cost of coal burned at the Gavin Plant is
subject to a 15-year predetermined price of $1.575 per million Btus with
quarterly escalation adjustments. As discussed above, the PUCO-approved
settlement agreement fixes the EFC factor at 1.465 cents per kwh for the period
June 1995 through November 1998. After November 2009, the price that OPCo can
recover for coal from its affiliated Meigs mine which supplies the Gavin Plant
will be limited to the lower of cost or the then-current market price. The
predetermined Gavin Plant price agreement, in conjunction with the above-
referenced settlement agreement, provide OPCo with an opportunity to recover
any operating losses incurred under the predetermined or fixed price, as well
as its investment in, and liabilities and closing costs associated with, its
affiliated mining operations attributable to its Ohio jurisdiction, to the
extent the actual cost of coal burned at the Gavin Plant is below the
predetermined price.

Based on the estimated future cost of coal burned at Gavin Plant, management
believes that the Ohio jurisdictional portion of the investment in, and
liabilities and closing costs of, the affiliated mining operations will be
recovered under the terms of the predetermined price agreement.

In November 1992, the municipal wholesale customers of OPCo filed a
complaint with the SEC requesting an investigation of the sale of the Martinka
mining operation to an unaffiliated company and an investigation into the
pricing of OPCo's affiliated coal purchases back to 1986. OPCo has filed a
response with the SEC seeking to dismiss this complaint.

FUEL SUPPLY

The following table shows the sources of power generated by the AEP System:

1991 1992 1993 1994 1995

Coal 86% 93% 86% 91% 88%
Nuclear 13% 6% 13% 8% 11%
Hydroelectric
and other 1% 1% 1% 1% 1%

Variations in the generation of nuclear power are primarily related to
refueling outages and, in 1992, a forced outage at Cook Plant Unit 2. See COOK
NUCLEAR PLANT.

COAL

The Clean Air Act Amendments of 1990 provide for the issuance of annual
allowance allocations covering sulfur dioxide emissions at levels below
historic emission levels for many coal-fired generating units of the AEP
System. Phase I of this program began in 1995 and Phase II begins in 2000,
with both phases requiring significant changes in coal supplies and suppliers.
The full extent of such changes, particularly in regard to Phase II, however,
has not been determined. See ENVIRONMENTAL AND OTHER MATTERS - ACID RAIN
PROGRAM - AEP SYSTEM COMPLIANCE PLAN for the current compliance plan.

In order to meet emission standards for existing and new emission sources,
the AEP System companies will, in any event, have to obtain coal supplies, in
addition to coal reserves now owned by System companies, through the
acquisition of additional coal reserves and/or by entering into additional
supply agreements, either on a long-term or spot basis, at prices and upon
terms which cannot now be predicted.

No representation is made that any of the coal rights owned or controlled by
the System will, in future years, produce for the System any major portion of
the overall coal supply needed for consumption at the coal-fired generating
units of the System. Although AEP believes that in the long run it will be
able to secure coal of adequate quality and in adequate quantities to enable
existing and new units to comply with emission standards applicable to such
sources, no assurance can be given that coal of such quality and quantity will
in fact be available. No assurance can be given either that statutes or
regulations limiting emissions from existing and new sources will not be
further revised in future years to specify lower sulfur contents than now in
effect or other restrictions. See ENVIRONMENTAL AND OTHER MATTERS herein.

The FERC has adopted regulations relating, among other things, to the
circumstances under which, in the event of fuel emergencies or shortages, it
might order electric utilities to generate and transmit electric power to other
regions or systems experiencing fuel shortages, and to rate-making principles
by which such electric utilities would be compensated. In addition, the
Federal Government is authorized, under prescribed conditions, to allocate coal
and to require the transportation thereof, for the use of power plants or major
fuel-burning installations.

System companies have developed programs to conserve coal supplies at System
plants which involve, on a progressive basis, limitations on sales of power and
energy to neighboring utilities, appeals to customers for voluntary limitations
of electric usage to essential needs, curtailment of sales to certain
industrial customers, voltage reductions and, finally, mandatory reductions in
cases where current coal supplies fall below minimum levels. Such programs
have been filed and reviewed with officials of Federal and state agencies and,
in some cases, the state regulatory agency has prescribed actions to be taken
under specified circumstances by System companies, subject to the jurisdiction
of such agencies.

The mining of coal reserves is subject to Federal requirements with respect
to the development and operation of coal mines, and to state and Federal
regulations relating to land reclamation and environmental protection,
including Federal strip mining legislation enacted in August 1977.
Continual evaluation and study is given to possible closure of existing coal
mines and divestiture or acquisition of coal properties in light of Federal
and state environmental and mining laws and regulations which may affect
the System's need for or ability to mine such coal.

