SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
<square>
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1995
<square>TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from _____________ to ______________
COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER
FILE NUMBER ADDRESS; AND TELEPHONE NUMBER IDENTIFICATION NO.
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640
(A New York Corporation)
1 Riverside Plaza
Columbus, Ohio 43215
Telephone (614) 223-1000
0-18135 AEP GENERATING COMPANY 31-1033833
(An Ohio Corporation)
1 Riverside Plaza
Columbus, Ohio 43215
Telephone (614) 223-1000
1-3457 APPALACHIAN POWER COMPANY 54-0124790
(A Virginia Corporation)
40 Franklin Road, S.W.
Roanoke, Virginia 24011
Telephone (540) 985-2300
1-2680 COLUMBUS SOUTHERN POWER COMPANY 31-4154203
(An Ohio Corporation)
215 North Front Street
Columbus, Ohio 43215
Telephone (614) 464-7700
1-3570 INDIANA MICHIGAN POWER COMPANY 35-0410455
(An Indiana Corporation)
One Summit Square
P. O. Box 60
Fort Wayne, Indiana 46801
Telephone (219) 425-2111
1-6858 KENTUCKY POWER COMPANY 61-0247775
(A Kentucky Corporation)
1701 Central Avenue
Ashland, Kentucky 41101
Telephone (800) 572-1113
1-6543 OHIO POWER COMPANY 31-4271000
(An Ohio Corporation)
301 Cleveland Avenue, S.W.
Canton, Ohio 44702
Telephone (330) 456-8173
AEP Generating Company, Columbus Southern Power Company and Kentucky Power
Company meet the conditions set forth in General Instruction J(1)(a) and (b) of
Form 10-K and are therefore filing this Form 10-K with the reduced disclosure
format specified in General Instruction J(2) to such Form 10-K.
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes <check-mark> . No. .
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED
AEP Generating
Company None
American Electric Common Stock,
Power Company, Inc. $6.50 par value New York Stock Exchange
Appalachian Power Cumulative Preferred
Company Stock Voting,
no par value:
4-1/2% Philadelphia Stock Exchange
4.50% Philadelphia Stock Exchange
7.40% New York Stock Exchange
Columbus Southern 8-3/8% Junior Subordinated
Power Company Deferrable Interest
Debentures, Series A,
Due 2025 New York Stock Exchange
Indiana Michigan Cumulative Preferred
Power Company Stock, Non-Voting,
$100 par value:
4-1/8% Chicago Stock Exchange
7.08% New York Stock Exchange
Kentucky Power Company 8.72% Junior Subordinated
Deferrable Interest
Debentures, Series A,
Due 2025 New York Stock Exchange
Ohio Power Company 8.16% Junior Subordinated
Deferrable Interest
Debentures, Series A,
Due 2025 New York Stock Exchange
Indicate by check mark if disclosure of delinquent filers with respect to
American Electric Power Company, Inc. and Appalachian Power Company pursuant to
Item 405 of Regulation S-K (<section>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 (<section>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. <check-mark>
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.
<PAGE>
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.
<PAGE>
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
<PAGE>
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
<PAGE>
[THIS PAGE INTENTIONALLY LEFT BLANK]
<PAGE>
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:
<TABLE>
<CAPTION>
AEGCO APCO CSPCO I&M KEPCO OPCO AEP SYSTEM (a)
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>
(a) Includes revenues of other subsidiaries not shown and reflects elimination
of intercompany transactions.
<PAGE>
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:
<TABLE>
<CAPTION>
1993 1994 1995 1996
ACTUAL ACTUAL ACTUAL ESTIMATE
(in thousands)
<S> <C> <C> <C> <C>
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
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
1993 1994 1995 1996
ACTUAL ACTUAL ACTUAL ESTIMATE
(in thousands)
<S> <C> <C> <C> <C>
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
</TABLE>
(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.
<PAGE>
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:
<TABLE>
<CAPTION>
TOTAL AEP
SHORT-TERM DEBT AEP AEGCO APCO CSPCO I&M KEPCO OPCO SYSTEM(a)
(in millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>
(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:
<PAGE>
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:
<TABLE>
<CAPTION>
1991 1992 1993 1994 1995
<S> <C> <C> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
1991 1992 1993 1994 1995
Dollars per ton
<S> <C> <C> <C> <C> <C>
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 158.88<cent>154.41<cent>150.89<cent>152.41<cent>145.26<cent>
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
<PAGE>
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.
</TABLE>
<TABLE>
<CAPTION>
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
<S> <C> <C> <C> <C>
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
</TABLE>
(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 that, with respect to the CCD Group
units partly owned but not operated by CSPCo, sufficient coal has been
contracted for or is believed to be available for the approximate lives of the
respective units operated by them. Under the terms of the operating agreements
with respect to CCD Group units, each operating company is contractually
responsible for obtaining the needed fuel.
<PAGE>
I&M: I&M has three coal supply agreements with unaffiliated suppliers
pursuant to which the suppliers are delivering low sulfur coal from surface
mines in Wyoming, principally for consumption by the Rockport Plant. Under
these agreements, the suppliers will sell to I&M, for consumption by I&M at the
Rockport Plant or consignment to other System companies, coal with an average
sulfur content not exceeding 1.2 pounds of sulfur dioxide per million Btu's of
heat input. One contract with remaining deliveries of 67,750,000 tons expires
on December 31, 2014 and another contract with remaining deliveries of
56,400,000 tons expires on December 31, 2004. The third contract with
deliveries of 750,000 tons per year expires in late 1996.
All of the coal consumed at I&M's Tanners Creek Plant is obtained from
unaffiliated suppliers under long-term contracts and/or on a spot purchase
basis.
KEPCO: Substantially all of the coal consumed at KEPCo's Big Sandy Plant is
obtained from unaffiliated suppliers under long-term contracts and/or on a spot
purchase basis. KEPCo has coal supply agreements with unaffiliated suppliers
pursuant to which KEPCo will receive approximately 2,500,000 tons of coal in
1996. To the extent that KEPCo has additional coal requirements, it may
purchase coal from the spot market and/or suppliers under contract to supply
other System companies.
OPCO: The coal consumed at OPCo's generating plants is obtained from both
affiliated and unaffiliated suppliers. The coal obtained from unaffiliated
suppliers is purchased under long-term contracts and/or on a spot purchase
basis.
OPCo and certain of its coal-mining subsidiaries own or control coal
reserves in the State of Ohio which contain approximately 212,000,000 tons of
clean recoverable coal, which ranges in sulfur content between 3.4% and 4.5%
sulfur by weight (weighted average, 3.8%), which can be recovered based upon
existing mining plans and projections and employing current mining practices
and techniques. OPCo and certain of its mining subsidiaries own an additional
113,000,000 tons of clean recoverable coal in Ohio which ranges in sulfur
content between 2.4% and 3.4% sulfur by weight (weighted average 2.7%).
Recovery of this coal would require substantial development.
OPCo and certain of its coal-mining subsidiaries also own or control coal
reserves in the State of West Virginia which contain approximately 106,000,000
tons of clean recoverable coal ranging in sulfur content between 1.4% and 3.3%
sulfur by weight (weighted average, 2.0%) of which approximately 29,000,000
tons can be recovered based upon existing mining plans and projections and
employing current mining practices and techniques.
<PAGE>
NUCLEAR
I&M has made commitments to meet certain of the nuclear fuel requirements of
the Cook Plant. The nuclear fuel cycle consists of the mining and milling of
uranium ore to uranium concentrates; the conversion of uranium concentrates to
uranium hexafluoride; the enrichment of uranium hexafluoride; the fabrication
of fuel assemblies; the utilization of nuclear fuel in the reactor; and the
reprocessing or other disposition of spent fuel. Steps currently are being
taken, based upon the planned fuel cycles for the Cook Plant, to review and
evaluate I&M's requirements for the supply of nuclear fuel beyond the existing
contractual commitments shown in the following table. I&M has made and will
make purchases of uranium in various forms in the spot and short-term market
until it decides that deliveries under mid- or long-term supply contracts are
warranted. The following table shows the year through which contracts have
been entered into to provide the requirements of the units for the various
segments of the nuclear fuel cycle.
<TABLE>
<CAPTION>
URANIUM
CONCENTRATES CONVERSION ENRICHMENT (1) FABRICATION REPROCESSING (2)
<S> <C> <C> <C> <C> <C>
Unit 1 -- -- 2000 2000 --
Unit 2 -- -- 2000 2000 --
</TABLE>
1) I&M has a requirements-type contract with DOE. I&M has partially terminated
the contract, subject to revocation of the termination, so that it may
procure enrichment services cost-effectively from the spot market.
2) No reprocessing facility in the United States currently is in operation.
I&M has contracted for reprocessing services at a facility on which
construction has been halted. Lack of reprocessing services has resulted in
the need to increase on-site storage capacity for spent fuel.
For purposes of the storage of high-level radioactive waste in the form of
spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel
storage pool to permit normal operations through 2010.
I&M's costs of nuclear fuel consumed do not assume any residual or salvage
value for residual plutonium and uranium.
NUCLEAR WASTE AND DECOMMISSIONING
The Nuclear Waste Policy Act of 1982, as amended, establishes Federal
responsibility for the permanent off-site disposal of spent nuclear fuel and
high-level radioactive waste. Disposal costs are paid by fees assessed against
owners of nuclear plants and deposited into the Nuclear Waste Fund created by
the Act. In 1983, I&M entered into a contract with DOE for the disposal of
spent nuclear fuel. Under terms of the contract, for the disposal of nuclear
fuel consumed after April 6, 1983 by I&M's Cook Plant, I&M is paying to the
fund a fee of one mill per kilowatt-hour, which I&M is currently recovering
from customers. For the disposal of nuclear fuel consumed prior to April 7,
1983, I&M must pay the U.S. Treasury a fee estimated at approximately
$71,964,000, exclusive of interest of $91,096,000 at December 31, 1995. The
aggregate amount has been recorded as long-term debt. Because of the current
uncertainties surrounding DOE's program to provide for permanent disposal of
spent nuclear fuel, I&M has not yet paid any of the pre-April 1983 fee. At
December 31, 1995, funds collected from customers to pay the pre-April 1983 fee
and accrued interest approximated the long-term debt liability.
On June 20, 1994, a group of 14 unaffiliated utilities owning and operating
nuclear plants and a group of states each filed a petition for review in the
U.S. Court of Appeals for the District of Columbia Circuit requesting that the
court issue a declaration that the Nuclear Waste Policy Act of 1982 imposes on
DOE an unconditional obligation to begin acceptance of spent nuclear fuel and
high level radioactive waste by January 31, 1998. DOE has indicated in its
Notice of Inquiry of May 25, 1994 that its preliminary view is that it has no
statutory obligation to begin to accept spent nuclear fuel beginning in 1998 in
the absence of an operational repository. In April 1995, DOE issued its Final
Interpretation affirming its earlier view. On May 30, 1995, I&M filed a
petition for review seeking the same relief requested earlier by the group of
utilities. This action was consolidated with the earlier petition. I&M also
seeks, if warranted, relief from the financial burden of fees being paid to
DOE.
Studies completed in 1994 estimate decommissioning and low-level radioactive
waste disposal costs for the Cook Plant to range from $634,000,000 to
$988,000,000 in 1993 nondiscounted dollars. The wide range is caused by
variables in assumptions, including the estimated length of time spent nuclear
fuel must be stored at the Cook Plant subsequent to ceasing operations, which
depends on future developments in the federal government's spent nuclear fuel
disposal program. Continued delays in the federal fuel disposal program can
result in increased decommissioning costs. I&M is recovering decommissioning
costs in its three rate-making jurisdictions based on at least the lower end of
the range in the most recent respective decommissioning study available at the
time of the rate proceeding (the study range utilized in the Indiana rate case,
I&M's primary jurisdiction, was $588,000,000 to $1.102 billion in 1991
dollars). I&M records decommissioning costs in other operation expense and
records a noncurrent liability equal to the decommissioning cost recovered in
rates which was $30,000,000 in 1995, $26,000,000 in 1994 and $13,000,000 in
1993. At December 31, 1995, I&M had recognized a decommissioning liability of
$269,000,000. I&M will continue to reevaluate periodically the cost of
decommissioning and to seek regulatory approval to revise its rates as
necessary.
Funds recovered through the rate-making process for disposal of spent
nuclear fuel consumed prior to April 7, 1983 and for nuclear decommissioning
have been segregated and deposited in external funds for the future payment of
such costs. Trust fund earnings decrease the amount to be recovered from
ratepayers.
The ultimate cost of retiring I&M's Cook Plant may be materially different
from the estimates contained in the site-specific study and the funding targets
as a result of (a) the type of decommissioning plan selected, (b) the
escalation of various cost elements (including, but not limited to, general
inflation), (c) the further development of regulatory requirements governing
decommissioning, (d) the absence to date of significant experience in
decommissioning such facilities and (e) the technology available at the time of
decommissioning differing significantly from that assumed in these studies.
Accordingly, management is unable to provide assurance that the ultimate cost
of decommissioning the Cook Plant will not be significantly greater than
current projections.
In February 1996, the Financial Accounting Standards Board (FASB) issued an
exposure draft entitled ACCOUNTING FOR CERTAIN LIABILITIES RELATED TO CLOSURE
OR REMOVAL OF LONG-LIVED ASSETS. The exposure draft proposes that the present
value of any decommissioning or other closure or removal obligation be recorded
as a liability when the obligation is incurred. A corresponding asset would be
recorded in the plant investment account and recovered through depreciation
charges over the asset's life. A proposed transition rule would require that
an entity report a charge to income for the cumulative effect of initially
applying the proposed standard. Management is studying the proposed standard
and evaluating its potential impact.
The Low-Level Waste Policy Act of 1980 (LLWPA) mandates that the
responsibility for the disposal of low-level waste rests with the individual
states. Low-level radioactive waste consists largely of ordinary trash and
other items that have come in contact with radioactive materials. To
facilitate this approach, the LLWPA authorized states to enter into regional
compacts for low-level waste disposal subject to Congressional approval. The
LLWPA also specified that, beginning in 1986, approved compacts may prohibit
the importation of low-level waste from other regions, thereby providing a
strong incentive for states to enter into compacts. As 1986 approached it
became apparent that no new disposal facilities would be operational, and
enforcement of the LLWPA would leave no disposal capacity for the majority of
the low-level waste generated in the United States. Congress, therefore,
passed the Low-Level Waste Policy Amendments Act of 1985. Michigan, the state
where the Cook Plant is located, was a member of the Midwest Compact, but its
membership was revoked in 1991. Michigan is responsible for developing a
disposal site for the low-level waste generated in Michigan.
In 1994, Michigan amended its law regarding disposal sites to provide for
allowing a volunteer to host a facility. Although progress has been made, the
site selection process is very long and management is unable to predict when a
permanent disposal site for Michigan low-level waste will be available.
On July 1, 1995, the disposal site in South Carolina reopened to accept
waste from most areas of the U.S., including Michigan. This is the first
opportunity for the Cook Plant to dispose of waste at that site since November
1990 when South Carolina denied access to its disposal site. To the extent
necessary, the Cook Plant's low-level radioactive waste is being stored on-
site. I&M has an on-site radioactive material storage facility at the Cook
Plant for temporary preshipment storage of the plant's low-level radioactive
waste. The facility can hold as much low-level waste as the Cook Plant is
expected to produce through approximately 2001, and the building could be
expanded to accommodate the storage of such waste through approximately 2017.
Currently, the Cook Plant produces less than 7,000 cubic feet of low-level
waste annually.
ENERGY POLICY ACT - NUCLEAR FEES
The Energy Policy Act of 1992 (Energy Act), contains a provision to fund the
decommissioning and decontamination of DOE's existing uranium enrichment
facilities from a combination of sources including assessments against electric
utilities which purchased enrichment services from DOE facilities. I&M's
remaining estimated liability is $45,703,000, subject to inflation adjustments,
and is payable in annual assessments over the next 11 years. I&M recorded a
regulatory asset concurrent with the recording of the liability. The payments
are being recorded and recovered as fuel expense.
In a case involving an unaffiliated utility, the U.S. Court of Federal
Claims decided in June 1995 that these assessments are unlawful. On November
13, 1995, the Federal Government appealed this decision to the U.S. Court of
Appeals for the Federal Circuit. I&M has filed with DOE claims for refunds
under certain of its enrichment services contracts based on this decision. I&M
also intends to pursue refund claims on other enrichment services contracts
directly to the U.S. Court of Federal Claims.
ENVIRONMENTAL AND OTHER MATTERS
AEP's subsidiaries are subject to regulation by Federal, state and local
authorities with regard to air and water-quality control and other
environmental matters, and are subject to zoning and other regulation by local
authorities.
It is expected that costs related to environmental requirements will
eventually be reflected in the rates of AEP's electric utility subsidiaries and
that, in the long term, AEP's electric utility subsidiaries will be able to
provide for such environmental controls as are required. However, some
customers may curtail or cease operations as a consequence of higher energy
costs. There can be no assurance that all such costs will be recovered.
Except as noted herein, AEP's subsidiaries which own or operate generating
facilities generally are in compliance with pollution control laws and
regulations.
AIR POLLUTION CONTROL
CLEAN AIR ACT AMENDMENTS OF 1990: For the AEP System, compliance with the
Clean Air Act Amendments of 1990 (CAAA) is requiring substantial expenditures
which are being recovered through increases in the rates of AEP's operating
subsidiaries. OPCo is incurring a major portion of such costs. There can be
no assurance that all such costs will be recovered. See CONSTRUCTION PROGRAM -
CONSTRUCTION EXPENDITURES.
The Acid Rain Program provisions of the CAAA create an emission allowance
program pursuant to which utilities are authorized to emit a designated
quantity of sulfur dioxide, measured in tons per year, on a system wide or
aggregate basis. Emission reductions are required by virtue of the
establishment of annual allowance allocations at a level below historical
emission levels for many utility units. For units that emitted sulfur dioxide
above a rate of 2.5 pounds per million Btu heat input in 1985, the CAAA
establish sulfur dioxide allowance limitations (caps or ceilings on emissions)
premised upon sulfur dioxide emissions at a rate of 2.5 pounds per million Btu
heat input at 1985 utilization levels as of the Phase I deadline of January 1,
1995. The following AEP System units are Phase I-affected units: I&M's Breed
Plant and Tanners Creek Unit 4; CSPCo's Beckjord Unit 6, Conesville Units 1-4,
Picway Unit 5 and Stuart Units 1-4; and OPCo's Gavin Units 1-2, Muskingum River
Units 1-5, Cardinal Unit 1, Mitchell Units 1-2 and Kammer Units 1-3. Phase I
permits have been issued for all Phase I-affected units in the AEP System.
All fossil fuel-fired steam generating units with capacity greater than 25
megawatts are affected in Phase II of the acid rain control program. All Phase
II-affected units are allocated allowances with which compliance must be
accomplished beginning January 1, 2000. The basis for Phase II allowance
allocation depends on 1985 sulfur dioxide emission rates - if a unit emitted
sulfur dioxide in 1985 at a rate in excess of 1.2 pounds per million Btu heat
input, the allowance allocation is premised upon an emission rate of 1.2 pounds
at 1985 utilization levels as of the Phase II deadline of January 1, 2000; if a
unit emitted sulfur dioxide in 1985 at a rate of less than 1.2 pounds, the
allowance allocation is in most instances premised upon the actual 1985
emission rate.
The Acid Rain Title also contains provisions concerning nitrogen oxides
emissions. In March 1994, Federal EPA issued final regulations governing
nitrogen oxides emissions from tangentially fired and dry bottom wall-fired
boilers at Phase I units which were appealed to the U.S. Court of Appeals for
the District of Columbia Circuit by APCo, CSPCo, I&M, KEPCo and OPCo and a
group of unaffiliated utilities based on the failure of Federal EPA to
correctly define low NOx burner technology. On November 29, 1994, the court
remanded the rules to Federal EPA and on April 13, 1995, Federal EPA issued
revised regulations pursuant to the court's remand. Compliance with these
emission limitations is determined on an annual basis beginning in 1996.
OPCo's Mitchell Units 1 & 2 and CSPCo's Conesville Units 3 & 4 and Picway Unit
5 are Phase I units subject to these regulations.
On January 19, 1996, Federal EPA published proposed Nox emission limitations
in the FEDERAL REGISTER for wet bottom wall-fired boilers, cyclone boilers,
units applying cell burner technology and all other types of boilers. These
proposed emission limitations are purported to be comparable in cost to the
controls applicable to tangentially fired boilers and non-cell burner dry
bottom wall-fired boilers. These emission limitations are required to be met
by Phase II-affected sources after January 1, 2000. Also on January 19, 1996,
Federal EPA published proposed revisions to the existing emission limitations
for tangentially fired and dry bottom wall-fired boilers. Federal EPA must
take final action on the proposed revisions by January 1, 1997. These
limitations are expected to be more restrictive than those which are currently
applicable.
The CAAA contain additional provisions, other than the Acid Rain Title,
which could require reductions in emissions of nitrogen oxides from fossil
fuel-fired power plants. Title I, dealing generally with non-attainment of
ambient air quality standards, establishes a tiered system for classifying
degrees of non-attainment with air quality standards for ozone. Depending upon
the severity of non-attainment within a given non-attainment area, reductions
in nitrogen oxides emissions from fossil fuel-fired power plants may be
required as part of a state's plan for achieving attainment with ozone air
quality standards. On February 25, 1994, the West Virginia Division of
Environmental Protection issued a consent order for APCo's Amos Units 1 and 2,
requiring reductions in nitrogen oxides emissions from these units after June
1, 1995. The reduction in nitrogen oxides emissions will be less than that
required under Title IV of the CAAA but will be required at an earlier time.
On September 6, 1994, Federal EPA officially redesignated Putnam, Wood and
Kanawha counties to ozone attainment. West Virginia does not plan to impose
Nox reduction requirements under Title I of the CAAA as part of its ozone
maintenance plan in any of the five former moderate ozone non-attainment
counties, barring any other mandate from Federal EPA to do so. While ozone
non-attainment is largely restricted to urban areas, AEP System generating
stations could be determined to be affecting ozone concentrations and may
therefore, eventually be required to reduce nitrogen oxides emissions pursuant
to Title I.