Western coal purchased by System companies is transported by rail to a
terminal on the Ohio River for transloading to barges for delivery to
generating stations on the river. Subsidiaries of AEP lease approximately
3,535 coal hopper cars to be used in unit train movements, as well as 14
towboats, 295 jumbo barges and 185 standard barges. Subsidiaries of AEP also
own or lease coal transfer facilities at various locations on the river.

The System generating companies procure coal from coal reserves which are
owned or mined by subsidiaries of AEP, and through purchases pursuant to long-
term contracts, or on a spot purchase basis, from unaffiliated producers. The
following table shows the amount of coal delivered to the AEP System during the
past five years, the proportion of such coal which was obtained either from
coal-mining subsidiaries, from unaffiliated suppliers under long-term contracts
or through spot or short-term purchases, and the average delivered price of
spot coal purchased by System companies:

1991 1992 1993 1994 1995

Total coal delivered to
AEP operated plants (thousands of tons) 45,232 44,738 40,561 49,024 46,867
Sources (percentage):
Subsidiaries 28% 25% 20% 15% 14%
Long-term contracts 62% 65% 66% 65% 75%
Spot or short-term purchases 10% 10% 14% 20% 11%
Average price per ton of spot-purchased
coal $25.40 $23.88 $23.55 $23.00 $25.15

The average cost of coal consumed during the past five years by all AEP
System companies, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo is shown in the
following tables:

1991 1992 1993 1994 1995
Dollars per ton

AEP System Companies $35.16 $34.31 $33.57 $33.95 $32.52
AEGCo 20.65 20.11 17.74 18.59 18.80
APCo 41.99 43.00 42.65 39.89 38.86
CSPCo 35.18 33.87 33.87 32.80 33.23
I&M 25.57 24.23 23.80 22.85 23.25
KEPCo 31.38 30.24 27.08 26.83 26.91
OPCo 40.18 38.36 38.12 41.10 37.58

CENTS PER MILLION BTU'S

AEP System Companies 158.88154.41150.89152.41145.26
AEGCo 123.33 120.90 107.71 112.06 112.87
APCo 169.48 173.05 173.32 161.37 156.96
CSPCo 152.55 143.94 143.66 140.45 140.79
I&M 139.16 135.11 129.39 123.62 125.50
KEPCo 132.25 126.92 113.90 113.40 114.77
OPCo 171.65 163.89 161.25 173.51 157.62

The coal supplies at AEP System plants vary from time to time
plants vary from time to time depending on various factors, including
customers' usage of electric power, space limitations, the rate of
consumption at particular plants, labor unrest and weather conditions
which may interrupt deliveries. At December 31, 1995, the System's coal
inventory was approximately 55 days of normal System usage. This estimate
assumes that the total supply would be utilized by increasing or decreasing
generation at particular plants.

The following tabulation shows the total consumption during 1995 of the
coal-fired generating units of AEP's principal electric utility subsidiaries,
coal requirements of these units over the remainder of their useful lives
and the average sulfur content of coal delivered in 1995 to these units.
Reference is made to ENVIRONMENTAL AND OTHER MATTERS for information
concerning current emissions limitations in the AEP System's various
jurisdictions and the effects of the Clean Air Act Amendments.

ESTIMATED REQUIRE- AVERAGE SULFUR CONTENT
TOTAL CONSUMPTION MENTS FOR REMAINDER OF DELIVERED COAL
During 1995 of Useful Lives Pounds of SO{2}
(IN THOUSANDS OF TONS) (IN MILLIONS OF TONS) BY WEIGHT PER MILLION BTU'S

AEGCo (a) 5,267 261 0.3% 0.7
APCo 8,988 446 0.8% 1.3
CSPCo (b) 5,367 234 2.9% 4.9
I&M (c) 6,723 300 0.5% 1.1
KEPCo 2,953 91 1.2% 2.0
OPCo 17,910 650 2.2% 3.7

(a) Reflects AEGCo's 50% interest in the Rockport Plant.
(b) Includes coal requirements for CSPCo's interest in Beckjord, Stuart and
Zimmer Plants.
(c) Includes I&M's 50% interest in the Rockport Plant.

AEGCO: See FUEL SUPPLY - I&M for a discussion of the coal supply for the
Rockport Plant.

APCO: Substantially all of the coal consumed at APCo's generating plants is
obtained from unaffiliated suppliers under long-term contracts and/or on a spot
purchase basis.

The average sulfur content by weight of the coal received by APCo at its
generating stations approximated 0.8% during 1995, whereas the maximum sulfur
content permitted, for emission standard purposes, for existing plants in the
regions in which APCo's generating stations are located ranged between 0.78%
and 2% by weight depending in some circumstances on the calorific value of the
coal which can be obtained for some generating stations.

CSPCO: CSPCo has coal supply agreements with unaffiliated suppliers for the
delivery of approximately 3,400,000 tons per year through 1998. Some of this
coal is washed to improve its quality and consistency for use principally at
Unit 4 of the Conesville Plant.

CSPCo has been informed by CG&E and DP&L