In addition, certain environmental organizations and northeastern states
have filed comments with Federal EPA contending that nitrogen oxides emissions
from the midwest must be reduced in order to achieve the National Ambient Air
Quality Standard for ozone in the northeast. Similar comments have been filed
by these organizations and others with the FERC in connection with the proposed
rulemaking involving open access to transmission facilities. See TRANSMISSION
SERVICES - TRANSMISSION SERVICES FOR NON-AFFILIATES. All AEP coal-fired plants
are potentially subject to the imposition of additional emission controls
resulting from these initiatives. The Environmental Council of States formed
the Ozone Transport Assessment Group (OTAG) in early 1995 to develop estimates
of levels of reduction in volatile organic compound and/or nitrogen oxides
emissions required for significant reductions in ozone concentrations in the
eastern United States. OTAG, consisting of the environmental commissioners and
air directors of 37 eastern states, Federal EPA and representatives from
environmental and industry groups, is currently scheduled to complete modeling
and technical work by the fall of 1996 - with evaluation of technical findings
and recommendations on regional emission controls to be submitted to Federal
EPA by January 1997. The cost of meeting Nox emissions reduction requirements
which might be imposed to achieve the ozone ambient air quality standard cannot
be precisely predicted but could be substantial.
Utility boilers are potentially subject to additional control requirements
under Title III of the CAAA governing hazardous air pollutant emissions.
Federal EPA is directed to conduct studies concerning the potential public
health impacts of pollutants identified by the legislation as hazardous in
connection with their emission from electric utility steam generating units.
Federal EPA was required to report the results of this study to Congress by
November 1993 and is required to regulate emissions of these pollutants from
electric utility steam generating units if it is determined that such
regulation is necessary and appropriate, based on the results of the study.
Federal EPA informed Congress that completion of this study has been delayed
significantly beyond the November 1993 deadline. Federal EPA is subject to a
judicial consent decree requiring completion of the study and submission of it
by April 15, 1996. Additionally, Federal EPA is directed to study the
deposition of hazardous pollutants to the Great Lakes, the Chesapeake Bay, Lake
Champlain and other coastal waters. As part of this assessment, Federal EPA is
authorized to adopt regulations to prevent serious adverse effects to public
health and serious or widespread environmental effects. It is possible that
emissions from electric utility steam generating units may be regulated under
this water body deposition assessment program.
The CAAA expand the enforcement authority of the Federal government by
increasing the range of civil and criminal penalties for violations of the
Clean Air Act and enhancing administrative civil provisions, adding a citizen
suit provision and imposing a national operating permit system, emission fee
program and enhanced monitoring, record keeping and reporting requirements for
existing and new sources.
ACID RAIN PROGRAM - AEP SYSTEM COMPLIANCE PLAN: In 1992, the PUCO approved
a system-wide Phase I Acid Rain Program compliance plan. The AEP System's
compliance plan centers around the compliance method selected for OPCo's two-
unit 2,600-megawatt Gavin Plant which was emitting about 25% of the System's
total sulfur dioxide emissions. Under an Ohio law, utilities could obtain
advance PUCO approval of a least-cost compliance plan which would be deemed
prudent in subsequent PUCO rate proceedings.
The PUCO approved least-cost plan set forth compliance measures for the
System's affected generating units, which included (i) installing leased flue
gas desulfurization equipment (scrubbers) to burn Ohio high-sulfur coal at
Gavin and (ii) designating Gavin's coal supply sources to include the
affiliated Meigs mine at a reduced operating capacity and under predetermined
prices, new long-term contracts with unaffiliated sources and spot market
purchases.
Pursuant to a settlement agreement approved by the PUCO in connection with
OPCo's rate case discussed in RATES - OPCO, the PUCO reaffirmed its approval of
the compliance plan, which does not seek to fuel switch Cardinal Unit 1 or
Muskingum River Units 1-4 to low-sulfur coal at the beginning of Phase I of the
CAAA. Under the terms of the compliance plan, OPCo's Muskingum River Unit 5
has been switched to low-sulfur coal. CSPCo's Conesville Units 1-3 have been
modified to enable these units to burn coal or natural gas to comply. Actual
fuel choice will depend on the cost and availability of gas. Although the
compliance plan originally contemplated that CSPCo's Picway Unit 5 also would
be modified to enable this unit to burn coal or natural gas to comply, this
proposed modification has been indefinitely deferred. Beckjord Unit 6 (owned
with CG&E and DP&L) has been switched to moderate sulfur coal. I&M's Tanners
Creek Unit 4 has also been switched to moderate sulfur coal and I&M's Breed
Plant was retired in 1994. Eight additional units are subject to Phase I rules,
but no operating or fuel changes are planned, because they will hold allowances
sufficient for compliance.
Since the approved plan reflects fuel switching to comply at OPCo's
Muskingum River Plant and Cardinal Unit 1, mining operations at OPCo's wholly-
owned coal-mining subsidiaries, Central Ohio Coal Company and Windsor Coal
Company, could be shut down resulting in substantial costs. Central Ohio Coal
Company and Windsor Coal Company supply coal to Muskingum River Plant and
Cardinal Plant, respectively.
As a result of the aforementioned PUCO approval of OPCo's least-cost
compliance plan, OPCo entered into an agreement in 1992 for construction and
lease of the Gavin Plant scrubbers with JMG Funding, Limited Partnership (JMG),
an unaffiliated entity. The scrubbers on Gavin Units 1 and 2 commenced
operation in December 1994 and March 1995, respectively. On March 15, 1995,
OPCo began to lease the scrubbers from JMG. See CONSTRUCTION PROGRAM -
CONSTRUCTION EXPENDITURES.
Recovery of compliance costs has been and will be sought through the rate-
making process. The aforementioned OPCo settlement agreement provides, among
other things, for OPCo to recover the annual lease cost of the scrubbers and
other compliance costs and provides OPCo with an opportunity to recover its
Ohio jurisdictional share of its investment in and the liabilities and closing
costs of the affiliated Central Ohio and Windsor mining operations to the
extent the actual cost of coal burned at the Gavin Plant is below a
predetermined price. AEP intends to also seek timely recovery of all
compliance costs, including mine shutdown costs, from its non-Ohio
jurisdictional customers. OPCo's non-Ohio jurisdictional portion of shutdown
costs for these mines, which includes the investment in the mines, leased asset
buy-outs, reclamation costs and employee benefits is estimated to be
approximately $195,000,000 net of tax at December 31, 1995. There can be no
assurance that regulators will provide for recovery of all CAAA compliance
costs. Compliance with the CAAA, including potential mine closure costs, could
have an adverse effect on results of operations and possibly financial
condition unless the costs can be recovered from ratepayers and/or from asset
dispositions.
GLOBAL CLIMATE CHANGE: Increasing concentrations of "greenhouse gases,"
including carbon dioxide (CO{2}), in the atmosphere have led to concerns about
the potential for the earth's climate to change in ways that could result in
adverse human health effects, destruction of sensitive ecosystems, inundated
low-lying areas caused by sea-level rise, shifts in agricultural production and
other serious environmental consequences. The proponents of this view maintain
that rising levels of greenhouse gas emissions will cause some of the sun's
energy that is normally radiated back into space to be trapped in the
atmosphere, warming the biosphere and triggering these detrimental effects.
At the Earth Summit in Rio de Janeiro, Brazil in June 1992, 165 nations,
including the United States, signed a global climate change treaty. Each
country that ratifies the treaty commits itself to a process of achieving the
aim of reducing greenhouse gas emissions, including CO{2}, to their 1990 level
by the year 2000. On October 7, 1992, the U.S. Senate ratified the treaty.
The treaty went into effect on March 21, 1994. In April 1995, the first
meeting of the nations that have ratified was held. The parties declared that
the existing commitments under the treaty are not adequate to address the
threat of global climate change and authorized the immediate commencement of
negotiations on a protocol or other legal instrument for emission controls in
the post-2000 period. The protocol or other legal instrument is required to
set forth "policies and measures," and "quantified limitation and reduction
objectives within specified time frames, such as 2005, 2010 and 2020" to be
adopted by signatory nations. The negotiations are expected to be complete in
early 1997.
In accordance with the obligations set forth in the global climate change
treaty, on April 21, 1993, President Clinton committed the United States to
reducing greenhouse gas emissions to 1990 levels by the year 2000. On October
19, 1993, the President unveiled the Administration's Climate Change Action
Plan for meeting this emission reduction target. The plan emphasizes
reductions in fossil fuel use, the largest source of CO{2} emissions, primarily
through reliance on voluntary energy efficiency programs and partnerships
between the Federal government and U.S. industry. One such collaboration is
between the electric utility industry and DOE. Known as the Climate Challenge,
this initiative has identified flexible, cost-effective measures to reduce,
avoid or sequester future greenhouse gas emissions. AEP System companies
joined with nearly 800 investor-owned, municipal, rural electric cooperative
and Federal utilities in a voluntary agreement signed with DOE on April 20,
1994 that has led to individual utility Participation Accords resulting in
substantial reductions in future greenhouse gas emissions. On February 3,
1995, the AEP System entered into its Climate Challenge Participation Accord
with DOE. The Accord contains a diverse portfolio of supply-side, demand-side
and forest management/tree planting activities that will be undertaken on the
AEP System between now and the year 2000 with a projected reduction in CO{2}
emissions of 9,550,000 tons from what would have otherwise been emitted but for
these actions.
As a result of the AEP System's historical practice of using low-cost
indigenous coal supplies to produce electricity, AEP System power plants are
significant sources of CO{2} emissions. Management is working to support
further efforts to properly study the issue of global climate change to define
the extent, if any, to which it poses a threat to the environment. Management
is concerned that new laws may be passed or new regulations promulgated without
sufficient scientific study and support.
Since the AEP System is a major emitter of carbon dioxide, its financial
condition and results of operations could be materially adversely affected by
the imposition of stringent command-and-control limitations on CO{2} emissions
if the compliance costs incurred are not fully recovered from ratepayers. In
addition, any such severe program to stabilize or reduce CO{2} emissions could
impose substantial costs on industry and society and seriously erode the
economic base that AEP's operations serve.
WEST VIRGINIA: West Virginia promulgated sulfur dioxide limitations which
Federal EPA approved in February 1978. The emission limitations for the
Mitchell Plant have been approved by Federal EPA for primary ambient air
quality (health-related) standards only. West Virginia is obliged to reanalyze
sulfur dioxide emission limits for the Mitchell Plant with respect to secondary
ambient air quality (welfare-related) standards. Because the Clean Air Act
provides no specific deadline for approval of emission limits to achieve
secondary ambient air quality standards, it is not certain when Federal EPA
will take dispositive action regarding the Mitchell Plant.
West Virginia has had a request to increase the sulfur dioxide emission
limitation for Kammer pending before Federal EPA for many years, although the
change has not been acted upon by Federal EPA. On August 4, 1994, however,
Federal EPA issued a Notice of Violation to OPCo alleging that Kammer Plant was
operating in violation of the applicable federally enforceable sulfur dioxide
emission limit. See Item 3. LEGAL PROCEEDINGS - KAMMER PLANT. A portion of
the Notice of Violation relating to compliance has been resolved. Separate
proceedings have been initiated by OPCo with both the West Virginia Division of
Environmental Protection and Region III, Federal EPA in an effort to obtain
approval for utilization of the existing fuel supply beyond the current final
compliance date of May 15, 1996. While it is likely that the May 15, 1996
final compliance date will be extended, management cannot predict at this time
how long it will be able to utilize the existing fuel supply at the Kammer
Plant.
STACK HEIGHT REGULATIONS: On June 27, 1985, Federal EPA issued stack height
regulations pursuant to an order of the United States Court of Appeals for the
District of Columbia Circuit. These regulations were appealed by a number of
states, environmental groups and investor-owned electric utilities (including
APCo, CSPCo, I&M, KEPCo and OPCo), along with three electric utility trade
associations. OPCo also filed a separate petition for review to raise issues
unique to its Kammer Plant. Various petitions for reconsideration filed with
and denied by Federal EPA were also appealed. This litigation was consolidated
into a single case.
On January 22, 1988, the U.S. Court of Appeals issued a decision in part
upholding the June 1985 stack height rules and remanding certain of the June
1985 rules to Federal EPA for further consideration. With respect to Kammer
Plant, the January 1988 court decision rejected OPCo's appeal, holding that
Federal EPA acted lawfully in revoking stack height credit previously granted
for Kammer Plant in October 1982. As discussed above, OPCo has also commenced
administrative proceedings with the State of West Virginia and Federal EPA in
an effort to preserve stack height credit for Kammer Plant.
While it is not possible to state with particularity the ultimate impact of
the final rules on AEP System operations, at present it appears that the most
likely AEP System plants at which the final rules could possibly result in more
stringent emission limitations are CSPCo's Conesville Plant, AEGCo's and I&M's
Rockport Plant, I&M's Tanners Creek Plant and OPCo's Gavin and Kammer plants.
Gavin and Rockport plants were not affected by Federal EPA's stack height rules
as issued in June 1985. However, the provision exempting these plants was
remanded to Federal EPA in the January 1988 court decision. Accordingly, the
ultimate impact of the stack height rules on Gavin and Rockport plants will not
be known until Federal EPA completes administrative proceedings on remand and
reissues final stack height rules. OPCo and AEGCo and I&M intend to
participate in the remand rulemaking affecting Gavin and Rockport plants,
respectively.
State air pollution control agencies will be required to implement the stack
height rules by revising emission limitations for sources subject to the rules
and submitting such revisions to Federal EPA.
On June 1, 1989, Ohio EPA adopted a rule concerning CSPCo's Conesville Plant
in response to Federal EPA's stack height rules adopted in 1985. Under Federal
EPA policy published in January 1988, emission reductions required by the stack
height rules may be obtained at plants other than the plant directly affected
by the rules, and thereafter credited to the directly affected plant. Under
Ohio EPA's June 1 rule, the sulfur dioxide emission limitations for Conesville
Units 5 and 6 remain at 1.2 pounds sulfur dioxide per million Btu heat input as
long as the emission rate at CSPCo's retired Poston Units 1-4 remains at 0.0
pounds sulfur dioxide per million Btu heat input. Federal EPA has yet to take
action concerning Ohio EPA's June 1 rule.
ADMINISTRATIVE DEVELOPMENTS REGARDING SULFUR DIOXIDE: On November 15, 1994,
Federal EPA published a notice in the FEDERAL REGISTER proposing to retain the
present 24-hour national ambient air quality standard for sulfur dioxide.
Federal EPA also sought comment on the need to adopt additional regulations to
address short-term peak exposures to sulfur dioxide. Federal EPA is soliciting
comments on three alternatives, including the adoption of a short-term standard
averaged over a five-minute period. Adoption of any of these proposed
approaches, or other targeted programs, could require substantial reductions in
sulfur dioxide emissions from the System's coal-fired generating plants which
would entail substantial capital and operating costs. In a related action,
Federal EPA, on March 7, 1995, proposed requirements for implementing
strategies to reduce short-term (five-minute) peak concentrations of sulfur
dioxide in order to reduce health risks to exercising asthmatics. The effect
on AEP operations of Federal EPA's proposed risk-based targeting strategies for
further regulating sulfur dioxide emissions, if finalized, cannot be predicted,
but may be significant. Federal EPA is expected to take final action on these
proposals in the spring of 1996.
LIFE EXTENSION: On July 21, 1992, Federal EPA published final regulations
in the FEDERAL REGISTER governing application of new source rules to generating
plant repairs and pollution control projects undertaken to comply with the
Clean Air Act Amendments of 1990. Generally, the rule provides that plants
undertaking pollution control projects will not trigger new source review
requirements. The Natural Resources Defense Council and a group of utilities,
including five AEP System companies, have filed petitions in the U.S. Court of
Appeals for the District of Columbia Circuit seeking a review of the
regulations.
OTHER REGULATORY DEVELOPMENTS: Federal EPA is considering whether the
National Ambient Air Quality Standard for ozone should be revised and is
currently expected to make a final decision on this issue in 1997.
Federal EPA is also considering revision of the National Ambient Air Quality
Standard for particulate matter. Federal EPA is required by court order to
make a final determination on this issue by June 28, 1997.
WATER POLLUTION CONTROL
Under the Clean Water Act, effluent limitations requiring application of the
best available technology economically achievable are to be applied, and those
limitations require that no pollutants be discharged if Federal EPA finds
elimination of such discharges is technologically and economically achievable.
The Clean Water Act provides citizens with a cause of action to enforce
compliance with its pollution control requirements. Since 1982, many such
actions against NPDES permit holders have been filed. To date, no AEP System
plants have been named in such actions.
All System Plants are operating with NPDES permits. Under EPA's
regulations, operation under an expired NPDES permit is authorized provided an
application is filed at least 180 days prior to expiration. Renewal
applications are being prepared or have been filed for renewal of NPDES permits
which expire in 1996.
The NPDES permits generally require that certain thermal impact study
programs be undertaken. These studies have been completed for all System
plants. Thermal variances are in effect for all plants with once-through
cooling water. The thermal variances for Conesville and Muskingum River plants
impose thermal management conditions that could result in load curtailment
under certain conditions, but the cost impacts are not expected to be
significant. Based on favorable results of in-stream biological studies, OPCo
has requested a modification of the thermal management plan in the renewed
permit for Muskingum River expected to be issued this year.
Certain mining operations conducted by System companies as discussed under
FUEL SUPPLY are also subject to Federal and state water pollution control
requirements, which may entail substantial expenditures for control facilities,
not included at present in the System's construction cost estimates set forth
herein. See Item 3. LEGAL PROCEEDINGS - MEIGS MINE with respect to litigation
regarding certain discharges from OPCo's Meigs 31 mine.
The Federal Water Quality Act of 1987 requires states to adopt stringent
water quality standards for a large category of toxic pollutants and to
identify specialized control measures for dischargers to waters where water
quality standards are not being met. Implementation of these provisions could
result in significant costs to the AEP System if biological monitoring
requirements and water quality-based effluent limits are placed in NPDES
permits.
In March 1995, Federal EPA finalized a set of rules which establish minimum
water quality standards, anti-degradation policies and implementation
procedures for more stringently controlling releases of toxic pollutants into
the Great Lakes system. This regulatory package is called the Great Lakes
Water Quality Initiative (GLWQI). The most direct compliance cost impact could
be related to I&M's Cook Plant. Management cannot presently determine whether
the GLWQI would have a significant adverse impact on AEP operations. The
significance of such impact will depend on the outcome of Federal EPA's policy
on intake credits and site specific variables as well as Michigan's
implementation strategy. Federal EPA's rule is presently under review by the
District of Columbia Circuit Court of Appeals in litigation initiated by
several industry groups. If Indiana and Ohio eventually adopt the GLWQI
criteria for statewide application, AEP System plants located in those states
could also be affected.
HAZARDOUS SUBSTANCES AND WASTES
Section 311 of the Clean Water Act imposes substantial penalties for spills
of Federal EPA-listed hazardous substances into water and for failure to report
such spills. The Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA) expanded the reporting requirements to cover the release
of hazardous substances generally into the environment, including water, land
and air. AEP's subsidiaries store and use some of these hazardous substances,
including PCB's contained in certain capacitors and transformers, but the
occurrence and ramifications of a spill or release of such substances cannot be
predicted.
CERCLA provides governmental agencies with the authority to require clean-up
of hazardous waste sites and releases of hazardous substances into the
environment. Since liability under CERCLA is strict and can be applied
retroactively, AEP System companies which previously disposed of PCB-containing
electrical equipment and other hazardous substances may be required to
participate in remedial activities at such disposal sites should environmental
problems result. AEP System companies are presently identified by Federal EPA
as potentially responsible parties (PRPs) for cleanup of seven federal sites,
including I&M at four sites, KEPCo at one site, OPCo at one site, and Wheeling
Power Company at one site. OPCo is a defendant in a cost recovery suit for the
site where OPCo is a PRP and at two additional CERCLA sites. I&M is a
defendant in a cost recovery action at one of the sites where I&M is a PRP and
for one additional CERCLA site. APCo and I&M each have been named as parties
potentially responsible at a state remediation site. Management's present
estimates do not anticipate material cleanup costs for identified sites for
which AEP subsidiaries have been declared PRPs. However, if for reasons not
currently identified significant costs are incurred for cleanup, future results
of operations and possibly financial condition would be adversely affected
unless the costs can be recovered through rates.
Regulations issued by Federal EPA under the Toxic Substances Control Act
govern the use, distribution and disposal of PCBs, including PCBs in electrical
equipment. Deadlines for removing certain PCB-containing electrical equipment
from service have been met.
In addition to handling hazardous substances, the System companies generate
solid waste associated with the combustion of coal, the vast majority of which
is fly ash, bottom ash and flue gas desulfurization wastes. These wastes
presently are considered to be non-hazardous under RCRA and applicable state
law and the wastes are treated and disposed in surface impoundments or
landfills in accordance with state permits or authorization or beneficially
utilized. As required by RCRA, EPA evaluated whether high volume coal
combustion wastes (such as fly ash, bottom ash and flue gas desulfurization
wastes) should be regulated as hazardous waste. In August, 1993 EPA issued a
regulatory determination that such high volume coal combustion wastes should
not be regulated as hazardous waste. For low volume coal combustion wastes,
such as metal and boiler cleaning wastes, Federal EPA will gather additional
information and make a regulatory determination by April 1998. Until that
time, these low volume wastes are provisionally excluded from regulation under
the hazardous waste provisions of RCRA. All presently generated hazardous
waste is being disposed of at permitted off-site facilities in compliance with
applicable Federal and state laws and regulations. For System facilities which
generate such wastes, System companies have filed the requisite notices and are
complying with RCRA and applicable state regulations for generators. Nuclear
waste produced at the Cook Plant regulated under the Atomic Energy Act is
excluded from regulation under RCRA.
Federal EPA's technical requirements for underground storage tanks
containing petroleum will require retrofitting or replacement of an appreciable
number of tanks. Compliance costs for tank replacement and site remediation
have not been significant to date.
ELECTRIC AND MAGNETIC FIELDS (EMF)
EMF is found everywhere there is electricity. Electric fields are created
by the presence of electric charges. Magnetic fields are produced by the flow
of those charges. This means that EMF is created by electricity flowing in
transmission and distribution lines, or being used in household wiring and
appliances.
A number of studies in the past several years have examined the possibility
of adverse health effects from EMF. While some of the epidemiological studies
have indicated some association between exposure to EMF and health effects, the
majority of studies have indicated no such association. The epidemiological
studies that have received the most public attention reflect a weak correlation
between surrogate or indirect estimates of EMF exposure and certain cancers.
Studies using direct measurements of EMF exposure show no such association.
There were two residential epidemiological studies of childhood brain cancer
published in early 1996 which showed no association with EMF exposure.
Research to date has not shown any causal relationship between EMF exposure and
cancer, or any other adverse health effects. Additional studies, which are
intended to provide a better understanding of the subject, are continuing.
Federal EPA is currently studying whether exposure to EMF is associated with
cancer in humans. In 1990, Federal EPA issued a draft report on EMF, received
interagency review and public comment, and is in the process of preparing its
final report. A December 1992 brochure from Federal EPA, QUESTIONS AND ANSWERS
ABOUT ELECTRIC AND MAGNETIC FIELDS (EMFS), states at page 3, "The bottom line
is that there is no established cause and effect relationship between EMF
exposure and cancer or other disease."
The Energy Policy Act of 1992 established a coordinated Federal EMF research
program. The program funding is $65,000,000 over five years, half of which is
to be provided by private parties including utilities. AEP has committed to
contribute $446,571 over the five-year period.
AEP's participation is a continuation of its efforts to support further
research and to communicate with its customers and employees about this issue.
Its operating company subsidiaries provide their residential customers with
information and field measurements on request, although there is no scientific
basis for interpreting such measurements.
A number of lawsuits based on EMF-related grounds have been filed in recent
years against electric utilities. A suit was filed on May 23, 1990 against I&M
involving claims that EMF from a 345 KV transmission line caused adverse health
effects. No specific amount has been requested for damages in this case and no
trial date has been set.
Some states have enacted regulations to limit the strength of magnetic
fields at the edge of transmission line rights-of-way. No state which the AEP
System serves has done so. In March 1993, The Ohio Power Siting Board issued
its amended rules providing for additional consideration of the possible
effects of EMF in the certification of electric transmission facilities. Under
the amended EMF rules, persons seeking approval to build electric transmission
lines have to provide estimates of EMF from transmission lines under a variety
of conditions. In addition, applicants are required to address possible health
effects and discuss the consideration of design alternatives with respect to
EMF.
In April 1993, the State of Indiana enacted a law which provides that the
IURC shall determine, based on the preponderance of evidence in the scientific
literature, whether rules are necessary to protect the public health from EMF.
If the IURC determines that such rules are necessary, the IURC is required to
adopt rules that reasonably protect the public health from EMF.
Management cannot predict the ultimate impact of the question of EMF
exposure and adverse health effects. If further research shows that EMF
exposure contributes to increased risk of cancer or other health problems, or
if the courts conclude that EMF exposure harms individuals and that utilities
are liable for damages, or if states limit the strength of magnetic fields to
such a level that the current electricity delivery system must be significantly
changed, then the results of operations and financial condition of AEP and its
operating subsidiaries could be materially adversely affected unless these
costs can be recovered from ratepayers.
RESEARCH AND DEVELOPMENT
AEP and its subsidiaries are involved in a number of research projects which
are directed toward developing more efficient methods of burning coal, reducing
the contaminants resulting from combustion of coal, and improving the
efficiency and reliability of power transmission, distribution and utilization,
including load management.
AEP System operating companies are members of the Electric Power Research
Institute (EPRI), a nonprofit organization that manages research and
development on behalf of the U.S. electric utility industry. EPRI, founded in
1973, manages technical research and development programs for its members to
improve power production, delivery and use. Approximately 700 utilities are
members. EPRI has agreed to a membership program with AEP whereby dues are
being phased in from 1994 through 1996. Recovery of these dues through rates
by AEP's operating companies has reasonably coincided with their phase-in
dates. It is anticipated that recovery of the final 1996 dues phase-in will be
sought in future rate cases.
<PAGE>
Total research and development expenditures by AEP and its subsidiaries were
approximately $19,300,000 for the year ended December 31, 1995, $7,600,000 for
the year ended December 31, 1994 and $13,800,000 for the year ended December
31, 1993. This includes expenditures of $6,700,000 for 1995, $2,200,000 for
1994 and $10,900,000 for 1993 related to pressurized fluidized-bed combustion,
a process in which sulfur is removed during coal combustion and nitrogen oxide
formation is minimized. EPRI dues of $9,600,000 for 1995 and $3,200,000 for
1994 are also included.
Item 2. PROPERTIES
At December 31, 1995, subsidiaries of AEP owned (or leased where indicated)
generating plants with the net power capabilities (winter rating) shown in the
following table:
<TABLE>
<CAPTION>
NET KILOWATT
OWNER, PLANT TYPE AND NAME LOCATION (NEAR) CAPABILITY
<S> <C> <C>
AEP GENERATING COMPANY:
Steam - Coal-Fired:
Rockport Plant (AEGCo share) Rockport, Indiana 1,300,000(a)
APPALACHIAN POWER COMPANY:
Steam - Coal-Fired:
John E. Amos, Units 1 & 2 St. Albans, West Virginia 1,600,000
John E. Amos, Unit 3 (APCo share) St. Albans, West Virginia 433,000(b)
Clinch River Carbo, Virginia 705,000
Glen Lyn Glen Lyn, Virginia 335,000
Kanawha River Glasgow, West Virginia 400,000
Mountaineer New Haven, West Virginia 1,300,000
Philip Sporn, Units 1 & 3 New Haven, West Virginia 308,000
Hydroelectric - Conventional:
Buck Ivanhoe, Virginia 10,000
Byllesby Byllesby, Virginia 20,000
Claytor Radford, Virginia 76,000
Leesville Leesville, Virginia 40,000
London Montgomery, West Virginia 16,000
Marmet Marmet, West Virginia 16,000
Niagara Roanoke, Virginia 3,000
Reusens Lynchburg, Virginia 12,000
Winfield Winfield, West Virginia 19,000
Hydroelectric - Pumped Storage:
Smith Mountain Penhook, Virginia 565,000
5,858,000
COLUMBUS SOUTHERN POWER COMPANY:
Steam - Coal-Fired:
Beckjord, Unit 6 New Richmond, Ohio 53,000(c)
Conesville, Units 1-3, 5 & 6 Coshocton, Ohio 1,165,000
Conesville, Unit 4 Coshocton, Ohio 339,000(c)
Picway, Unit 5 Columbus, Ohio 100,000
Stuart, Units 1-4 Aberdeen, Ohio 608,000(c)
Zimmer Moscow, Ohio 330,000(c)
2,595,000
INDIANA MICHIGAN POWER COMPANY:
Steam - Coal-Fired:
Rockport Plant (I&M share) Rockport, Indiana 1,300,000(a)
Tanners Creek Lawrenceburg, Indiana 995,000
Steam - Nuclear:
Donald C. Cook Bridgman, Michigan 2,110,000
Gas Turbine:
Fourth Street Fort Wayne, Indiana 18,000(d)
Hydroelectric - Conventional:
Berrien Springs Berrien Springs, Michigan 3,000
Buchanan Buchanan, Michigan 2,000
Constantine Constantine, Michigan 1,000
Elkhart Elkhart, Indiana 1,000
Mottville Mottville, Michigan 1,000
Twin Branch Mishawaka, Indiana 3,000
4,434,000
KENTUCKY POWER COMPANY:
Steam - Coal-Fired:
Big Sandy Louisa, Kentucky 1,060,000
OHIO POWER COMPANY:
Steam - Coal-Fired:
John E. Amos, Unit 3 (OPCo share) St. Albans, West Virginia 867,000(b)
Cardinal, Unit 1 Brilliant, Ohio 600,000
General James M. Gavin Cheshire, Ohio 2,600,000(e)
Kammer Captina, West Virginia 630,000
Mitchell Captina, West Virginia 1,600,000
Steam - Coal-Fired:
Muskingum River Beverly, Ohio 1,425,000
Philip Sporn, Units 2, 4 & 5 New Haven, West Virginia 742,000
Hydroelectric - Conventional:
Racine Racine, Ohio 48,000
8,512,000
Total Generating Capability 23,759,000
SUMMARY:
Total Steam -
Coal-Fired 20,795,000
Nuclear 2,110,000
Total Hydroelectric -
Conventional 271,000
Pumped Storage 565,000
Other 18,000
Total Generating Capability 23,759,000
</TABLE>
(a)Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by I&M.
Unit 2 of the Rockport Plant is leased one-half by AEGCo and one-half by
I&M. The leases terminate in 2022 unless extended.
(b)Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds
by OPCo.
(c)Represents CSPCo's ownership interest in generating units owned in common
with CG&E and DP&L.
(d)Leased from the City of Fort Wayne, Indiana. Since 1975, I&M has leased and
operated the assets of the municipal system of the City of Fort Wayne,
Indiana under a 35-year lease with a provision for an additional 15-year
extension at the election of I&M.
(e)The scrubber facilities at the Gavin Plant are leased. The lease terminates
in 2010 unless extended.
See Item 1 under FUEL SUPPLY, for information concerning coal reserves owned
or controlled by subsidiaries of AEP.
The following table sets forth the total circuit miles of transmission and
distribution lines of the AEP System, APCo, CSPCo, I&M, KEPCo and OPCo and that
portion of the total representing 765,000-volt lines:
TOTAL CIRCUIT MILES
OF TRANSMISSION AND CIRCUIT MILES OF
DISTRIBUTION LINES 765,000-VOLT LINES
AEP System (a) 125,545(b) 2,022
APCo 48,961 641
CSPCo (a) 14,710 ---
I&M 20,784 614
KEPCo 9,944 258
OPCo 28,286 509
(a) Includes 766 miles of 345,000-volt jointly owned lines.
(b) Includes lines of other AEP System companies not shown.
TITLES
The AEP System's electric generating stations are generally located on lands
owned in fee simple. The greater portion of the transmission and distribution
lines of the System has been constructed over lands of private owners pursuant
to easements or along public highways and streets pursuant to appropriate
statutory authority. The rights of the System in the realty on which its
facilities are located are considered by it to be adequate for its use in the
conduct of its business. Minor defects and irregularities customarily found in
title to properties of like size and character may exist, but such defects and
irregularities do not materially impair the use of the properties affected
thereby. System companies generally have the right of eminent domain whereby
they may, if necessary, acquire, perfect or secure titles to or easements on
privately-held lands used or to be used in their utility operations.
Substantially all the physical properties of APCo, CSPCo, I&M, KEPCo and
OPCo are subject to the lien of the mortgage and deed of trust securing the
first mortgage bonds of each such company.
SYSTEM TRANSMISSION LINES AND FACILITY SITING
Legislation in the states of Indiana, Kentucky, Michigan, Ohio, Virginia,
and West Virginia requires prior approval of sites of generating facilities
and/or routes of high-voltage transmission lines. Delays and additional costs
in constructing facilities have been experienced as a result of proceedings
conducted pursuant to such statutes, as well as in proceedings in which
operating companies have sought to acquire rights-of-way through condemnation,
and such proceedings may result in additional delays and costs in future years.
PEAK DEMAND
The AEP System is interconnected through 120 high-voltage transmission
interconnections with 29 neighboring electric utility systems. The all-time
and 1995 one-hour peak System demands were 25,940,000 and 24,888,000 kilowatts,
respectively (which included 7,314,000 and 4,934,000 kilowatts, respectively,
of scheduled deliveries to unaffiliated systems which the System might, on
appropriate notice, have elected not to schedule for delivery) and occurred on
June 17, 1994 and August 15, 1995, respectively. The net dependable capacity
to serve the System load on such date, including power available under
contractual obligations, was 23,457,000 and 23,364,000 kilowatts, respectively.
The all-time and 1995 one-hour internal peak demands were 19,557,000 and
19,516,000 kilowatts, respectively, and occurred on February 5, 1996 and August
14, 1995, respectively. The net dependable capacity to serve the System load
on such date, including power dedicated under contractual arrangements, was
23,670,000 and 23,364,000 kilowatts, respectively. The all-time one-hour
integrated and internal net system peak demands and 1995 peak demands for AEP's
generating subsidiaries are shown in the following tabulation:
ALL-TIME ONE-HOUR INTEGRATED 1995 ONE-HOUR INTEGRATED
NET SYSTEM PEAK DEMAND NET SYSTEM PEAK DEMAND
(in thousands)
Number of Number of
KILOWATTS DATE KILOWATTS DATE
APCo 8,214 February 5, 1996 7,327 February 6, 1995
CSPCo 4,172 June 17, 1994 4,085 August 14, 1995
I&M 5,027 June 17, 1994 4,949 August 15, 1995
KEPCo 1,686 February 5, 1996 1,512 February 6, 1995
OPCo 7,291 June 17, 1994 6,913 August 15, 1995
ALL-TIME ONE-HOUR INTEGRATED 1995 ONE-HOUR INTEGRATED
NET INTERNAL PEAK DEMAND NET INTERNAL PEAK DEMAND
(in thousands)
Number of Number of
KILOWATTS DATE KILOWATTS DATE
APCo 6,908 February 5, 1996 6,507 February 9, 1995
CSPCo 3,378 August 14, 1995 3,378 August 14, 1995
I&M 3,864 August 14, 1995 3,864 August 14, 1995
KEPCo 1,418 February 5, 1996 1,363 February 9, 1995
OPCo 5,641 August 14, 1995 5,641 August 14, 1995
HYDROELECTRIC PLANTS
Licenses for hydroelectric plants, issued under the Federal Power Act,
reserve to the United States the right to take over the project at the
expiration of the license term, to issue a new license to another entity, or to
relicense the project to the existing licensee. In the event that a project is
taken over by the United States or licensed to a new licensee, the Federal
Power Act provides for payment to the existing licensee of its "net investment"
plus severance damages. Licenses for six System hydroelectric plants expired
in 1993 and applications for new licenses for these plants were filed in 1991.
The existing licenses for these plants were extended on an annual basis and
will be renewed automatically until new licenses are issued. No competing
license applications were filed. Four new licenses were issued in 1994. New
licenses for two other projects, one in Indiana and one in Michigan, are still
pending before the FERC. An original license for the previously unlicensed
Constantine project was issued in 1993. In 1995, a notice of intent to
relicense the Elkhart project located in Indiana was filed.
COOK NUCLEAR PLANT
Unit 1 of the Cook Plant, which was placed in commercial operation in 1975,
has a nominal net electric rating of 1,020,000 kilowatts. Unit 1's
availability factor was 66.3% during 1995 and 71.0% during 1994. Unit 2, of
slightly different design, has a nominal net electrical rating of 1,090,000
kilowatts and was placed in commercial operation in 1978. Unit 2's
availability factor was 94.4% during 1995 and 54.3% during 1994. Outages to
refuel affected the availability of Unit 1 in 1995 and Units 1 and 2 in 1994.
Units 1 and 2 are licensed by the NRC to operate at 100% of rated thermal
power to October 25, 2014 and December 23, 2017, respectively.
Costs associated with the operation, maintenance and retirement of nuclear
plants continue to be significant and less predictable than costs associated
with other sources of generation, in large part due to changing regulatory
requirements and safety standards and experience gained in the construction and
operation of nuclear facilities. I&M may also incur costs and experience
reduced output at its Cook Plant because of the design criteria prevailing at
the time of construction and the age of the plant's systems and equipment. In
addition, for economic or other reasons, operation of the Cook Plant for the
full term of its now assumed life cannot be assured. Nuclear industry-wide and
Cook Plant initiatives have contributed to slowing the growth of operating and
maintenance costs. However, the ability of I&M to obtain adequate and timely
recovery of costs associated with the Cook Plant, including replacement power
and retirement costs, is not assured.
NUCLEAR INCIDENT LIABILITY
The Price-Anderson Act limits public liability for a nuclear incident at any
licensed reactor in the United States to $8.9 billion. I&M has insurance
coverage for liability from a nuclear incident at its Cook Plant. Such
coverage is provided through a combination of private liability insurance, with
the maximum amount available of $200,000,000, and mandatory participation for
the remainder of the $8.9 billion liability, in an industry retrospective
deferred premium plan which would, in case of a nuclear incident, assess all
licensees of nuclear plants in the U.S. Under the deferred premium plan, I&M
could be assessed up to $158,600,000 payable in annual installments of
$20,000,000 in the event of a nuclear incident at Cook or any other nuclear
plant in the U.S. There is no limit on the number of incidents for which I&M
could be assessed these sums.
I&M also has property damage, decontamination and decommissioning insurance
for loss resulting from damage to the Cook Plant facilities in the amount of
$3.6 billion. Energy Insurance Bermuda (EIB), Nuclear Mutual Limited (NML) and
Nuclear Electric Insurance Limited (NEIL) provide $2.75 billion of coverage and
nuclear insurance pools provide the remainder. If EIB's, NML's and NEIL's
losses exceed their available resources, I&M would be subject to a total
retrospective premium assessment of up to $33,000,000. NRC regulations require
that, in the event of an accident, whenever the estimated costs of reactor
stabilization and site decontamination exceed $100,000,000, the insurance
proceeds must be used, first, to return the reactor to, and maintain it in, a
safe and stable condition and, second, to decontaminate the reactor and reactor
station site in accordance with a plan approved by the NRC. The insurers then
would indemnify I&M for property damage up to $3.35 billion less any amounts
used for stabilization and decontamination. The remaining $250,000,000, as
provided by NEIL (reduced by any stabilization and decontamination expenditures
over $3.35 billion), would cover decommissioning costs in excess of funds
already collected for decommissioning. See FUEL SUPPLY - NUCLEAR WASTE.
NEIL's extra-expense program provides insurance to cover extra costs
resulting from a prolonged accidental outage of a nuclear unit. I&M's policy
insures against such increased costs up to approximately $3,500,000 per week
(starting 21 weeks after the outage) for one year, $2,800,000 per week for the
second and third years, or 80% of those amounts per unit if both units are down
for the same reason. If NEIL's losses exceed its available resources, I&M
would be subject to a total retrospective premium assessment of up to
$7,900,000.
POTENTIAL UNINSURED LOSSES
Some potential losses or liabilities may not be insurable or the amount of
insurance carried may not be sufficient to meet potential losses and
liabilities, including liabilities relating to damage to the Cook Plant and
costs of replacement power in the event of a nuclear incident at the Cook
Plant. Future losses or liabilities which are not completely insured, unless
allowed to be recovered through rates, could have a material adverse effect on
results of operations and the financial condition of AEP, I&M and other AEP
System companies.
<PAGE>
Item 3. LEGAL PROCEEDINGS
On April 4, 1991, then Secretary of Labor Lynn Martin announced that the
U.S. Department of Labor (DOL) had issued a total of 4,710 citations to
operators of 847 coal mines who allegedly submitted respirable dust sampling
cassettes that had been altered so as to remove a portion of the dust. The
cassettes were submitted in compliance with DOL regulations which require
systematic sampling of airborne dust in coal mines and submission of the entire
cassettes (which include filters for collecting dust particulates) to the Mine
Safety and Health Administration (MSHA) for analysis. The amount of dust
contained on the cassette's filter determines an operator's compliance with
respirable dust standards under the law. OPCo's Meigs No. 2, Meigs No. 31,
Martinka, and Windsor Coal mines received 16, 3, 15 and 2 citations,
respectively. MSHA has assessed civil penalties totalling $56,900 for all
these citations. OPCo's samples in question involve about 1 percent of the
2,500 air samples that OPCo submitted over a 20-month period from 1989 through
1991 to the DOL. OPCo is contesting the citations before the Federal Mine
Safety and Health Review Commission. An administrative hearing was held before
an administrative law judge with respect to all affected coal operators. On
July 20, 1993, the administrative law judge rendered a decision in this case
holding that the Secretary of Labor failed to establish that the presence of a
"white center" on the dust sampling filter indicated intentional alteration.
In the case of an unaffiliated mine, the administrative law judge ruled on
April 20, 1994, that there was not an intentional alteration of the dust
sampling filter. The Secretary of Labor appealed to the Federal Mine Safety
and Health Review Commission the July 20, 1993 and April 20, 1994
administrative law judge decisions and in November 1995 the Commission affirmed
these decisions. All remaining cases, including the citations involving OPCo's
mines, have been stayed.
On September 30, 1994, Federal EPA served APCo and Global Power Company, an
independent contractor retained by APCo, with a complaint alleging violations
of the Clean Air Act. The complaint is based on alleged violations of the
National Emission Standard for Asbestos related to an asbestos abatement
project at APCo's Kanawha River Plant. The complaint seeks a civil
administrative penalty of $167,500. On October 27, 1994, APCo and Global
jointly filed an answer to this complaint and requested both a formal hearing
and informal settlement conference.
On February 28, 1994, Ormet Corporation filed a complaint in the U.S.
District Court, Northern District of West Virginia, against AEP, OPCo, the
Service Corporation and two of its employees, Federal EPA and the Administrator
of Federal EPA. Ormet is the operator of a major aluminum reduction plant in
Ohio and is a customer of OPCo. See CERTAIN INDUSTRIAL CUSTOMERS. Pursuant to
the Clean Air Act Amendments of 1990, OPCo received SO{2} Allowances for its
Kammer Plant. See ENVIRONMENTAL AND OTHER MATTERS. Ormet's complaint sought a
declaration that it is the owner of approximately 89% of the Phase I and Phase
II SO{2} allowances issued for use by the Kammer Plant. On March 31, 1995, the
District Court issued an opinion and order dismissing Ormet's claims based on a
lack of jurisdiction. On April 11, 1995, Ormet appealed the District Court's
decision to the U.S. Court of Appeals for the Fourth Circuit with respect to
the Service Corporation and OPCo only.
See Item 1 for a discussion of certain environmental and rate matters.
MEIGS MINE: On July 11, 1993, water from an adjoining sealed and abandoned
mine owned by Southern Ohio Coal Company (SOCCo), a mining subsidiary of OPCo,
entered Meigs 31 mine, one of two mines currently being operated by SOCCo.
Ohio EPA approved a plan to pump water from the mine to certain Ohio River
tributaries under stringent conditions for biological and water quality
monitoring and restoring the streams after pumping. On July 30, pumping
commenced in accordance with the Ohio EPA approved plan and, after all water
was removed from the mine, the mine was returned to service in February 1994.
In April 1994, the U.S. Court of Appeals for the Sixth Circuit reversed the
judgement of the U.S. District Court for the Southern District of Ohio which
had granted a preliminary injunction to SOCCo preventing Federal EPA and the
Federal Office of Surface Mining, Reclamation and Enforcement (OSM) from
interfering with the removal of water from SOCCo's Meigs 31 mine.
The West Virginia Division of Environmental Protection (West Virginia DEP)
had proposed fining SOCCo $1,800,000 for violations of West Virginia Water
Quality Standards and permitting requirements alleged to have resulted from the
release of mine water into the Ohio River. As a result of the West Virginia
DEP proposing to fine SOCCo, SOCCo filed an action on June 1, 1994 in the U.S.
District Court for the Southern District of West Virginia seeking a
determination that the state of West Virginia has no jurisdiction to impose
penalties with respect to the mine water discharges. SOCCo and the West
Virginia DEP have entered into a settlement agreement dated May 8, 1995, under
which the West Virginia DEP has released SOCCo from any claims which it may
have had and SOCCo has made a donation of $260,000 to the Water Quality
Management Fund of the West Virginia DEP.
SOCCo has entered into a consent decree and settlement agreement with
Federal EPA and OSM which was lodged with the U.S. District Court, Southern
District of Ohio, on January 30, 1996 and noticed in the FEDERAL REGISTER on
February 15, 1996. The decree and settlement agreement resolve all disputes
between SOCCo and Federal EPA and OSM over the legality of the removal of water
from SOCCo's Meigs 31 mine. Under the terms of the settlement agreement, SOCCo
is responsible for the return of pre-pumping biological conditions in the
affected streams if those conditions do not return to pre-pumping status under
the plan previously agreed to by SOCCo and the Ohio EPA as a condition to the
pumping. SOCCo will pay to the U.S. $1,900,000 as compensation for natural
resources alleged to have been affected by the mine dewatering. The $1,900,000
will be used to fund Leading Creek watershed enhancement projects in three Ohio
counties. Under the settlement agreement, SOCCo is also required to pay to the
U.S. $242,200 as reimbursement for costs incurred in monitoring and assessing
the effects of its discharge of water. SOCCo will also pay to the U.S. a civil
penalty of $300,000. Of this amount, $200,000 is designated as settlement for
claims under the Clean Water Act, and $100,000 is designated as settlement for
claims under the Surface Mining Control and Reclamation Act. Finally, SOCCo
will provide $100,000 to the State of West Virginia for work in the Ohio
River for the benefit of Leading Creek on acceptance by the U.S. Fish and
Wildlife Service of an acceptable plan from the State.
KAMMER PLANT: In August 1994, Federal EPA issued a Notice of Violation (NOV)
to OPCo alleging that its Kammer Plant has been operating in violation of
applicable federally enforceable air pollution control requirements for sulfur
dioxide since at least January 1, 1989. The Clean Air Act provides that
Federal EPA may commence a civil action for injunctive relief and/or civil
penalties of up to $25,000 per day for each day of violation. On November 15,
1994, a civil complaint containing the allegations included in the NOV was
filed by Federal EPA against OPCo in the U.S. District Court, Northern District
of West Virginia. A Partial Consent Decree has been entered by the court,
extending until May 15, 1996 the date by which OPCo would need to reduce the
sulfur content of the fuel supply for Kammer. Negotiations are in an advanced
stage to extend the final compliance date beyond May 15, 1996 and to resolve
the penalty issues raised by the civil complaint. It is not anticipated that
the ultimate resolution of this matter will have a material adverse impact on
results of operations.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
AEP, APCO, I&M AND OPCO. None.
AEGCO, CSPCO AND KEPCO. Omitted pursuant to Instruction J(2)(c).
EXECUTIVE OFFICERS OF THE REGISTRANTS
AEP
The following persons are, or may be deemed, executive officers of AEP.
Their ages are given as of March 15, 1996.
NAME AGE OFFICE (a)
E. Linn Draper, Jr. 54 Chairman of the Board, President and Chief Executive
Officer of AEP and of the Service Corporation
Peter J. DeMaria 61 Controller of AEP; Executive Vice President-
Administration and Chief Accounting Officer of the
Service Corporation
William J. Lhota 56 Executive Vice President of the Service Corporation
Gerald P. Maloney 63 Vice President and Secretary of AEP; Executive Vice
President-Chief Financial Officer of the Service
Corporation
James J. Markowsky 51 Executive Vice President-Power Generation of the
Service Corporation
(a)All of the executive officers listed above have been employed by the Service
Corporation or System companies in various capacities (AEP, as such, has no
employees) during the past five years, except E. Linn Draper, Jr. who was
Chairman of the Board, President and Chief Executive Officer of Gulf States
Utilities Company from 1987 until 1992 when he joined AEP and the Service
Corporation. All of the above officers are appointed annually for a one-
year term by the board of directors of AEP, the board of directors of the
Service Corporation, or both, as the case may be.
APCO
The names of the executive officers of APCo, the positions they hold with
APCo, their ages as of March 15, 1996, and a brief account of their business
experience during the past five years appears below. The directors and
executive officers of APCo are elected annually to serve a one-year term.
<TABLE>
<CAPTION>
NAME AGE POSITION (a) PERIOD
<S> <C> <C> <C>
E. Linn Draper, Jr. 54 Director 1992-Present
Chairman of the Board and Chief Executive Officer 1993-Present
Vice President 1992-1993
Chairman of the Board, President and Chief Executive
Officer of AEP and the Service Corporation 1993-Present
President of AEP 1992-1993
President and Chief Operating Officer of the Service
Corporation 1992-1993
Chairman of the Board, President and Chief Executive
Officer of Gulf States Utilities Company 1987-1992
Peter J. DeMaria 61 Director 1988-Present
Vice President 1991-Present
Controller 1995-Present
Treasurer 1978-1995
Controller of AEP 1995-Present
Treasurer of AEP 1978-1995
Executive Vice President-Administration and Chief
Accounting Officer of the Service Corporation 1984-Present
Treasurer of the Service Corporation 1989-1990
William J. Lhota 56 Director 1990-Present
President and Chief Operating Officer 1996-Present
Vice President 1989-1995
Executive Vice President of the Service Corporation 1993-Present
Executive Vice President-Operations of the Service
Corporation 1989-1993
Gerald P. Maloney 63 Director and Vice President 1970-Present
Vice President of AEP 1974-Present
Secretary of AEP 1994-Present
Executive Vice President-Chief Financial Officer of
the Service Corporation 1991-Present
Senior Vice President-Finance of the Service
Corporation 1974-1990
James J. Markowsky 51 Director 1993-Present
Vice President 1995-Present
Executive Vice President-Power Generation of the
Service Corporation 1996-Present
Executive Vice President-Engineering and Construction
of the Service Corporation 1993-1996
Senior Vice President and Chief Engineer of the
Service Corporation 1988-1993
(a) Positions are with APCo unless otherwise indicated.
OPCO
The names of the executive officers of OPCo, the positions they hold with
OPCo, their ages as of March 15, 1996, and a brief account of their business
experience during the past five years appear below. The directors and
executive officers of OPCo are elected annually to serve a one-year term.
</TABLE>
<TABLE>
<CAPTION>
NAME AGE POSITION (a) PERIOD
<S> <C> <C> <C>
E. Linn Draper, Jr. 54 Director 1992-Present
Chairman of the Board and Chief Executive Officer 1993-Present
Vice President 1992-1993
Chairman of the Board, President and Chief Executive
Officer of AEP and the Service Corporation 1993-Present
President of AEP 1992-1993
President and Chief Operating Officer of the Service
Corporation 1992-1993
Chairman of the Board, President and Chief Executive
Officer of Gulf States Utilities Company 1987-1992
Peter J. DeMaria 61 Director 1978-Present
Vice President 1991-Present
Controller 1995-Present
Treasurer 1978-1995
Controller of AEP 1995-Present
Treasurer of AEP 1978-1995
Executive Vice President-Administration and Chief
Accounting Officer of the Service Corporation 1984-Present
Treasurer of the Service Corporation 1989-1990
William J. Lhota 56 Director 1989-Present
President and Chief Operating Officer 1996-Present
Vice President 1989-1995
Executive Vice President of the Service Corporation 1993-Present
Executive Vice President-Operations of the Service
Corporation 1989-1993
Gerald P. Maloney 63 Director 1973-Present
Vice President 1970-Present
Vice President of AEP 1974-Present
Secretary of AEP 1994-Present
Executive Vice President-Chief Financial Officer of
the Service Corporation 1991-Present
Senior Vice President-Finance of the Service
Corporation 1974-1990
James J. Markowsky 51 Director 1989-Present
Vice President 1995-Present
Executive Vice President-Power Generation of the
Service Corporation 1996-Present
Executive Vice President-Engineering and Construction
of the Service Corporation 1993-1996
Senior Vice President and Chief Engineer of the
Service Corporation 1988-1993
(a) Positions are with OPCo unless otherwise indicated.
<PAGE>
PART II
Item 5.MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
AEP. AEP Common Stock is traded principally on the New York Stock Exchange.
The following table sets forth for the calendar periods indicated the high and
low sales prices for the Common Stock as reported on the New York Stock
Exchange Compsite Tape and the amount of cash dividends paid per share of
Common Stock.
At December 31, 1995, AEP had approximately 170,980 shareholders of
record.
AEGCO, APCO, CSPCO, I&M, KEPCO AND OPCO. The information required by
this item is not applicable as the common stock of all these companies is
held solely by AEP.
PER SHARE
MARKET PRICE
QUARTER ENDED HIGH LOW DIVIDEND(1)
March 1994 $37-3/8 $29-7/8 $.60
June 1994 32-7/8 27-1/4 .60
September 1994 31-3/4 28 .60
December 1994 33-5/8 30-1/2 .60
March 1995 35-3/4 31-1/4 .60
June 1995 35-3/8 31-1/2 .60
September 1995 36-1/2 33-5/8 .60
December 1995 40-5/8 35-7/8 .60
(1)See Note 5 of the Notes to the Consolidated Financial Statements of
AEP for information regarding restrictions on payment of dividends.
</TABLE>
Item 6. SELECTED FINANCIAL DATA
AEGCO. Omitted pursuant to Instruction J(2)(a).
AEP. The information required by this item is incorporated herein by
reference to the material under SELECTED CONSOLIDATED FINANCIAL DATA in the
AEP 1995 Annual Report (for the fiscal year ended December 31, 1995).
APCO. The information required by this item is incorporated herein by
reference to the material under SELECTED CONSOLIDATED FINANCIAL DATA in the
APCo 1995 Annual Report (for the fiscal year ended December 31, 1995).
CSPCO. Omitted pursuant to Instruction J(2)(a).
I&M. The information required by this item is incorporated herein by
reference to the material under SELECTED CONSOLIDATED FINANCIAL DATA in the
I&M 1995 Annual Report (for the fiscal year ended December 31, 1995).
KEPCO. Omitted pursuant to Instruction J(2)(a).
OPCO. The information required by this item is incorporated herein by
reference to the material under SELECTED CONSOLIDATED FINANCIAL DATA in the
OPCo 1995 Annual Report (for the fiscal year ended December 31, 1995).
Item 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION
AEGCO. Omitted pursuant to Instruction J(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction J(2)(a) is incorporated herein by reference to the material under
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS in the AEGCo 1995
Annual Report (for the fiscal year ended December 31, 1995).
AEP. The information required by this item is incorporated herein by
reference to the material under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION in the AEP 1995 Annual Report
(for the fiscal year ended December 31, 1995).
APCO. The information required by this item is incorporated herein by
reference to the material under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION in the APCo 1995 Annual Report
(for the fiscal year ended December 31, 1995).
CSPCO. Omitted pursuant to Instruction J(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction J(2)(a) is incorporated herein by reference to the material under
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS in the CSPCo 1995
Annual Report (for the fiscal year ended December 31, 1995).
I&M. The information required by this item is incorporated herein by
reference to the material under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION in the I&M 1995 Annual Report
(for the fiscal year ended December 31, 1995).
KEPCO. Omitted pursuant to Instruction J(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction J(2)(a) is incorporated herein by reference to the material under
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS in the KEPCo 1995
Annual Report (for the fiscal year ended December 31, 1995).
OPCO. The information required by this item is incorporated herein by
reference to the material under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION in the OPCo 1995 Annual Report
(for the fiscal year ended December 31, 1995).
Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
AEGCO. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
AEP. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
APCO. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
CSPCO. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
I&M. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
KEPCO. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
OPCO. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
Item 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
AEGCO, AEP, APCO, CSPCO, I&M, KEPCO AND OPCO. None.
<PAGE>
PART III
Item 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
AEGCO. Omitted pursuant to Instruction J(2)(c).
AEP. The information required by this item is incorporated herein by
reference to the material under NOMINEES FOR DIRECTOR and SHARE OWNERSHIP OF
DIRECTORS AND EXECUTIVE OFFICERS of the definitive proxy statement of AEP,
dated March 9, 1996, for the 1996 annual meeting of shareholders. Reference
also is made to the information under the caption EXECUTIVE OFFICERS OF THE
REGISTRANTS in Part I of this report.
APCO. The information required by this item is incorporated herein by
reference to the material under ELECTION OF DIRECTORS of the definitive
information statement of APCo for the 1996 annual meeting of stockholders,
to be filed within 120 days after December 31, 1995. Reference also is made
to the information under the caption EXECUTIVE OFFICERS OF THE REGISTRANTS
in Part I of this report.
CSPCO. Omitted pursuant to Instruction J(2)(c).
I&M. The names of the directors and executive officers of I&M, the
positions they hold with I&M, their ages as of March 15, 1996, and a brief
account of their business experience during the past five years appear below.
The directors and executive officers of I&M are elected annually to serve a
one-year term.
<TABLE>
<CAPTION>
NAME AGE POSITION (A)(B)(C) PERIOD
<S> <C> <C> <C>
E. Linn Draper, Jr. 54 Director 1992-Present
Chairman of the Board and Chief Executive
Officer 1993-Present
Vice President 1992-1993
Chairman of the Board, President and Chief
Executive Officer of AEP and of the Service
Corporation 1993-Present
President of AEP 1992-1993
President and Chief Operating Officer of the
Service Corporation 1992-1993
Chairman of the Board, President and Chief
Executive Officer of Gulf States Utilities
Company 1987-1992
Peter J. DeMaria 61 Director 1992-Present
Vice President 1991-Present
Controller 1995-Present
Treasurer 1978-1995
Controller of AEP 1995-Present
Treasurer of AEP 1978-1995
Executive Vice President-Administration and
Chief Accounting Officer of the Service
Corporation 1984-Present
Treasurer of the Service Corporation 1989-1990
William N. D'Onofrio 48 Director 1984-Present
Vice President 1984-1995
Director-Regions of the Service Corporation 1996-Present
William J. Lhota 56 Director 1989-Present
President and Chief Operating Officer 1996-Present
Vice President 1989-1995
Executive Vice President of the Service
Corporation 1993-Present
Executive Vice President-Operations of the
Service Corporation 1989-1993
Gerald P. Maloney 63 Director 1978-Present
Vice President 1970-Present
Vice President of AEP 1974-Present
Secretary of AEP 1994-Present
Executive Vice President-Chief Financial
Officer of the Service Corporation 1991-Present
Senior Vice President-Finance of the Service
Corporation 1974-1990
James J. Markowsky 51 Director 1995-Present
Vice President 1993-Present
Executive Vice President-Power Generation
of the Service Corporation 1996-Present
Executive Vice President-Engineering &
Construction of the Service Corporation 1993-1996
Senior Vice President and Chief Engineer
of the Service Corporation 1988-1993
A. H. Potter 48 Director 1994-Present
Transmission and Distribution Director 1987-Present
D. M. Trenary 59 Director 1994-Present
Indiana Region Manager 1994-Present
Division Manager 1989-1994
W. E. Walters 48 Director 1991-Present
Michiana Region Manager 1994-Present
Executive Assistant to President 1987-1994
C. R. Boyle, III 48 Director and Vice President 1996-Present
President and Chief Operating Officer of KEPCo1990-1995
G. A. Clark 44 Director 1995-Present
Governmental Affairs Manager 1996-Present
General Counsel 1994-1995
General Attorney 1991-1993
D. B. Synowiec 52 Director 1995-Present
Plant Manager 1990-Present
J. H. Vipperman 55 Director and Vice President 1996-Present
Executive Vice President- Energy Delivery
of the Service Corporation 1996-Present
President and Chief Operating Officer of APCo 1990-1995
(a) Positions are with I&M unless otherwise indicated.
(b) Dr. Draper is a director of VECTRA Technologies, Inc. and Mr. Lhota is a
director of Huntington Bancshares Incorporated.
(c) Drs. Draper and Markowsky and Messrs. DeMaria, Lhota and Maloney are
directors of AEGCo, APCo, CSPCo, KEPCo and OPCo. Dr. Draper and Messrs.
DeMaria and Maloney are also directors of AEP. Mr. Vipperman is a director
of APCo, CSPCo, KEPCo and OPCo.
KEPCo. Omitted pursuant to Instruction J(2)(c).
OPCo. The information required by this item is incorporated herein by
reference to the material under the heading Election of Directors of the
definitive information statement of OPCo for the 1996 annual meeting of
shareholders, to be filed within 120 days after December 31, 1995.
Reference also is made to the information under the caption EXECUTIVE
OFFICERS OF THE REGISTRANTS in Part I of this report.
Item 11. EXECUTIVE COMPENSATION
AEGCO. Omitted pursuant to Instruction J(2)(c).
AEP. The information required by this item is incorporated herein by
reference to the material under COMPENSATION OF DIRECTORS, EXECUTIVE
COMPENSATION and the performance graph of the definitive proxy statement of
AEP, dated March 9, 1996, for the 1996 annual meeting of shareholders.
APCO. The information required by this item is incorporated herein by
reference to the material under EXECUTIVE COMPENSATION of the definitive
information statement of APCo for the 1996 annual meeting of stockholders, to
be filed within 120 days after December 31, 1995.
CSPCO. Omitted pursuant to Instruction J(2)(c).
KEPCO. Omitted pursuant to Instruction J(2)(c).
OPCO. The information required by this item is incorporated herein by
reference to the material under EXECUTIVE COMPENSATION of the definitive
information statement of OPCo for the 1996 annual meeting of shareholders, to
be filed within 120 days after December 31, 1995.
I&M. Certain executive officers of I&M are employees of the Service
Corporation. The salaries of these executive officers are paid by the
Service Corporation and a portion of their salaries has been allocated and
charged to I&M. The following table shows for 1995, 1994 and 1993 the
compensation earned from all AEP System companies by the chief executive
officer and four other most highly compensated executive officers (as
defined by regulations of the SEC) of I&M at December 31, 1995.
SUMMARY COMPENSATION TABLE
</TABLE>
<TABLE>
<CAPTION>
LONG-TERM
ANNUAL COMPENSATION COMPENSATION All Other
Salary Bonus PAYOUTS Compensation
NAME AND PRINCIPAL POSITION YEAR ($) ($)(1) LTIP PAYOUTS($)(1) ($)(2)
<S> <C> <C> <C> <C> <C>
E. LINN DRAPER, JR. - chairman of the board, 1995 685,000 236,325 334,851 30,790
president and chief executive officer of the 1994 620,000 209,436 137,362 29,385
Company and the Service Corporation; chairman 1993 538,333 148,742 18,180
and chief executive officer of other subsidiaries
PETER J. DEMARIA - Controller and director of the 1995 330,000 113,850 143,829 20,050
Company; executive vice president-administration 1994 305,000 103,029 59,032 18,750
and chief accounting officer and director of the 1993 280,000 77,364 17,811
Service Corporation; vice president, controller
and director of other subsidiaries
G. P. MALONEY - Vice president, secretary and 1995 330,000 113,850 141,582 20,060
director of the Company; executive vice president 1994 300,000 101,340 58,094 19,745
- chief financial officer and director of the 1993 269,000 74,325 18,000
Service Corporation; vice president and director
of other subsidiaries
WILLIAM J. LHOTA - Executive vice president and 1995 300,000 103,500 132,592 19,140
director of the Service Corporation; president, 1994 280,000 94,584 54,409 19,185
chief operating officer and director of other 1993 249,000 68,799 17,160
subsidiaries
JAMES J. MARKOWSKY - Executive vice president 1995 285,000 98,325 126,599 17,515
- power generation and director of the Service 1994 267,000 90,193 51,930 14,755
Corporation; vice president and director of 1993 247,000 65,259 11,165
other subsidiaries
(1)Amounts in the "Bonus" column reflect payments under the Management
Incentive Compensation Plan for performance measured for each of the years
ended December 31, 1993, 1994 and 1995. Payments are made in March of the
subsequent year. Amounts for 1995 are estimates but should not change
significantly.
Amounts in the "Long-Term Compensation" column reflect performance share
units earned under the Performance Share Incentive Plan (which became
effective January 1, 1994) for the one-year and two-year transition
performance periods ending December 31, 1994 and 1995, respectively. For
1995, their value was calculated by multiplying the $40.50 closing price of
AEP's Common Stock as reported on the New York Stock Exchange on December
29, 1995, the last trading day of fiscal year 1995, by the number of units
earned.
See below under "Long-Term Incentive Plans - Awards in 1995" and pages 13
and 14 for additional information.
(2)For 1995, includes (i) employer matching contributions under the AEP System
Employees Savings Plan: $4,500 for each of the named executive officers;
(ii) employer matching contributions under the AEP System Supplemental
Savings Plan (which became effective January 1, 1994), a non-qualified plan
designed to supplement the AEP Savings Plan: Dr. Draper, $16,050;
Mr. DeMaria, $5,400; Mr. Maloney, $5,400; Mr. Lhota, $4,500; and
Dr. Markowsky, $4,050; and (iii) subsidiary companies director fees:
Dr. Draper, $10,240; Mr. DeMaria, $10,150; Mr. Maloney, $10,160; Mr. Lhota,
$10,140; and Dr. Markowsky, $8,965.
LONG-TERM INCENTIVE PLANS - AWARDS IN 1995
Each of the awards set forth below constitutes a grant of performance share
units, which represent units equivalent to shares of Common Stock, pursuant to
the Company's Performance Share Incentive Plan. Since it is not possible to
predict future dividends and the price of AEP Common Stock, credits of
performance share units in amounts equal to the dividends that would have been
paid if the performance share units were granted in the form of shares of
Common Stock are not included in the table.
The ability to earn performance share units is tied to achieving specified
levels of total shareholder return ("TSR") relative to the S&P Electric Utility
Index. Notwithstanding AEP's TSR ranking, no performance share units are
earned unless AEP shareholders realize a positive TSR over the relevant
three-year performance period. The Human Resources Committee may, at its
discretion, reduce the number of performance share units otherwise earned.
In accordance with the performance goals established for the periods set
forth below, the threshold, target and maximum awards are equal to 25%,
100% and 200%, respectively, of the performance share units held. No
payment will be made for performance below the threshold.
Payments of earned awards are deferred in the form of restricted stock units
(equivalent to shares of AEP Common Stock) until the officer has met the
equivalent stock ownership target discussed in the Human Resources Committee
Report. Once officers meet and maintain their respective targets, they may
elect either to continue to defer or to receive further earned awards in cash
and/or Common Stock.
</TABLE>
<TABLE>
<CAPTION>
ESTIMATED FUTURE PAYOUTS OF
PERFORMANCE PERFORMANCE SHARE UNITS UNDER
NUMBER OF PERIOD UNTIL NON-STOCK PRICE-BASED PLAN
Performance Maturation Threshold Target Maximum
NAME SHARE UNITS OR PAYOUT (#) (#) (#)
<S> <C> <C> <C> <C> <C>
E. L. Draper, Jr. 8,302 1995-1997 2,075 8,302 16,604
P. J. DeMaria 3,499 1995-1997 875 3,499 6,998
G. P. Maloney 3,499 1995-1997 875 3,499 6,998
W. J. Lhota 3,181 1995-1997 795 3,181 6,362
J. J. Markowsky 3,022 1995-1997 755 3,022 6,044
</TABLE>
RETIREMENT BENEFITS
The American Electric Power System Retirement Plan provides pensions for all
employees of AEP System companies (except for employees covered by certain
collective bargaining agreements), including the executive officers of the
Company. The Retirement Plan is a noncontributory defined benefit plan.
The following table shows the approximate annual annuities under the
Retirement Plan that would be payable to employees in certain higher salary
classifications, assuming retirement at age 65 after various periods of
service.
PENSION PLAN TABLE
<TABLE>
<CAPTION>
HIGHEST AVERAGE YEARS OF ACCREDITED SERVICE
ANNUAL EARNINGS 15 20 25 30 35 40 45
<S> <C> <C> <C> <C> <C> <C> <C>
$ 300,000 $ 69,930 $ 93,240 $116,550 $139,860 $163,170 $183,120 $203,070
400,000 93,930 125,240 156,550 187,860 219,170 245,770 272,370
500,000 117,930 157,240 196,550 235,860 275,170 308,420 341,670
700,000 165,930 221,240 276,550 331,860 387,170 433,720 480,270
900,000 213,930 285,240 356,550 427,860 499,170 559,020 618,870
1,100,000 261,930 349,240 436,550 523,860 611,170 684,320 757,470
</TABLE>
The amounts shown in the table are the straight life annuities payable under
the Retirement Plan without reduction for the joint and survivor annuity.
Retirement benefits listed in the table are not subject to any deduction for
Social Security or other offset amounts. The retirement annuity is reduced 3%
per year in the case of retirement between ages 60 and 62 and further reduced
6% per year in the case of retirement between ages 55 and 60. If an employee
retires after age 62, there is no reduction in the retirement annuity.
The Company maintains a supplemental retirement plan which provides for the
payment of benefits that are not payable under the Retirement Plan due
primarily to limitations imposed by Federal tax law on benefits paid by
qualified plans. The table includes supplemental retirement benefits.
Compensation upon which retirement benefits are based, for the executive
officers named in the Summary Compensation Table above, consists of the average
of the 36 consecutive months of the officer's highest aggregate salary and
Management Incentive Compensation Plan awards, shown in the "Salary" and
"Bonus" columns, respectively, of the Summary Compensation Table, out of the
officer's most recent 10 years of service. As of December 31, 1995, the number
of full years of service applicable for retirement benefit calculation purposes
for such officers were as follows: Dr. Draper, three years; Mr. DeMaria,
36 years; Mr. Maloney, 40 years; Mr. Lhota, 31 years; and Dr. Markowsky,
24 years.
Dr. Draper's employment agreement described below provides him with a
supplemental retirement annuity that credits him with 24 years of service in
addition to his years of service credited under the Retirement Plan less his
actual pension entitlement under the Retirement Plan and any pension
entitlement from the Gulf States Utilities Company Trusteed Retirement Plan, a
plan sponsored by his prior employer.
The Company will pay supplemental retirement benefits to 19 AEP System
employees (including Messrs. DeMaria, Maloney and Lhota and Dr. Markowsky)
whose pensions may be adversely affected by amendments to the Retirement Plan
made as a result of the Tax Reform Act of 1986. Such payments, if any, will be
equal to any reduction occurring because of such amendments. Assuming
retirement in 1996 of the executive officers named in the Summary
Compensation Table, only Mr. Maloney would be affected and his annual
supplemental benefit would be $972.
The Company made available a voluntary deferred-compensation program in 1982
and 1986, which permitted certain members of AEP System management to defer
receipt of a portion of their salaries. Under this program, a participant was
able to defer up to 10% or 15% annually (depending on the terms of the program
offered), over a four-year period, of his or her salary, and receive
supplemental retirement or survivor benefit payments over a 15-year period.
The amount of supplemental retirement payments received is dependent upon the
amount deferred, age at the time the deferral election was made, and number of
years until the participant retires. The following table sets forth, for the
executive officers named in the Summary Compensation Table, the amounts of
annual deferrals and, assuming retirement at age 65, annual supplemental
retirement payments under the 1982 and 1986 programs.
<TABLE>
<CAPTION>
1982 PROGRAM 1986 PROGRAM
Annual Amount of Annual Amount of
Annual Supplemental Annual Supplemental
Amount Retirement Amount Retirement
Deferred Payment Deferred Payment
NAME (4-YEAR PERIOD) (15-YEAR PERIOD) (4-YEAR PERIOD) (15-YEAR PERIOD)
<S> <C> <C> <C> <C>
P. J. DeMaria $10,000 $52,000 $13,000 $53,300
G. P. Maloney 15,000 67,500 16,000 56,400
</TABLE>
EMPLOYMENT AGREEMENT
Dr. Draper has a contract with the Company and AEP Service Corporation which
provides for his employment for an initial term from no later than March 15,
1992 until March 15, 1997. Dr. Draper commenced his employment with the
Company and AEP Service Corporation on March 1, 1992. The Company or AEP
Service Corporation may terminate the contract at any time and, if this is done
for reasons other than cause and other than as a result of Dr. Draper's death
or permanent disability, AEP Service Corporation must pay Dr. Draper's then
base salary through March 15, 1997, less any amounts received by Dr. Draper
from other employment.
Directors of I&M receive a fee of $100 for each meeting of the Board of
Directors attended in addition to their salaries.
The AEP System is an integrated electric utility system and, as a result,
the member companies of the AEP System have contractual, financial and other
business relationships with the other member companies, such as participation
in the AEP System savings and retirement plans and tax returns, sales of
electricity, transportation and handling of fuel, sales or rentals of property
and interest or dividend payments on the securities held by the companies'
respective parents.
<PAGE>
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AEGCO. Omitted pursuant to Instruction J(2)(c).
AEP. The information required by this item is incorporated herein by
reference to the material under Share Ownership of Directors and Executive
Officers of the definitive proxy statement of AEP, dated March 9, 1996, for
the 1996 annual meeting of shareholders.
APCO. The information required by this item is incorporated herein by
reference to the material under Share Ownership of Directors and Executive
Officers in the definitive information statement of APCo for the 1995 annual
meeting of stockholders, to be filed within 120 days after December 31, 1995.
CSPCO. Omitted pursuant to Instruction J(2)(c).
I&M. All 1,400,000 outstanding shares of Common Stock, no par value, of
I&M are directly and beneficially held by AEP. Holders of the Cumulative
Preferred Stock of I&M generally have no voting rights, except with respect
to certain corporate actions and in the event of certain defaults in the
payment of dividends on such shares.
The table below shows the number of shares of AEP Common Stock and stock-
based units that were beneficially owned, directly or indirectly, as of January
1, 1996, by each director and nominee of I&M and each of the executive officers
of I&M named in the summary compensation table, and by all directors and
executive officers of I&M as a group. It is based on information provided to
I&M by such persons. No such person owns any shares of any series of the
Cumulative Preferred Stock of I&M. Unless otherwise noted, each person has
sole voting power and investment power over the number of shares of AEP Common
Stock and stock-based units set forth opposite his name. Fractions of shares
and units have been rounded to the nearest whole number.
<TABLE>
<CAPTION>
STOCK
NAME SHARES UNITS(a) TOTAL
<S> <C> <C> <C>
Coulter R. Boyle, III 3,470(b) 629 4,099
Gregory A. Clark 833(b) 327 1,160
Peter J. DeMaria 7,356(b)(c)(d)(e)(f) 5,391 12,747
William N. D'Onofrio 4,154(b)(e) 492 4,646
E. Linn Draper, Jr. 6,119(b)(e) 11,984 18,103
William J. Lhota 13,064(b)(d)(e) 4,944 18,008
Gerald P. Maloney 5,227(b)(d)(e) 5,306 10,533
James J. Markowsky 6,631(b)(f) 4,714 11,345
Albert H. Potter 3,084(b)(e) - 3,084
David B. Synowiec 2,214(b) 398 2,612
Dale M. Trenary 64(b) 412 476
Joseph H. Vipperman 5,092(b)(e) 3,365 8,457
William E. Walters 4,738(b) 278 5,016
All Directors and Executive
Officers 147,277(d)(g) 38,240 185,517
</TABLE>
(a)This column includes amounts deferred in stock units and held under the
Management Incentive Compensation Plan and Performance Share Incentive Plan.
(b)Includes shares and share equivalents held in the following plans in the
amounts listed below:
<TABLE>
<CAPTION>
AEP EMPLOYEE STOCK AEP PERFORMANCE AEP EMPLOYEES SAVINGS
OWNERSHIP PLAN (SHARES) SHARE INCENTIVE PLAN (SHARES)PLAN (SHARE EQUIVALENTS)
<S> <C> <C> <C>
Mr. Boyle 47 316 3,107
Mr. Clark 8 - 825
Mr. DeMaria 83 944 2,705
Mr. D'Onofrio 59 - 3,595
Dr. Draper - 2,196 1,958
Mr. Lhota 60 812 10,824
Mr. Maloney 85 867 2,775
Dr. Markowsky 66 830 5,718
Mr. Potter 41 - 3,029
Mr. Synowiec 53 - 2,161
Mr. Trenary 41 - 23
Mr. Vipperman 80 564 4,391
Mr. Walters 45 - 4,693
All Directors and Executive Officers 668 6,529 45,804
</TABLE>
With respect to the shares and share equivalents held in these plans, such
persons have sole voting power, but the investment/disposition power is
subject to the terms of such plans.
(c)Mr. DeMaria owns 100 shares of Cumulative Preferred Shares 9.50% Series,
$100 par value, of Columbus Southern Power Company.
(d)Does not include, for Messrs. DeMaria, Lhota and Maloney, 85,231 shares in
the American Electric Power System Educational Trust Fund over which
Messrs. DeMaria, Lhota and Maloney share voting and investment power as
trustees (they disclaim beneficial ownership). The amount of shares shown
for all directors and executive officers as a group includes these shares.
(e)Includes the following numbers of shares held in joint tenancy with a family
member: Mr. DeMaria, 1,232; Mr. D'Onofrio, 500; Dr. Draper, 1,965;
Mr. Lhota, 1,368; Mr. Maloney, 1,500; Mr. Potter, 14; and Mr. Vipperman, 57.
(f)Includes the following numbers of shares held by family members over which
beneficial ownership is disclaimed: Mr. DeMaria, 2,392; and Dr. Markowsky,
17.
(g)Represents less than 1% of the total number of shares outstanding.
KEPCO. Omitted pursuant to Instruction J(2)(c).
OPCO. The information required by this item is incorporated herein by
reference to the material under Share Ownership of Directors and Executive
Officers in the definitive information statement of OPCo for the 1996 annual
meeting of shareholders, to be filed within 120 days after December 31, 1995.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
AEP. The information required by this item is incorporated herein by
reference to the material under Transactions With Management of the definitive
proxy statement of AEP, dated March 9, 1996, for the 1996 annual meeting of
shareholders.
APCO, I&M AND OPCO. None.
AEGCO, CSPCO, AND KEPCO. Omitted pursuant to Instruction J(2)(c).
<PAGE>
PART IV
Item 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)The following documents are filed as a part of this report:
1.FINANCIAL STATEMENTS:
The following financial statements have been incorporated herein by reference
pursuant to Item 8.
AEGCo:
Independent Auditors' Report; Statements of Income for the years ended
December 31, 1995, 1994 and 1993; Statements of Retained Earnings for
the years ended December 31, 1995, 1994 and 1993; Statements of Cash
Flows for the years ended December 31, 1995, 1994 and 1993; Balance
Sheets as of December 31, 1995 and 1994; Notes to Financial Statements.
AEP and its subsidiaries consolidated:
Consolidated Statements of Income for the years ended December 31, 1995,
1994 and 1993; Consolidated Statements of Retained Earnings for the
years ended December 31, 1995, 1994 and 1993; Consolidated Statements of
Cash Flows for the years ended December 31, 1995, 1994 and 1993;
Consolidated Balance Sheets as of December 31, 1995 and 1994; Notes to
Consolidated Financial Statements; Schedule of Consolidated Cumulative
Preferred Stocks of Subsidiaries at December 31, 1995 and 1994; Schedule
of Consolidated Long-term Debt of Subsidiaries at December 31, 1995 and
1994; Independent Auditors' Report.
APCo:
Independent Auditors' Report; Consolidated Statements of Income for the
years ended December 31, 1995, 1995 and 1994; Consolidated Balance
Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash
Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated
Statements of Retained Earnings for the years ended December 31, 1995,
1994 and 1993; Notes to Consolidated Financial Statements.
CSPCo:
Independent Auditors' Report; Consolidated Statements of Income for the
years ended December 31, 1995, 1994 and 1993; Consolidated Balance
Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash
Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated
Statements of Retained Earnings for the years ended December 31, 1995,
1994 and 1993; Notes to Consolidated Financial Statements.
I&M:
Independent Auditors' Report; Consolidated Statements of Income for the
years ended December 31, 1995, 1994 and 1993; Consolidated Balance
Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash
Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated
Statements of Retained Earnings for the years ended December 31, 1995,
1994 and 1993; Notes to Consolidated Financial Statements.
KEPCo:
Independent Auditors' Report; Statements of Income for the years ended
December 31, 1995, 1994 and 1993; Statements of Retained Earnings for
the years ended December 31, 1995, 1994 and 1993; Balance Sheets as of
December 31, 1995 and 1994; Statements of Cash Flows for the years ended
December 31, 1995, 1994 and 1993; Notes to Financial Statements.
OPCo:
Independent Auditors' Report; Consolidated Statements of Income for the
years ended December 31, 1995, 1994 and 1993; Consolidated Balance
Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash
Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated
Statements of Retained Earnings for the years ended December 31, 1995,
1994 and 1993; Notes to Consolidated Financial Statements.
2.FINANCIAL STATEMENT SCHEDULES:
Financial Statement Schedules are listed in the Index to Financial
Statement Schedules (Certain schedules have been omitted because the
required information is contained in the notes to financial statements
or because such schedules are not required or are not applicable.) S-1
Independent Auditors' Report S-2
3.EXHIBITS:
Exhibits for AEGCo, AEP, APCo, CSPCo, I&M, KEPCo and OPCo are listed
in the Exhibit Index and are incorporated herein by reference E-1
(b) No Reports on Form 8-K were filed during the quarter ended December 31,
1995.
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
AEP GENERATING COMPANY
BY: /S/ G. P. MALONEY
(G. P. MALONEY, VICE
PRESIDENT)
Date: March 25, 1996
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
<S> <C> <C>
(i) Principal Executive Officer:
*E. LINN DRAPER, JR. President,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/S/ G. P. MALONEY Vice President March 25, 1996
(G. P. MALONEY) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ P. J. DEMARIA Vice President,
(P. J. DEMARIA) Controller March 25, 1996
and Director
(IV) A MAJORITY OF THE DIRECTORS:
*HENRY FAYNE
*JOHN R. JONES, III
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*By: /S/ G. P. MALONEY March 25, 1996
(G. P. MALONEY, ATTORNEY-IN-FACT)
</TABLE>
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
AMERICAN ELECTRIC POWER COMPANY, INC.
BY: /S/ G. P. MALONEY
(G. P. MALONEY, VICE
PRESIDENT)
Date: March 25, 1996
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
<S> <C> <C>
(i) Principal Executive Officer:
*E. LINN DRAPER, JR. Chairman of the Board,
President,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/S/ G. P. MALONEY Vice President, March 25, 1996
(G. P. MALONEY) Secretary and
Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ P. J. DEMAA Controller and Director March 25, 1996
(P. J. DEMARIA)
(IV) A MAJORITY OF THE DIRECTORS:
*ROBERT M. DUNCAN
*ROBERT W. FRI
*ARTHUR G. HANSEN
*LESTER A. HUDSON, JR.
*ANGUS E. PEYTON
*TOY F. REID
*DONALD G. SMITH
*LINDA GILLESPIE STUNTZ
*MORRIS TANENBAUM
*ANN HAYMOND ZWINGER
*By: /S/ G. P. MALONEY March 25, 1996
(G. P. MALONEY, ATTORNEY-IN-FACT)
</TABLE>
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
APPALACHIAN POWER COMPANY
BY: /S/ G. P. MALONEY
(G. P. MALONEY, VICE
PRESIDENT)
Date: March 25, 1996
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
<S> <C> <C>
(i) Principal Executive Officer:
*E. LINN DRAPER, JR. Chairman of the Board,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/S/ G. P. MALONEY Vice President March 25, 1996
(G. P. MALONEY) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ P. J. DEMARIA Vice President, March 25, 1996
(P. J. DEMARIA) Controller
and Director
(IV) A MAJORITY OF THE DIRECTORS:
*HENRY FAYNE
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*J. H. VIPPERMAN
*By: /S/ G. P. MALONEY March 25, 1996
(G. P. MALONEY, ATTORNEY-IN-FACT)
</TABLE>
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
COLUMBUS SOUTHERN POWER COMPANY
BY: /S/ G. P. MALONEY
(G. P. MALONEY, VICE
PRESIDENT)
Date: March 25, 1996
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
<S> <C> <C>
(i) Principal Executive Officer:
*E. LINN DRAPER, JR. Chairman of the Board,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/S/ G. P. MALONEY Vice President March 25, 1996
(G. P. MALONEY) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ P. J. DEMARIA Vice President, ControllerMarch 25, 1996
(P. J. DEMARIA) Controller
and Director
(IV) A MAJORITY OF THE DIRECTORS:
*HENRY FAYNE
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*J. H. VIPPERMAN
*By: /S/ G. P. MALONEY March 25, 1996
(G. P. MALONEY, ATTORNEY-IN-FACT)
</TABLE>
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
INDIANA MICHIGAN POWER COMPANY
BY: /S/ G. P. MALONEY
(G. P. MALONEY, VICE
PRESIDENT)
Date: March 25, 1996
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
<S> <C> <C>
(i) Principal Executive Officer:
*E. LINN DRAPER, JR. Chairman of the Board,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/S/ G. P. MALONEY Vice President March 25, 1996
(G. P. MALONEY) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ P. J. DEMARIA Vice President, March 25, 1996
(P. J. DEMARIA) Controller
and Director
(IV) A MAJORITY OF THE DIRECTORS:
*C. R. BOYLE, III
*G. A. CLARK
*W. N. D'ONOFRIO
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*A. H. POTTER
*D. B. SYNOWIEC
*D. M. TRENARY
*J. H. VIPPERMAN
*W. E. WALTERS
*By: /S/ G. P. MALONEY March 25, 1996
(G. P. MALONEY, ATTORNEY-IN-FACT)
</TABLE>
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
KENTUCKY POWER COMPANY
BY: /S/ G. P. MALONEY
(G. P. MALONEY, VICE
PRESIDENT)
Date: March 25, 1996
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
<S> <C> <C>
(i) Principal Executive Officer:
*E. LINN DRAPER, JR. Chairman of the Board,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/S/ G. P. MALONEY Vice President March 25, 1996
(G. P. MALONEY) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ P. J. DEMARIA Vice President, March 25, 1996
(P. J. DEMARIA) Controller
and Director
(IV) A MAJORITY OF THE DIRECTORS:
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*J. H. VIPPERMAN
*By: /S/ G. P. MALONEY March 25, 1996
(G. P. MALONEY, ATTORNEY-IN-FACT)
</TABLE>
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
OHIO POWER COMPANY
BY: /S/ G. P. MALONEY
(G. P. MALONEY, VICE
PRESIDENT)
Date: March 25, 1996
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
<S> <C> <C>
(i) Principal Executive Officer:
*E. LINN DRAPER, JR. Chairman of the Board,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/S/ G. P. MALONEY Vice President March 25, 1996
(G. P. MALONEY) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/S/ P. J. DEMARIA Vice President, March 25, 1996
(P. J. DEMARIA) Controller
and Director
(IV) A MAJORITY OF THE DIRECTORS:
*HENRY FAYNE
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*J. H. VIPPERMAN
*By: /S/ G. P. MALONEY March 25, 1996
(G. P. MALONEY, ATTORNEY-IN-FACT)
</TABLE>
<PAGE>
INDEX TO FINANCIAL STATEMENT SCHEDULES
PAGE
INDEPENDENT AUDITORS' REPORT S-2
The following financial statement schedules for the years ended
December 31, 1995, 1994 and 1993 are included in this report on
the pages indicated.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule II- Valuation and Qualifying Accounts and Reserves S-3
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Schedule II- Valuation and Qualifying Accounts and Reserves S-3
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Schedule II- Valuation and Qualifying Accounts and Reserves S-3
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Schedule II- Valuation and Qualifying Accounts and Reserves S-4
KENTUCKY POWER COMPANY
Schedule II- Valuation and Qualifying Accounts and Reserves S-4
OHIO POWER COMPANY AND SUBSIDIARIES
Schedule II- Valuation and Qualifying Accounts and Reserves S-4
<PAGE>
INDEPENDENT AUDITORS' REPORT
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARIES:
We have audited the consolidated financial statements of American Electric
Power Company, Inc. and its subsidiaries and the financial statements of
certain of its subsidiaries, listed in Item 14 herein, as of December 31, 1995
and 1994, and for each of the three years in the period ended December 31,
1995, and have issued our reports thereon dated February 27, 1996; such
financial statements and reports are included in your respective 1995 Annual
Report and are incorporated herein by reference. Our audits also included the
financial statement schedules of American Electric Power Company, Inc. and its
subsidiaries and of certain of its subsidiaries, listed in Item 14. These
financial statement schedules are the responsibility of the respective
Company's management. Our responsibility is to express an opinion based on our
audits. In our opinion, such financial statement schedules, when considered in
relation to the corresponding basic financial statements taken as a whole,
present fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 27, 1996
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts Deductions Period
<S> <C> <C> <C> <C> <C>
(in thousands)
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1995 $4,056 $12,907 $ 5,927(a) $17,460(b) $5,430
Year Ended December 31, 1994 $4,048 $20,265 $(3,556)(a) $16,701(b) $4,056
Year Ended December 31, 1993 $7,287 $14,237 $ 4,163(a) $21,639(b) $4,048
</TABLE>
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts Deductions Period
<S> <C> <C> <C> <C> <C>
(in thousands)
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1995 $ 830 $ 3,442 $ 963 (a) $ 2,982(b) $2,253
Year Ended December 31, 1994 $1,344 $ 2,297 $ 596 (a) $ 3,407(b) $ 830
Year Ended December 31, 1993 $ 724 $ 3,392 $ 627 (a) $ 3,399(b) $1,344
</TABLE>
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts Deductions Period
<S> <C> <C> <C> <C> <C>
(in thousands)
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1995 $1,768 $ 4,873 $ 3,531(a) $ 9,111(b) $1,061
Year Ended December 31, 1994 $ 991 $ 6,181 $ 2,778(a) $ 8,182(b) $1,768
Year Ended December 31, 1993 $1,332 $ 4,167 $ 2,106(a) $ 6,614(b) $ 991
</TABLE>
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts Deductions Period
<S> <C> <C> <C> <C> <C>
(in thousands)
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1995 $ 121 $ 1,506 $ 632(a) $ 1,925(b) $ 334
Year Ended December 31, 1994 $ 504 $ 774 $ 707(a) $ 1,864(b) $ 121
Year Ended December 31, 1993 $ 562 $ 1,380 $ 624(a) $ 2,062(b) $ 504
</TABLE>
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
<TABLE>
<CAPTION>
KENTUCKY POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts Deductions Period
<S> <C> <C> <C> <C> <C>
(in thousands)
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1995 $ 260 $ 925 $ 234(a) $ 1,160(b) $ 259
Year Ended December 31, 1994 $ 208 $ 600 $ 84(a) $ 632(b) $ 260
Year Ended December 31, 1993 $ 248 $ 390 $ 179(a) $ 609(b) $ 208
</TABLE>
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
OHIO POWER COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts Deductions Period
<S> <C> <C> <C> <C> <C>
(in thousands)
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1995 $1,019 $ 1,952 $ 472(a) $ 2,019(b) $1,424
Year Ended December 31, 1994 $ 960 $10,087 $(7,785)(a) $ 2,243(b) $1,019
Year Ended December 31, 1993 $4,353 $ 4,812 $ 549(a) $ 8,754(b) $960
</TABLE>
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
<PAGE>
EXHIBIT INDEX
Certain of the following exhibits, designated with an asterisk(*), are
filed herewith. The exhibits not so designated have heretofore been filed with
the Commission and, pursuant to 17 C.F.R. <section>229.10(d) and
<section>240.12b-32, are incorporated herein by reference to the documents
indicated in brackets following the descriptions of such exhibits. Exhibits,
designated with a dagger (<dagger>), are management contracts or compensatory
plans or arrangements required to be filed as an exhibit to this form pursuant
to Item 14(c) of this report.
EXHIBIT NUMBER DESCRIPTION
AEGCO
3(a) - Copy of Articles of Incorporation of AEGCo [Registration Statement
on Form 10 for the Common Shares of AEGCo, File No. 0-18135,
Exhibit 3(a)].
3(b) - Copy of the Code of Regulations of AEGCo [Registration Statement
on Form 10 for the Common Shares of AEGCo, File No. 0-18135,
Exhibit 3(b)].
10(a) - Copy of Capital Funds Agreement dated as of December 30, 1988
between AEGCo and AEP [Registration Statement No. 33-32752,
Exhibit 28(a)].
10(b)(1) - Copy of Unit Power Agreement dated as of March 31, 1982 between
AEGCo and I&M, as amended [Registration Statement No. 33-32752,
Exhibits 28(b)(1)(A) and 28(b)(1)(B)].
10(b)(2) - Copy of Unit Power Agreement, dated as of August 1, 1984, among
AEGCo, I&M and KEPCo [Registration Statement No. 33-32752, Exhibit
28(b)(2)].
10(b)(3) - Copy of Agreement, dated as of October 1, 1984, among AEGCo, I&M,
APCo and Virginia Electric and Power Company [Registration
Statement No. 33-32752, Exhibit 28(b)(3)].
10(c) - Copy of Lease Agreements, dated as of December 1, 1989, between
AEGCo and Wilmington Trust Company, as amended [Registration
Statement No. 33-32752, Exhibits 28(c)(1)(C), 28(c)(2)(C),
28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and 28(c)(6)(C); Annual
Report on Form 10-K of AEGCo for the fiscal year ended December
31, 1993, File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B),
10(c)(3)(B), 10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B)].
*13 - Copy of those portions of the AEGCo 1995 Annual Report (for the
fiscal year ended December 31, 1995) which are incorporated by
reference in this filing.
*24 - Power of Attorney.
*27 - Financial Data Schedules.
AEP<double-dagger>
3(a) - Copy of Restated Certificate of Incorporation of AEP, dated April
26, 1978 [Registration Statement No. 2-62778, Exhibit 2(a)].
3(b)(1) - Copy of Certificate of Amendment of the Restated Certificate of
Incorporation of AEP, dated April 23, 1980 [Registration Statement
No. 33-1052, Exhibit 4(b)].
3(b)(2) - Copy of Certificate of Amendment of the Restated Certificate of
Incorporation of AEP, dated April 28, 1982 [Registration Statement
No. 33-1052, Exhibit 4(c)].
3(b)(3) - Copy of Certificate of Amendment of the Restated Certificate of
Incorporation of AEP, dated April 25, 1984 [Registration Statement
No. 33-1052, Exhibit 4(d)].
3(b)(4) - Copy of Certificate of Change of the Restated Certificate of
Incorporation of AEP, dated July 5, 1984 [Registration Statement
No. 33-1052, Exhibit 4(e)].
3(b)(5) - Copy of Certificate of Amendment of the Restated Certificate of
Incorporation of AEP, dated April 27, 1988 [Registration Statement
No. 33-1052, Exhibit 4(f)].
3(c) - Composite copy of the Restated Certificate of Incorporation of
AEP, as amended [Registration Statement No. 33-1052, Exhibit
4(g)].
3(d) - Copy of By-Laws of AEP, as amended through July 26, 1989 [Annual
Report on Form 10-K of AEP for the fiscal year ended December 31,
1989, File No. 1-3525, Exhibit 3(d)].
10(a) - Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo,
KEPCo, OPCo and I&M and with the Service Corporation, as amended
[Registration Statement No. 2-52910, Exhibit 5(a); Registration
Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-
K of AEP for the fiscal year ended December 31, 1990, File No. 1-
3525, Exhibit 10(a)(3)].
10(b) - Copy of Transmission Agreement, dated April 1, 1984, among APCo,
CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent,
as amended [Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and
Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
AEP<double-dagger> (continued)
EXHIBIT NUMBER DESCRIPTION
<dagger>10(c)(1)-AEP Deferred Compensation Agreement for certain executive
officers [Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1985, File No. 1-3525, Exhibit 10(e)].
<dagger>10(c)(2)-Amendment to AEP Deferred Compensation Agreement for certain
executive officers [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1986, File No. 1-3525, Exhibit
10(d)(2)].
<dagger>10(d)-AEP Deferred Compensation Agreement for directors, as amended,
effective October 24, 1984 [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1984, File No. 1-3525, Exhibit
10(e)].
<dagger>10(e)-AEP Accident Coverage Insurance Plan for directors [Annual
Report on Form 10-K of AEP for the fiscal year ended December 31,
1985, File No. 1-3525, Exhibit 10(g)].
<dagger>10(f)-AEP Retirement Plan for directors [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 1986, File No. 1-3525,
Exhibit 10(g)].
*<dagger>10(g)(1)(A)-AEP Excess Benefit Plan, as amended through January 4,
1996.
<dagger>10(g)(1)(B)-Guaranty by AEP of the Service Corporation Excess Benefits
Plan [Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1990, File No. 1-3525, Exhibit 10(h)(1)(B)].
<dagger>10(g)(2)-AEP System Supplemental Savings Plan (Non-Qualified) [Annual
Report on Form 10-K of AEP for the fiscal year ended December 31,
1993, File No. 1-3525, Exhibit 10(g)(2)].
<dagger>10(g)(3)-Service Corporation Umbrella Trust<trademark> for Executives
[Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)].
<dagger>10(h)(1)-Employment Agreement between E. Linn Draper, Jr. and AEP and
the Service Corporation [Annual Report on Form 10-K of AEGCo for
the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit
10(g)(3)].
*<dagger>10(i)(1)-AEP Management Incentive Compensation Plan.
<dagger>10(i)(2)-American Electric Power System Performance Share Incentive
Plan, as Amended and Restated through October 1, 1995 [Quarterly
Report on Form 10-Q of AEP for the quarterly period ended
September 30, 1995, File No. 1-3525, Exhibit 10].
10(j) - Copy of Lease Agreements, dated as of December 1, 1989, between
AEGCo or I&M and Wilmington Trust Company, as amended
[Registration Statement No. 33-32752, Exhibits 28(c)(1)(C),
28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and
28(c)(6)(C); Registration Statement No. 33-32753, Exhibits
28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C)
and 28(a)(6)(C); and Annual Report on Form 10-K of AEGCo for the
fiscal year ended December 31, 1993, File No. 0-18135, Exhibits
10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B), 10(c)(5)(B)
and 10(c)(6)(B); Annual Report on Form 10-K of I&M for the fiscal
year ended December 31, 1993, File No. 1-3570, Exhibits
10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B)
and 10(e)(6)(B)].
10(k)(1) - Copy of Agreement for Lease, dated as of September 17, 1992,
between JMG Funding, Limited Partnership and OPCo [Annual Report
on Form 10-K of OPCo for the fiscal year ended December 31, 1992,
File No. 1-6543, Exhibit 10(l)].
10(k)(2) - Lease Agreement between Ohio Power Company and JMG Funding,
Limited, dated January 20, 1995 [Annual Report on Form 10-K of
OPCo for the fiscal year ended December 31, 1994, File No. 1-6543,
Exhibit 10(l)(2)].
10(l) - Interim Allowance Agreement, dated July 28, 1994, among APCo,
CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report
on Form 10-K of APCo for the fiscal year ended December 31, 1994,
File No. 1-3457, Exhibit 10(d)].
*13 - Copy of those portions of the AEP 1995 Annual Report (for the
fiscal year ended December 31, 1995) which are incorporated by
reference in this filing.
*21 - List of subsidiaries of AEP.
*23 - Consent of Deloitte & Touche LLP.
*24 - Power of Attorney.
*27 - Financial Data Schedules.
APCO<double-dagger>
EXHIBIT NUMBER DESCRIPTION
3(a) - Copy of Restated Articles of Incorporation of APCo, and amendments
thereto to November 4, 1993 [Registration Statement No. 33-50163,
Exhibit 4(a); Registration Statement No. 33-53805, Exhibits 4(b)
and 4(c)].
3(b) - Copy of Articles of Amendment to the Restated Articles of
Incorporation of APCo, dated June 6, 1994 [Annual Report on Form
10-K of APCo for the fiscal year ended December 31, 1994, File No.
1-3457, Exhibit 3(b)].
3(c) - Composite copy of the Restated Articles of Incorporation of APCo,
as amended [Annual Report on Form 10-K of APCo for the fiscal year
ended December 31, 1994, File No. 1-3457, Exhibit 3(c)].
*3(d) - Copy of By-Laws of APCo (amended as of January 1, 1996).
4(a) - Copy of Mortgage and Deed of Trust, dated as of December 1, 1940,
between APCo and Bankers Trust Company and R. Gregory Page, as
Trustees, as amended and supplemented [Registration Statement No.
2-7289, Exhibit 7(b); Registration Statement No. 2-19884, Exhibit
2(1); Registration Statement No. 2-24453, Exhibit 2(n);
Registration Statement No. 2-60015, Exhibits 2(b)(2), 2(b)(3),
2(b)(4), 2(b)(5), 2(b)(6), 2(b)(7), 2(b)(8), 2(b)(9), 2(b)(10),
2(b)(12), 2(b)(14), 2(b)(15), 2(b)(16), 2(b)(17), 2(b)(18),
2(b)(19), 2(b)(20), 2(b)(21), 2(b)(22), 2(b)(23), 2(b)(24),
2(b)(25), 2(b)(26), 2(b)(27) and 2(b)(28); Registration Statement
No. 2-64102, Exhibit 2(b)(29); Registration Statement No. 2-66457,
Exhibits (2)(b)(30) and 2(b)(31); Registration Statement No. 2-
69217, Exhibit 2(b)(32); Registration Statement No. 2-86237,
Exhibit 4(b); Registration Statement No. 33-11723, Exhibit 4(b);
Registration Statement No. 33-17003, Exhibit 4(a)(ii),
Registration Statement No. 33-30964, Exhibit 4(b); Registration
Statement No. 33-40720, Exhibit 4(b); Registration Statement No.
33-45219, Exhibit 4(b); Registration Statement No. 33-46128,
Exhibits 4(b) and 4(c); Registration Statement No. 33-53410,
Exhibit 4(b); Registration Statement No. 33-59834, Exhibit 4(b);
Registration Statement No. 33-50229, Exhibits 4(b) and 4(c);
Registration Statement No. 33-58431, Exhibits 4(b), 4(c), 4(d) and
4(e); Registration Statement No. 333-01049, Exhibits 4(b) and
4(c); Form 8-K, dated March 18, 1996, File No. 1-3457, Exhibit 4].
10(a)(1) - Copy of Power Agreement, dated October 15, 1952, between OVEC and
United States of America, acting by and through the United States
Atomic Energy Commission, and, subsequent to January 18, 1975, the
Administrator of the Energy Research and Development
Administration, as amended [Registration Statement No. 2-60015,
Exhibit 5(a); Registration Statement No. 2-63234, Exhibit
5(a)(1)(B); Registration Statement No. 2-66301, Exhibit
5(a)(1)(C); Registration Statement No. 2-67728, Exhibit
5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year
ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and
Annual Report on Form 10-K of APCo for the fiscal year ended
December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) - Copy of Inter-Company Power Agreement, dated as of July 10, 1953,
among OVEC and the Sponsoring Companies, as amended [Registration
Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-
67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo
for the fiscal year ended December 31, 1992, File No. 1-3457,
Exhibit 10(a)(2)(B)].
10(a)(3) - Copy of Power Agreement, dated July 10, 1953, between OVEC and
Indiana-Kentucky Electric Corporation, as amended [Registration
Statement No. 2-60015, Exhibit 5(e)].
10(b) - Copy of Interconnection Agreement, dated July 6, 1951, among APCo,
CSPCo, KEPCo, OPCo and I&M and with the Service Corporation, as
amended [Registration Statement No. 2-52910, Exhibit 5(a);
Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on
Form 10-K of AEP for the fiscal year ended December 31, 1990, File
No. 1-3525, Exhibit 10(a)(3)].
10(c) - Copy of Transmission Agreement, dated April 1, 1984, among APCo,
CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent,
as amended [Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual
Report on Form 10-K of AEP for the fiscal year ended December 31,
1988, File No. 1-3525, Exhibit 10(b)(2)].
10(d) - Copy of AEP System Interim Allowance Agreement, dated July 28,
1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service
Corporation [Annual Report on Form 10-K of APCo for the fiscal
year ended December 31, 1994, File No. 1-3457, Exhibit 10(d)].
<dagger>10(e)(1)-AEP Deferred Compensation Agreement for certain executive
officers [Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1985, File No. 1-3525, Exhibit 10(e)].
<dagger>10(e)(2)-Amendment to AEP Deferred Compensation Agreement for certain
executive officers [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1986, File No. 1-3525, Exhibit
10(d)(2)].
APCO<double-dagger> (continued)
EXHIBIT NUMBER DESCRIPTION
<dagger>10(f)(1)-Management Incentive Compensation Plan [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1995, File No.
1-3525, Exhibit 10(i)(1)].
<dagger>10(f)(2)-American Electric Power System Performance Share Incentive
Plan [Quarterly Report on Form 10-Q of APCo for the quarterly
period ended September 30, 1995, File No. 1-3457, Exhibit 10].
<dagger>10(g)(1)-Excess Benefits Plan [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit
10(g)(1)(A)].
<dagger>10(g)(2)-AEP System Supplemental Savings Plan (Non-Qualified) [Annual
Report on Form 10-K of AEP for the fiscal year ended December 31,
1993, File No. 1-3525, Exhibit 10(g)(2)].
<dagger>10(g)(3)-Umbrella Trust<trademark> for Executives [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31, 1993, File
No. 1-3525, Exhibit 10(g)(3)].
<dagger>10(h)(1)-Employment Agreement between E. Linn Draper, Jr. and AEP and
the Service Corporation [Annual Report on Form 10-K of AEGCo for
the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit
10(g)(3)].
*12 - Statement re: Computation of Ratios.
*13 - Copy of those portions of the APCo 1995 Annual Report (for the
fiscal year ended December 31, 1995) which are incorporated by
reference in this filing.
21 - List of subsidiaries of APCo [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1995, File No. 1-3525,
Exhibit 21].
*23 - Consent of Deloitte & Touche LLP.
*24 - Power of Attorney.
*27 - Financial Data Schedules.
CSPCO<double-dagger>
3(a) - Copy of Amended Articles of Incorporation of CSPCo, as amended to
March 6, 1992 [Registration Statement No. 33-53377, Exhibit 4(a)].
3(b) - Copy of Certificate of Amendment to Amended Articles of
Incorporation of CSPCo, dated May 19, 1994 [Annual Report on Form
10-K of CSPCo for the fiscal year ended December 31, 1994, File
No. 1-2680, Exhibit 3(b)].
3(c) - Composite copy of Amended Articles of Incorporation of CSPCo, as
amended [Annual Report on Form 10-K of CSPCo for the fiscal year
ended December 31, 1994, File No. 1-2680, Exhibit 3(c)].
3(d) - Copy of Code of Regulations and By-Laws of CSPCo [Annual Report on
Form 10-K of CSPCo for the fiscal year ended December 31, 1987,
File No. 1-2680, Exhibit 3(d)].
4(a) - Copy of Indenture of Mortgage and Deed of Trust, dated September
1, 1940, between CSPCo and City Bank Farmers Trust Company (now
Citibank, N.A.), as trustee, as supplemented and amended
[Registration Statement No. 2-59411, Exhibits 2(B) and 2(C);
Registration Statement No. 2-80535, Exhibit 4(b); Registration
Statement No. 2-87091, Exhibit 4(b); Registration Statement No. 2-
93208, Exhibit 4(b); Registration Statement No. 2-97652, Exhibit
4(b); Registration Statement No. 33-7081, Exhibit 4(b);
Registration Statement No. 33-12389, Exhibit 4(b); Registration
Statement No. 33-19227, Exhibits 4(b), 4(e), 4(f), 4(g) and 4(h);
Registration Statement No. 33-35651, Exhibit 4(b); Registration
Statement No. 33-46859, Exhibits 4(b) and 4(c); Registration
Statement No. 33-50316, Exhibits 4(b) and 4(c); Registration
Statement No. 33-60336, Exhibits 4(b), 4(c) and 4(d); Registration
Statement No. 33-50447, Exhibits 4(b) and 4(c); Annual Report on
Form 10-K of CSPCo for the fiscal year ended December 31, 1993,
File No. 1-2680, Exhibit 4(b)].
10(a)(1) - Copy of Power Agreement, dated October 15, 1952, between OVEC and
United States of America, acting by and through the United States
Atomic Energy Commission, and, subsequent to January 18, 1975, the
Administrator of the Energy Research and Development
Administration, as amended [Registration Statement No. 2-60015,
Exhibit 5(a); Registration Statement No. 2-63234, Exhibit
5(a)(1)(B); Registration Statement No. 2-66301, Exhibit
5(a)(1)(C); Registration Statement No. 2-67728, Exhibit
5(a)(1)(B); Annual Report on Form 10-K of APCo for the fiscal year
ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and
Annual Report on Form 10-K of APCo for the fiscal year ended
December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) - Copy of Inter-Company Power Agreement, dated July 10, 1953, among
OVEC and the Sponsoring Companies, as amended [Registration
Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-
67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo
for the fiscal year ended December 31, 1992, File No. 1-3457,
Exhibit 10(a)(2)(B)].
<PAGE>
CSPCO<double-dagger> (continued)
EXHIBIT NUMBER DESCRIPTION
10(a)(3) - Copy of Power Agreement, dated July 10, 1953, between OVEC and
Indiana-Kentucky Electric Corporation, as amended [Registration
Statement No. 2-60015, Exhibit 5(e)].
10(b) - Copy of Interconnection Agreement, dated July 6, 1951, among APCo,
CSPCo, KEPCo, OPCo and I&M and the Service Corporation, as amended
[Registration Statement No. 2-52910, Exhibit 5(a); Registration
Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-
K of AEP for the fiscal year ended December 31, 1990, File No. 1-
3525, Exhibit 10(a)(3)].
10(c) - Copy of Transmission Agreement, dated April 1, 1984, among APCo,
CSPCo, I&M, KEPCo, OPCo, and with the Service Corporation as
agent, as amended [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1985, File No. 1-3525, Exhibit
10(b); and Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
10(d) - Copy of Interim Allowance Agreement [Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1994, File No. 1-3457,
Exhibit 10(d)].
*12 - Statement re: Computation of Ratios.
*13 - Copy of those portions of the CSPCo 1995 Annual Report (for the
fiscal year ended December 31, 1995) which are incorporated by
reference in this filing.
*23 - Consent of Deloitte & Touche LLP.
*24 - Power of Attorney.
*27 - Financial Data Schedules.
I&M<double-dagger>
3(a) - Copy of the Amended Articles of Acceptance of I&M and amendments
thereto [Annual Report on Form 10-K of I&M for fiscal year ended
December 31, 1993, File No. 1-3570, Exhibit 3(a)].
3(b) - Composite Copy of the Amended Articles of Acceptance of I&M, as
amended [Annual Report on Form 10-K of I&M for fiscal year ended
December 31, 1993, File No. 1-3570, Exhibit 3(b)].
*3(c) - Copy of the By-Laws of I&M (amended as of January 1, 1996).
4(a) - Copy of Mortgage and Deed of Trust, dated as of June 1, 1939,
between I&M and Irving Trust Company (now The Bank of New York)
and various individuals, as Trustees, as amended and supplemented
[Registration Statement No. 2-7597, Exhibit 7(a); Registration
Statement No. 2-60665, Exhibits 2(c)(2), 2(c)(3), 2(c)(4),
2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11),
2(c)(12), 2(c)(13), 2(c)(14), 2(c)(15), (2)(c)(16), and 2(c)(17);
Registration Statement No. 2-63234, Exhibit 2(b)(18); Registration
Statement No. 2-65389, Exhibit 2(a)(19); Registration Statement
No. 2-67728, Exhibit 2(b)(20); Registration Statement No. 2-85016,
Exhibit 4(b); Registration Statement No. 33-5728, Exhibit 4(c);
Registration Statement No. 33-9280, Exhibit 4(b); Registration
Statement No. 33-11230, Exhibit 4(b); Registration Statement No.
33-19620, Exhibits 4(a)(ii), 4(a)(iii), 4(a)(iv) and 4(a)(v);
Registration Statement No. 33-46851, Exhibits 4(b)(i), 4(b)(ii)
and 4(b)(iii); Registration Statement No. 33-54480, Exhibits
4(b)(i) and 4(b)(ii); Registration Statement No. 33-60886, Exhibit
4(b)(i); Registration Statement No. 33-50521, Exhibits 4(b)(i),
4(b)(ii) and 4(b)(iii); Annual Report on Form 10-K of I&M for
fiscal year ended December 31, 1993, File No. 1-3570, Exhibit
4(b); Annual Report on Form 10-K of I&M for fiscal year ended
December 31, 1994, File No. 1-3570, Exhibit 4(b)].
10(a)(1) - Copy of Power Agreement, dated October 15, 1952, between OVEC and
United States of America, acting by and through the United States
Atomic Energy Commission, and, subsequent to January 18, 1975, the
Administrator of the Energy Research and Development
Administration, as amended [Registration Statement No. 2-60015,
Exhibit 5(a); Registration Statement No. 2-63234, Exhibit
5(a)(1)(B); Registration Statement No. 2-66301, Exhibit
5(a)(1)(C); Registration Statement No. 2-67728, Exhibit
5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year
ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and
Annual Report on Form 10-K of APCo for the fiscal year ended
December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) - Copy of Inter-Company Power Agreement, dated as of July 10, 1953,
among OVEC and the Sponsoring Companies, as amended [Registration
Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-
67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for
the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit
10(a)(2)(B)].
10(a)(3) - Copy of Power Agreement, dated July 10, 1953, between OVEC and
Indiana-Kentucky Electric Corporation, as amended [Registration
Statement No. 2-60015, Exhibit 5(e)].
<PAGE>
I&M<double-dagger> (continued)
EXHIBIT NUMBER DESCRIPTION
10(b) - Copy of Interconnection Agreement, dated July 6, 1951, between
APCo, CSPCo, KEPCo, I&M, and OPCo and with the Service
Corporation, as amended [Registration Statement No. 2-52910,
Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b);
and Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].
10(c) - Copy of Transmission Agreement, dated April 1, 1984, among APCo,
CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent,
as amended [Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and
Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
10(d) - Copy of Interim Allowance Agreement [Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1994, File No. 1-3457,
Exhibit 10(d)].
10(e) - Copy of Nuclear Material Lease Agreement, dated as of December 1,
1990, between I&M and DCC Fuel Corporation [Annual Report on Form
10-K of I&M for the fiscal year ended December 31, 1993, File No.
1-3570, Exhibit 10(d)].
10(f) - Copy of Lease Agreements, dated as of December 1, 1989, between
I&M and Wilmington Trust Company, as amended [Registration
Statement No. 33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C),
28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); Annual
Report on Form 10-K of I&M for the fiscal year ended December 31,
1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B),
10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)].
*12 - Statement re: Computation of Ratios
*13 - Copy of those portions of the I&M 1995 Annual Report (for the
fiscal year ended December 31, 1995) which are incorporated by
reference in this filing.
21 - List of subsidiaries of I&M [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit
21].
*23 - Consent of Deloitte & Touche LLP.
*24 - Power of Attorney.
*27 - Financial Data Schedules.
KEPCO
3(a) - Copy of Restated Articles of Incorporation of KEPCo [Annual Report
on Form 10-K of KEPCo for the fiscal year ended December 31, 1991,
File No. 1-6858, Exhibit 3(a)].
*3(b) - Copy of By-Laws of KEPCo (amended as of January 1, 1996).
4(a) - Copy of Mortgage and Deed of Trust, dated May 1, 1949, between
KEPCo and Bankers Trust Company, as supplemented and amended
[Registration Statement No. 2-65820, Exhibits 2(b)(1), 2(b)(2),
2(b)(3), 2(b)(4), 2(b)(5), and 2(b)(6); Registration Statement
No. 33-39394, Exhibits 4(b) and 4(c); Registration Statement No.
33-53226, Exhibits 4(b) and 4(c); Registration Statement No. 33-
61808, Exhibits 4(b) and 4(c), Registration Statement No. 33-
53007, Exhibits 4(b), 4(c) and 4(d)].
10(a) - Copy of Interconnection Agreement, dated July 6, 1951, among APCo,
CSPCo, KEPCo, I&M and OPCo and with the Service Corporation, as
amended [Registration Statement No. 2-52910, Exhibit 5(a);
Registration Statement No. 2-61009, Exhibit 5(b); and Annual
Report on Form 10-K of AEP for the fiscal year ended December 31,
1990, File No. 1-3525, Exhibit 10(a)(3)].
10(b) - Copy of Transmission Agreement, dated April 1, 1984, among APCo,
CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent,
as amended [Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and
Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
10(c) - Copy of Interim Allowance Agreement [Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1994, File No. 1-3457,
Exhibit 10(d)].
*12 - Statement re: Computation of Ratios.
*13 - Copy those portions of the KEPCo 1995 Annual Report (for the
fiscal year ended December 31, 1995) which are incorporated by
reference in this filing.
*23 - Consent of Deloitte & Touche LLP.
*24 - Power of Attorney.
*27 - Financial Data Schedules.
<PAGE>
OPCO<double-dagger>
EXHIBIT NUMBER DESCRIPTION
3(a) - Copy of Amended Articles of Incorporation of OPCo, and amendments
thereto to December 31, 1993 [Registration Statement No. 33-50139,
Exhibit 4(a); Annual Report on Form 10-K of OPCo for the fiscal
year ended December 31, 1993, File No. 1-6543, Exhibit 3(b)].
3(b) - Certificate of Amendment to Amended Articles of Incorporation of
OPCo, dated May 3, 1994 [Annual Report on Form 10-K of OPCo for
the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit
3(b)].
3(c) - Composite copy of the Amended Articles of Incorporation of OPCo,
as amended [Annual Report on Form 10-K of OPCo for the fiscal year
ended December 31, 1994, File No. 1-6543, Exhibit 3(c)].
3(d) - Copy of Code of Regulations of OPCo [Annual Report on Form 10-K of
OPCo for the fiscal year ended December 31, 1990, File No. 1-6543,
Exhibit 3(d)].
4(a) - Copy of Mortgage and Deed of Trust, dated as of October 1, 1938,
between OPCo and Manufacturers Hanover Trust Company (now Chemical
Bank), as Trustee, as amended and supplemented [Registration
Statement No. 2-3828, Exhibit B-4; Registration Statement No. 2-
60721, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6),
2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13),
2(c)(14), 2(c)(15), 2(c)(16), 2(c)(17), 2(c)(18), 2(c)(19),
2(c)(20), 2(c)(21), 2(c)(22), 2(c)(23), 2(c)(24), 2(c)(25),
2(c)(26), 2(c)(27), 2(c)(28), 2(c)(29), 2(c)(30), and 2(c)(31);
Registration Statement No. 2-83591, Exhibit 4(b); Registration
Statement No. 33-21208, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(vi);
Registration Statement No. 33-31069, Exhibit 4(a)(ii);
Registration Statement No. 33-44995, Exhibit 4(a)(ii);
Registration Statement No. 33-59006, Exhibits 4(a)(ii), 4(a)(iii)
and 4(a)(iv); Registration Statement No. 33-50373, Exhibits
4(a)(ii), 4(a)(iii) and 4(a)(iv); Annual Report on Form 10-K of
OPCo for the fiscal year ended December 31, 1993, File No. 1-6543,
Exhibit 4(b)].
10(a)(1) - Copy of Power Agreement, dated October 15, 1952, between OVEC and
United States of America, acting by and through the United States
Atomic Energy Commission, and, subsequent to January 18, 1975, the
Administrator of the Energy Research and Development
Administration, as amended [Registration Statement No. 2-60015,
Exhibit 5(a); Registration Statement No. 2-63234, Exhibit
5(a)(1)(B); Registration Statement No. 2-66301, Exhibit
5(a)(1)(C); Registration Statement No. 2-67728, Exhibit
5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year
ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F);
Annual Report on Form 10-K of APCo for the fiscal year ended
December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) - Copy of Inter-Company Power Agreement, dated July 10, 1953, among
OVEC and the Sponsoring Companies, as amended [Registration
Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-
67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for
the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit
10(a)(2)(B)].
10(a)(3) - Copy of Power Agreement, dated July 10, 1953, between OVEC and
Indiana-Kentucky Electric Corporation, as amended [Registration
Statement No. 2-60015, Exhibit 5(e)].
10(b) - Copy of Interconnection Agreement, dated July 6, 1951, between
APCo, CSPCo, KEPCo, I&M and OPCo and with the Service Corporation,
as amended [Registration Statement No. 2-52910, Exhibit 5(a);
Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on
Form 10-K of AEP for the fiscal year ended December 31, 1990, File
1-3525, Exhibit 10(a)(3)].
10(c) - Copy of Transmission Agreement, dated April 1, 1984, among APCo,
CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent
[Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report
on Form 10-K of AEP for the fiscal year ended December 31, 1988,
File No. 1-3525, Exhibit 10(b)(2)].
10(d) - Copy of Interim Allowance Agreement [Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1994, File No. 1-3457,
Exhibit 10(d)].
10(e) - Copy of Agreement, dated June 18, 1968, between OPCo and Kaiser
Aluminum & Chemical Corporation (now known as Ravenswood Aluminum
Corporation) and First Supplemental Agreement thereto
[Registration Statement No. 2-31625, Exhibit 4(c); Annual Report
on Form 10-K of OPCo for the fiscal year ended December 31, 1986,
File No. 1-6543, Exhibit 10(d)(2)].
10(f) - Copy of Power Agreement, dated November 16, 1966, between OPCo and
Ormet Generating Corporation and First Supplemental Agreement
thereto [Annual Report on Form 10-K of OPCo for the fiscal year
ended December 31, 1993, File No. 1-6543, Exhibit 10(e)].
10(g) - Copy of Amendment No. 1, dated October 1, 1973, to Station
Agreement dated January 1, 1968, among OPCo, Buckeye and Cardinal
Operating Company, and amendments thereto [Annual Report
<PAGE>
OPCO<double-dagger> (continued)
EXHIBIT NUMBER DESCRIPTION
on Form 10-K of OPCo for the fiscal year ended December 31, 1993,
File No. 1-6543, Exhibit 10(f)].
<dagger>10(h)(1)-AEP Deferred Compensation Agreement for certain executive
officers [Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1985, File No. 1-3525, Exhibit 10(e)].
<dagger>10(h)(2)-Amendment to AEP Deferred Compensation Agreement for certain
executive officers [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1986, File No. 1-3525, Exhibit
10(d)(2)].
<dagger>10(i)(1)-Management Incentive Compensation Plan [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1995, File No.
1-3525, Exhibit 10(i)(1)].
<dagger>10(i)(2)-American Electric Power System Performance Share Incentive
Plan, as Amended and Restated through January 1, 1995 [Quarterly
Report on Form 10-Q of OPCo for the quarterly period ended
September 30, 1995, File No. 1-6543].
<dagger>10(j)(1)-Excess Benefits Plan [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit
10(g)(1)(A)].
<dagger>10(j)(2)-AEP System Supplemental Savings Plan (Non-Qualified) [Annual
Report on Form 10-K of AEP for the fiscal year ended December 31,
1993, File No. 1-3525, Exhibit 10(g)(2)].
<dagger>10(j)(3)-Umbrella Trust<trademark> for Executives [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31, 1993, File
No. 1-3525, Exhibit 10(g)(3)].
<dagger>10(k)(1)-Employment Agreement between E. Linn Draper, Jr. and AEP and
the Service Corporation [Annual Report on Form 10-K of AEGCo for
the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit
10(g)(2)].
10(l)(1) - Agreement for Lease dated as of September 17, 1992 between JMG
Funding, Limited Partnership and OPCo [Annual Report on Form 10-K
of OPCo for the fiscal year ended December 31, 1992, File No. 1-
6543, Exhibit 10(l)].
10(l)(2) - Lease Agreement dated January 20, 1995 between OPCo and JMG
Funding, Limited Partnership, and amendment thereto (confidential
treatment requested) [Annual Report on Form 10-K of OPCo for the
fiscal year ended December 31, 1994, File No. 1-6543, Exhibit
10(l)(2)].
*12 - Statement re: Computation of Ratios.
*13 - Copy of those portions of the OPCo 1995 Annual Report (for the
fiscal year ended December 31, 1995) which are incorporated by
reference in this filing.
21 - List of subsidiaries of OPCo [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1995, File No. 1-3525,
Exhibit 21].
*23 - Consent of Deloitte & Touche LLP.
*24 - Power of Attorney.
*27 - Financial Data Schedules.
<double-dagger>Certain instruments defining the rights of holders of long-term
debt of the registrants included in the financial statements of registrants
filed herewith have been omitted because the total amount of securities
authorized thereunder does not exceed 10% of the total assets of registrants.
The registrants hereby agree to furnish a copy of any such omitted instrument
to the SEC upon request.
Exhibit 10(g)(1)(A)
American Electric Power System
Excess Benefit Plan
As Amended through January 4, 1996
ARTICLE I
Purposes and Effective Date
Section 1.1 The American Electric Power System Excess
Benefit Plan is established to provide benefits for certain
employees in excess of the limitations on benefits imposed by
provisions of the Internal Revenue Code of 1986, as amended
from time to time.
Section 1.2 The effective date of the Excess Plan is
January 1, 1990.
ARTICLE II
Definitions
Section 2.1 "Code" shall mean the Internal Revenue Code
of 1986, as amended from time to time.
Section 2.2 "Committee" shall mean the Employee Benefits
Trust Committee established pursuant to a resolution adopted
by the American Electric Power Service Corporation Board of
Directors as in effect from time to time.
Section 2.3 "Company" shall mean American Electric Power
Service Corporation.
Section 2.4 "ERISA" shall mean the Employee Retirement
Income Security Act of 1974 as amended from time to time.
Section 2.5 "Maximum Benefit" shall mean the monthly
equivalent of the maximum benefit permitted by the Code to be
paid to a Participant or the Participant's Surviving Spouse
from the Retirement Plan.
Section 2.6 "Participant" shall mean any exempt salaried
employee of the Company, who is an active Participant in the
Retirement Plan on or after the Effective Date, whose Unre-
stricted Benefit exceeds the Maximum Benefit and who either is
an officer of the Company or has been designated and confirmed
by the Committee as eligible to participate in the Plan.
Section 2.7 "Plan" shall mean the American Electric
Power System Excess Benefit Plan, as from time to time amended
or restated.
Section 2.8 "QDRO" shall mean a qualified domestic
relations order as defined in section 414(p) of the Code or
section 206(d) of ERISA.
Section 2.9 "Retirement Plan" shall mean the American
Electric Power System Retirement Plan, as amended from time to
time.
Section 2.10 "Supplemental Retirement Benefit" shall
mean any supplemental retirement benefit payable to a Partici-
pant or a Participant's spouse pursuant to the terms of an
employment agreement entered into between the Participant and
the Company. The term Supplemental Retirement Benefit shall
not include deferred compensation payable to a Participant
pursuant to a Participant's participation in a deferred com-
pensation arrangement entered into prior to January 1, 1987 or
deferred compensation payable to the Participant pursuant to
the terms and conditions of the Management Incentive Compensa-
tion Program.
Section 2.11 "Surviving Spouse" shall mean the spouse of
a Participant who is legally married to the Participant and
whose marriage to the Participant occurred at least one year
prior to the earlier of the Participant's termination of
employment or death.
Section 2.12 "Unrestricted Benefit" shall mean either
(a) the monthly Normal, Early, or Deferred Vested retirement
benefit payable to the Participant, whichever is applicable,
or (b) the pre-retirement or post-retirement surviving
spouse's benefit payable to the Participant's Surviving
Spouse, whichever is applicable, determined under the provi-
sions of the Retirement Plan without regard to the limitations
imposed by the Code and based upon Participant earnings that,
for each plan year, are the total of: (1) the Participant's
Retirement Plan Earnings, (2) the Participant's contributions
to the American Electric Power System Supplemental Savings
Plan, and (3) for Participants who terminate employment after
December 31, 1995, Management Incentive Compensation Plan
awards earned, but not necessarily paid, in the plan year,
including MICP awards earned prior to January 1, 1996.
ARTICLE III
Benefits
Section 3.1 Upon the Normal Retirement of a Participant,
as provided under the Retirement Plan, the Participant shall
be entitled to a monthly benefit equal in amount to the Parti-
cipant's Unrestricted Benefit less the Maximum Benefit and
less any Supplemental Retirement Benefit.
Section 3.2 Upon the Early Retirement of a Participant,
as provided under the Retirement Plan, the Participant shall
be entitled to a monthly benefit equal to the Participant's
Unrestricted Benefit less the Maximum Benefit and less any
Supplemental Retirement Benefit.
Section 3.3 If a Participant terminates employment with
the Company and is entitled to a Deferred Vested Retirement
Benefit provided under the Retirement Plan, the Participant
shall be entitled to a monthly benefit equal to the Partici-
pant's Unrestricted Benefit less the Maximum Benefit and less
any Supplemental Retirement Benefit.
Section 3.4 Supplemental Retirement Benefits accrued as
of December 31, 1993 shall be vested as of December 31, 1993.
Supplemental Retirement Benefits accrued after 1993 shall vest
when the Participant terminates employment.
ARTICLE IV
Spousal Benefit
Section 4.1 Upon the death of a Participant whose spouse
is entitled to a pre-retirement or a post-retirement surviving
spouse's benefit from the Retirement Plan, the Participant's
Surviving Spouse shall be entitled to receive a monthly bene-
fit equal in amount to the Surviving Spouse's pre-retirement
or post-retirement Unrestricted Benefit less the Maximum
Benefit and less any Supplemental Retirement Benefit.
ARTICLE V
Benefit Payments
Section 5.1 Payment of retirement benefits under Article
3 or 4 shall commence at the same time Retirement Plan bene-
fits are paid.
Section 5.2 The Plan benefit payable to a Participant
shall be paid in the same form in which the Retirement Plan
benefit is payable to the Participant. The Participant's
election under the Retirement Plan of an optional form of
payment (with the valid consent of the Participant's Spouse
where required under the Retirement Plan) shall be deemed to
be the form of payment elected for the payment of benefits
from this Plan. Retirement Plan benefit payments subject to
an assignment pursuant to the terms of a QDRO shall not be
treated as a form of benefit payment selected by the Partici-
pant under the terms of the Retirement Plan.
ARTICLE VI
Administration
Section 6.1 The Company shall be responsible for the
general operation and administration of the Plan and for
carrying out the provisions thereof.
Section 6.2 All provisions set forth in the Retirement
Plan with respect to the administrative powers and duties of
the Company, expenses of administration and procedures for
filing claims shall also be applicable with respect to the
Plan. The Company shall be entitled to rely conclusively upon
all tables, valuations, certificates, opinions and reports
furnished by any actuary, accountant, controller, counsel or
other person employed or engaged by the Company with respect
to the Plan or with respect to any Supplemental Retirement
Benefit.
Section 6.3 The Company shall provide a retired Par-
ticipant, at the time of retirement or as soon thereafter as
practicable, with a copy of the Plan and a certificate stating
that the retired Participant is entitled to benefits under the
Plan and the amount thereof.
ARTICLE VII
Amendment or Termination
Section 7.1 The Company intends the Plan to be permanent
but reserves the right to amend or terminate the Plan when, in
the sole opinion of the Company, such amendment or termination
is advisable. Any such amendment or termination shall be made
pursuant to a resolution of the Board and shall be effective
as of the date of such resolution.
Section 7.2 No amendment or termination of the Plan
shall directly or indirectly deprive any current or former
Participant or Surviving Spouse of all or any portion of any
retirement benefit or surviving spouse benefit payment which
commenced prior to the effective date of such amendment or
termination or which would be payable if the Participant
terminated employment for any reason, including death, on such
effective date.
ARTICLE VIII
General Provisions
Section 8.1 Except as otherwise expressly provided
herein, all terms and conditions of the Retirement Plan appli-
cable to a retirement benefit or a surviving spouse benefit
shall also be applicable to a retirement benefit or a surviv-
ing spouse benefit payable hereunder. Any Plan retirement
benefit or surviving spouse benefit, or any other benefit
payable under the Plan, shall be paid solely in accordance
with the terms and conditions of the Retirement Plan and
nothing in this Plan shall operate or be construed in any way
to modify, amend or affect the terms and provisions of the
Retirement Plan.
Section 8.2 Nothing contained in the Plan shall consti-
tute a guaranty by the Company or any other entity or person
that the assets of the Company will be sufficient to pay any
benefit hereunder. The benefits under this Plan shall not be
funded, but shall constitute liabilities of the Company pay-
able when due.
Section 8.3 No Participant or Surviving Spouse shall
have any right to a benefit under the Plan except in accor-
dance with the terms of the Plan. Establishment of the Plan
shall not be construed to give any Participant the right to be
retained in the service of the Company.
Section 8.4 No interest of any person or entity in, or
right to receive a benefit under, the Plan shall be subject in
any manner to sale, transfer, assignment, pledge, attachment,
garnishment, or other alienation or encumbrance of any kind;
nor may such interest or right to receive a benefit be taken,
either voluntarily or involuntarily, for the satisfaction of
the debts of, or other obligations or claims against, such
person or entity, including claims for alimony, support,
separate maintenance and claims in bankruptcy proceedings.
Section 8.5 The Plan shall be construed and administered
under the laws of the State of Ohio.
Section 8.6 If the actuarial value of any retirement
benefit or surviving spouse benefit is less than $3,500, the
Company may pay the actuarial value of such Benefit to the
Participant or Surviving Spouse in a single lump sum in lieu
of any further benefit payments hereunder.
Section 8.7 If any person entitled to a benefit payment
under the Plan is deemed by the Company to be incapable of
personally receiving and giving a valid receipt for such
payment, then, unless and until claim therefor shall have been
made by a duly appointed guardian or other legal representa-
tive of such person, the Company may provide for such payment
or any part thereof to be made to any other person or institu-
tion then contributing toward or providing for the care and
maintenance of such person. Any such payment shall be a
payment for the account of such person and a complete dis-
charge of any liability of the Company and the Plan therefor.
Section 8.8 The Plan shall not be automatically termi-
nated by a transfer or sale of assets of the Company or by the
merger or consolidation of the Company into or with any other
corporation or other entity, but the Plan shall be continued
after such sale, merger or consolidation only if and to the
extent that the transferee, purchaser or successor entity
agrees to continue the Plan. In the event that the Excess
Plan is not continued by the transferee, purchaser or succes-
sor entity, then the Plan shall terminate subject to the
provisions of Section 7.2.
Section 8.9 Each Participant shall keep the Company
informed of his current address and the current address of his
spouse. The Company shall not be obligated to search for the
whereabouts of any person. If the location of a Participant
is not made known to the Company within three (3) years after
the date on which payment of the Participant's retirement
benefit may first be made, payment may be made as though the
Participant had died at the end of the three-year period. If,
within one additional year after such three-year period has
elapsed, or, within three years after the actual death of a
Participant, the Company is unable to locate any Surviving
Spouse of the Participant, then the Company shall have no
further obligation to pay any benefit hereunder to such Par-
ticipant or Surviving Spouse or any other person and such
benefit shall be irrevocably forfeited.
Section 8.10 Notwithstanding any of the preceding provi-
sions of the Plan, neither the Company nor any individual
acting as an employee or agent of the Company shall be liable
to any Participant, former Participant, Surviving Spouse or
any other person for any claim, loss, liability or expense
incurred in connection with the Plan.
Section 8.11 An assignment of part or all of a Partici-
pant's Maximum Benefit pursuant to the terms of a QDRO shall
not reduce the Participant's Maximum Benefit for the purpose
of determining the benefit, if any, to be paid pursuant to the
provisions of this Plan.
Section 8.12 The benefits paid by this Plan shall not
duplicate benefits being paid or to be paid by the Retirement
Plan or any Supplemental Retirement Benefit the Participant or
Participant's spouse is receiving or may be entitled to re-
ceive.
Section 8.13 In the event a Participant's claim for Plan
benefits is denied or in the event the Participant disputes
the computation of the benefit amount, the Participant shall
be entitled to the same claims appeal procedure that is avail-
able to the Participant under the terms of the Retirement
Plan.
EXHIBIT 10(i)(1)
CONFIDENTIAL
AMERICAN ELECTRIC POWER SYSTEM
MANAGEMENT INCENTIVE COMPENSATION PLAN
1995
<PAGE>
TABLE OF CONTENTS
PAGE
INTRODUCTION iv
1.0 OVERVIEW 1
1.1 Participation in MICP 1
1.2 MICP Award Limitation 2
2.0 TARGET AWARD ALLOCATIONS 3
3.0 AEP CORPORATE PERFORMANCE CRITERIA 5
3.1 Average Annual ROE 5
3.2 Total Investor Return 6
3.3 Realization Ratio 7
4.0 OPERATING COMPANY/DIVISION PERFORMANCE CRITERIA 8
4.1 Marketing Performance 8
4.2 Safety Performance 9
4.3 O&M Expense vs. Budget 11
4.4 Customer Service Reliability Index 12
5.0 POWER PLANT MANAGERS 13
6.0 CENTRALIZED PLANT MAINTENANCE MANAGERS 13
7.0 CENTRAL MACHINE SHOP MANAGER 13
8.0 TIDD PLANT MANAGER 13
9.0 FUEL SUPPLY PERFORMANCE CRITERIA 14
9.1 Adjusted Cost of Coal Produced from
Affiliated Mines 14
9.2 PUCO Cap Performance 15
9.3 Safety Performance 15
9.4 Senior Vice President and Senior Staff - Fuel
Supply - Delivered Fuel Prices 16
9.5 Vice President - Fuel Procurement Measures 16
9.6 General Mine Managers/General Superintendent
Measures 17
9.7 Manager - River Transportation Measures 18
9.8 Manager - Cook Coal Terminal Measures 18
9.9 Managing Director - Transportation Measures 19
10.0 DEPARTMENT OBJECTIVES 20
11.0 THE MICP IN ACTION 21
12.0 PAYMENT RIGHTS AT TERMINATION OF ACTIVE EMPLOYMENT 24
12.1 Termination After Completion of Plan Year 24
ii
<PAGE>
12.2 Termination Due to Death, Retirement, or
Disability 24
12.3 Involuntary Termination During Plan Year 25
13.0 CHANGES IN SALARY/POSITION/PARTICIPATION 26
14.0 PLAN ADMINISTRATION 27
ADDENDUM
PAGE
15.0 MICP AWARD DISTRIBUTIONS A-1
16.0 POSSIBLE ADJUSTMENTS TO CORPORATE PERFORMANCE DATA A-3
17.0 FUEL SUPPLY PAYMENT SCHEDULES A-4
17.1 Senior Vice President - Fuel Supply A-4
17.2 Delivered Fuel Prices A-4
17.3 Vice President - Fuel Procurement A-4
17.4 Delivered Fuel Prices A-4
17.5 Sum Total of PV Benefits/Special Contract
Renegotiations A-5
17.6 General Mine Managers/General Superintendent
(Meigs) A-6
17.7 Southern Ohio Coal Company - Meigs A-6
17.8 Central Ohio Coal Company A-6
17.9 Windsor Coal Company A-7
17.10 All Coal Mines - Safety Incidence Rate A-7
17.11 Manager - River Transportation A-8
17.12 River Transportation Operating Cost Per
Ton Mile A-8
17.13 River Transportation Safety Incidence Rate A-8
17.14 Manager - Cook Coal Terminal A-9
17.15 Cook Coal Terminal Adjusted Expenses A-9
17.16 Cook Coal Terminal Safety Incidence Rate A-9
17.17 Managing Director - Transportation A-10
17.18 Cook Coal Terminal Adjusted Expenses A-10
17.19 River Transportation Operating Cost Per
Ton Mile A-10
17.20 Delivered Fuel Prices A-11
17.21 River Transportation and Cook Coal Terminal
Safety Incidence Rate A-11
iii
<PAGE>
INTRODUCTION
The American Electric Power System will continue the Management Incentive
Compensation Plan (MICP) during 1995, with revisions from the 1994 Plan.
The Plan's purpose is to bring together the interests of key managers with
those of the AEP System's customers and shareholders by providing
performance incentives to serve customers' needs and meet shareholders'
financial expectations at the highest possible levels.
Through the MICP, a key manager can receive an annual monetary award in
addition to base salary, if certain performance levels are met. The Plan
is designed to help motivate a consistent level of superior Company
performance by rewarding those principally accountable for achieving it.
This Plan provides an element of compensation which will vary directly with
Company performance. It will ensure that key managers are compensated
competitively and consistent with the AEP System's financial and operating
performance.
Any questions about the Plan should be directed to the Assistant Vice
President-Compensation and Benefits through the respective Operating
Company President, Senior Vice President-Fuel Supply, or AEPSC Department
head.
iv
<PAGE>
1.0 OVERVIEW OF THE
MANAGEMENT INCENTIVE COMPENSATION PLAN
A participant in the MICP is assigned an annual target award expressed as a
percentage of annual base earnings. Actual awards can vary from 0% to 150%
of the target award, based on performance.
Performance criteria are established each year for the following
organization units:
- AEP Corporate
- Each Operating Company (including Fuel Supply)
- Individual Units
Each participant in the MICP is assigned a target award percentage and
advised how that target award is allocated by organizational unit. After
the end of a year, actual awards are determined based on how well the
participant and/or the organizational units meet their performance
criteria.
During the first part of the year following each performance year a
participant will receive 80% of any actual award in cash unless a deferral
election had been made in accordance with Section 15.2. The remaining 20%
is deferred in the form of AEP common stock units payable 3 years later
(see Addendum page A-1) unless a deferral election had been made in
accordance with Section 15.2. The Plan will pay out 75% and defer 25% of
the award to those employees participating in the MICP and an all-employee
variable pay plan.
1.1 PARTICIPATION IN MICP
Participation in MICP is limited each year to a select group of key
managers and executives whose performance most significantly affects
the Company's success. Positions eligible and individual executives
were approved for participation by the Chief Executive Officer at the
inception of the Plan. The following procedures apply to the addition
of any other positions or executives:
A. OPERATING COMPANIES
Participation is generally automatic for employees promoted or
transferred to a position that has been previously approved as
eligible for participation in the Plan, effective on the
promotion or transfer date. However, if an employee is demoted
to a position normally covered by the MICP, approval of the Chief
Executive Officer is required for the demoted employee to be
eligible to continue as a participant. Requests for such
approval should be submitted to the Executive Vice President.
B. AEPSC AND FUEL SUPPLY DEPARTMENT
Prior to becoming a participant in the Plan, specific approval of
the Chief Executive Officer is required for all employees or
positions not previously eligible to participate in the Plan.
Requests for approval by the Chief Executive Officer should be
submitted through the AVP-Compensation & Benefits.
An executive who is not currently a Plan participant and who is
entering an eligible position for the first time, will generally be
eligible to participate in that year's Plan if the promotion/transfer
date is prior to October 1. If it is after this date, the executive
will be eligible to participate in the following year's Plan.
1.2 MICP AWARD LIMITATION
No award is payable unless AEP's dividends remain at prevailing levels
and net income is greater than dividend payments in the current year.
2.0 TARGET AWARD ALLOCATIONS
Target awards of MICP participants are allocated to AEP Corporate and other
organization units, as follows:
<TABLE>
<CAPTION>
Target
Award* as
Percent of Percent of Awards Allocated
Participant Base Salary to Organizational Units
<S> <C> <C> <C>
Office of the Chairman 30 100 Corporate Performance
AEPSC Treasurer, VPs, and SVPs 25 75 Corporate Performance
25 Department Performance
or
100 Corporate Performance
Senior VP - Fuel Supply 25 25 Corporate Performance
50 Fuel Supply Performance
25 Delivered Fuel Prices
Operating Company Presidents 25 50 Corporate Performance
50 Operating Company Performance
AEPSC Senior Division Managers 20 75 Corporate Performance
and Others as Designated 25 Department Performance
or
100 Corporate Performance
Operating Company VPs 20 50 Corporate Performance
50 Operating Company Performance
Operating Company G.O. Department 20 25 Corporate Performance
Heads and Executive Assistants 50 Operating Company Performance
25 Department Performance
or
25 Corporate Performance
75 Operating Company Performance
Operating Company Division/Region 20 25 Corporate Performance
Managers 25 Operating Company Performance
50 Division/Region Performance
Power Plant Managers (including 20 25 Corporate Performance
Cook & Tidd) 75 Plant Incentive Plan
Centralized Plant Maintenance 20 25 Corporate Performance
Managers 75 Central Plant Maintenance Performance
Central Machine Shop Manager 20 25 Corporate Performance
75 Central Machine Shop Performance
Fuel Supply Lancaster Senior Staff 20 25 Corporate Performance
50 Fuel Supply Performance
25 Delivered Fuel Prices
Vice President - Fuel Procurement 20 25 Corporate Performance
25 Fuel Supply Performance
50 Department Performance
Managing Director - Transportation 20 25 Corporate Performance
25 Fuel Supply Performance
50 Department Performance
Fuel Supply General Mine Managers/ 20 25 Corporate Performance
General Superintendent (Meigs) 25 Fuel Supply Performance
50 Division/Mine Performance
Manager - Cook Coal Terminal 20 25 Corporate Performance
75 Cook Coal Terminal Performance
Manager - River Transportation 20 25 Corporate Performance
75 River Transportation Performance
*Target awards are proportionately reduced for those participants in other all-
employee variable pay plans.
</TABLE>
3.0 AEP CORPORATE PERFORMANCE CRITERIA
There are three AEP Corporate performance criteria which are weighted to
determine a single Corporate performance factor. The three are as follows:
- A two-component measure of Annual Return on Average Stockholder
Equity (ROE) for the current year - weighted at 25%;
- A component measuring the Three-year Average Total Investor Return
(TIR) - weighted at 25%; and
- A component comparing the Realization Ratio (Average Price of Power
Sold to Retail Customers vs. Other Utilities) for the current year -
weighted at 50%.
The following describes each in greater detail.
3.1 RETURN ON EQUITY (ROE) is corporate annual after-tax income as a
percentage of average annual stockholder equity. It is an indication
of how profitably AEP manages its investors' capital. For purposes of
the MICP, ROE is measured in the following two ways, each of which is
weighted 12.5%:
- In terms of absolute performance; and
- Relative to the ranking of the AEP ROE among the 20 other
electric utilities that together with AEP make up the Standard &
Poor's Utility Index.
The results of these two measures are averaged to determine performance
on this component.
The following chart indicates both of these ROE measurements and the
performance factors for each.
<TABLE>
<CAPTION> Average Annual ROE
Absolute Performance S&P Utility Performance
ROE Factor* ROE Ranking** Factor
<S> <C> <C> <C>
16 or more 1.50 1 - 6 1.50
15 1.25 7 1.40
14 1.00 8 1.30
13 .80 9 1.20
12 .60 10 1.10
11 .40 11 1.00
10 or less 0 12 .80
13 .60
14 .40
15 .20
16 or more 0
</TABLE>
*Interpolate at intermediate performance.
**Highest ROE is ranked first.
Example: If AEP's annual ROE is 14%, and AEP achieves an S&P Utility Index
rank of seventh out of 21, the average performance factor will be
calculated this way: (1.00 + 1.40) <divide> 2 = 1.20.
3.2 TOTAL INVESTOR RETURN (TIR) is an indicator of the increase in value of
AEP shareholders' investment. It measures the annual percentage
increase in stock price as well as dividends paid over a three-year
period (the current and two prior years). AEP System results are then
compared with the other 20 companies in the Standard & Poor's Utility
Index and are ranked for each of the three years. Performance factors
are determined based on the average of the TIR rankings for the three
years, as follows:
<TABLE>
<CAPTION> Three-Year Average Total Investor Return
AEP TIR Ranking* Performance Factor
<S> <C>
6 or higher 1.50
7 1.40
8 1.30
9 1.20
10 1.10
11 1.00
12 .80
13 .60
14 .40
15 .20
16 0
</TABLE>
*Highest TIR is ranked first.
Example: If the three-year average rank of AEP is 12 out of 21, the
performance factor is .80.
3.3 REALIZATION RATIO is a measure of relative cost efficiency and
productivity -- from AEP customers' perspective. It compares the AEP
System's average price of power sold to ultimate customers with other
utilities' corresponding average price. The realization ratio is
based on average realization for sales to ultimate customers by other
investor-owned utilities in the seven states in which AEP operates,
weighted by the respective proportions of AEP's corresponding sales in
those states. (Because Kingsport Power is the only investor-owned
electric utility in Tennessee, the realization ratio for that state is
based on retail rates of TVA Tennessee distributors.) Performance
factors are then derived, as follows:
<TABLE>
<CAPTION> AEP REALIZATION RATIO
AEP Ratio Performance Factor*
<S> <C>
.75 or less 1.50
.80 1.25
.85 1.00
.90 .75
.95 .50
1.00 .25
above 1.00 0
</TABLE>
*Interpolate at intermediate performance.
Example: If AEP's average realization is 20% below the seven-state
average, its ratio will be .80 and the performance factor will be 1.25.
4.0 OPERATING COMPANY/DIVISION PERFORMANCE CRITERIA
There are four Operating Company and Division performance criteria, each of
which is given equal weighting to determine a single performance factor for
each Operating Company and each Division. The four are as follows:
- Achievement of Annual Marketing Objectives - weighted at 25%;
- Safety Performance - weighted at 25%;
- O&M Expense Performance vs. Budget - weighted at 25%; and
- Customer Service Reliability Index - weighted at 25%.
The following describes each measure in more detail.
4.1 ACHIEVEMENT OF ANNUAL MARKETING OBJECTIVES is measured by comparing
actual performance against marketing objectives for the current year.
Performance factors relate to achievement, as follows:
Operating Company and Division
Target Award Payment Schedules
Annual Marketing Results vs. Goal
Results as Percent of Goal Performance Factor*
Over 110% 1.50
105% 1.25
100% 1.00
95% .50
Below 95% 0
*Interpolate at intermediate performance.
Example: If 105% of the marketing goal has been achieved, the
performance factor is 1.25. If 108% had been obtained, the
performance factor would be calculated as follows:
(108%-105%/110%-105% x 25) + 1.25 = 1.40
4.2 SAFETY PERFORMANCE of each Operating Company and Division is measured
by two indices, equally weighted at 50%:
- RECORDABLE CASE INCIDENCE RATE - Number of recordable cases per
200,000 work hours.
- LOST AND RESTRICTED WORKDAY (SEVERITY) RATE - Number of days away
from work AND restricted activity days per 200,000 work hours.
The rate for the appropriate group will be compared to the most
recently published EEI rate calculated for each measure. The related
performance factors are determined from the following schedule and
averaged to yield a single performance factor for safety performance.
Operating Company and Division/Region
Target Award Payment Schedule
Ratio to the Latest EEI Rate
Operating Company or Division/Region Safety Performance
Ratio to EEI Performance Performance Factor*
0.700 1.50
0.850 1.00
0.925 0.50
1.000 or more 0
*Interpolate at intermediate performance.
Example: If a Division achieves a ratio of .9250 to the EEI recordable
case incidence rate and a ratio of .6500 to the EEI lost and
restricted workday (severity) rate, the respective
performance factors are .5000 and 1.50. Averaging the two
yields a single performance factor of 1.000.
For the purposes of these safety measures, Wheeling Power and
Kingsport Power are considered Divisions.
The performance factor shall be zero for any Division whose recordable
injuries include a fatality or a permanent total disability case.
SOURCE OF DATA
- EEI Rate and AEP Data
The EEI rates will be taken from the latest EEI Safety Statistical
Survey Report at the time the awards are calculated. The data for
the companies and divisions is taken from the year-end AEP System
Report of Employee Injuries and Illnesses. This information is
compiled by the Safety & Health Section of System Human Resources.
The following data for the December cumulative year-to-date report is
to be compiled by each Operating Company and forwarded to the AEPSC
Safety & Health Division on or before January 15 of the following
year:
- Company/Division
- Total Hours Worked
- Lost Workdays (LWD Case - days away from work)
- Restricted Activity Days
- Lost and Restricted Workday (Severity) Rate
- Recordable Cases
- Recordable Case Incidence Rate
DATA AVAILABILITY, CALCULATIONS AND AWARD DETERMINATIONS
The AEPSC Safety & Health Section will calculate the performance
factors for each Company and Division. The calculations will be
completed by January 30 and approved by the SVP-Human Resources.
4.3 O&M EXPENSE PERFORMANCE VS. BUDGET is measured by comparing
controllable operating and maintenance expenses against budget for the
current year. Performance factors are designed to provide increased
awards for expense performance which is below budget. However,
because some O&M budgets are developed based primarily upon historical
expenses and not upon need to complete specific projects, close
monitoring of expenses is required. Each Operating Company president
is responsible for monitoring expenses in each operation to ensure
that projects that should have been accomplished are not delayed or
omitted in order to achieve a higher performance factor score. If
this is judged to occur, the approved budget will be commensurately
reduced by an amount equal to the estimated cost of the project, and a
revised performance factor determined.
Operating Company and Division/Region
Target Award Payment Schedule
Controllable O & M Expenses vs. Budget
Expenses as Percent of Budget* Performance Factor
Less than 91% 1.50
91% but less than 96% 1.25
96% but less than 101% 1.00
101% but less than 103% .50
103% but less than 105% .25
105% or higher 0
*All numbers to be rounded to nearest whole numbers.
Example: If an Operating Company's actual result is 93% of budget, the
company has placed between the 91% and 96% bracket, achieving
a performance factor of 1.25.
4.4 CUSTOMER SERVICE RELIABILITY INDEX is measured by comparing the
current year annual service interruption frequency index and the
interruption duration index against prior five-year average indices.
The reliability index is determined by the following formula:
[(Cur.Interpt.Freq.Index) + (Cur.Inerpt.Dur.Index)]
_______________________________________________________ X 100 / 2
[(5-yr.Avg.Intm.Freq.Index) (5-yr.Avg.Intm.Dur.Index)]
Resulting performance factors are determined as follows:
Operating Company and Division/Region
Target Award Payment Schedule
Customer Service
Reliability Index vs. Prior Five-Year Average
<TABLE>
<CAPTION>
Service Reliability Index Performance Factor*
<S> <C>
85% or lower 1.50
92.5% 1.25
100% 1.00
105% .50
110% or higher 0
*Interpolate at intermediate performance.
Example: If an Operating Company's current reliability index is
97%, 3% better than its five-year average of 100%, the
performance factor is:
(100%-97%)
_________ x.25)+1=1.10
(100%-92.5%)
</TABLE>
SPECIAL ADJUSTMENTS MAY BE CONSIDERED FOR CATASTROPHIC SITUATIONS.
(SEE PAGE 2 OF THE ADMINISTRATION MANUAL.)
5.0 POWER PLANT MANAGERS
INCENTIVE AWARDS FOR POWER PLANT MANAGERS ARE FROM TWO SOURCES:
--AEP CORPORATE PERFORMANCE - WEIGHTED 25%;
AND
--PERFORMANCE AS DETERMINED BY POWER PLANT
INCENTIVE COMPENSATION PLAN - WEIGHTED 75%.
6.0 CENTRALIZED PLANT MAINTENANCE MANAGERS
INCENTIVE AWARDS FOR THE MANAGERS OF APPALACHIAN POWER'S
AND OHIO POWER'S CENTRALIZED PLANT MAINTENANCE DIVISIONS
ARE FROM TWO SOURCES:
--AEP CORPORATE PERFORMANCE - WEIGHTED 25%;
AND
--PERFORMANCE AS DETERMINED BY THE
CENTRALIZED PLANT MAINTENANCE DIVISION'S
INCENTIVE COMPENSATION PLAN - WEIGHTED 75%.
7.0 CENTRAL MACHINE SHOP MANAGER
INCENTIVE AWARDS FOR THE CENTRAL MACHINE SHOP MANAGER ARE FROM TWO SOURCES:
--AEP CORPORATE PERFORMANCE - WEIGHTED 25%;
AND
--PERFORMANCE AS DETERMINED BY THE CENTRAL
MACHINE SHOP INCENTIVE COMPENSATION PLAN - WEIGHTED 75%.
8.0 TIDD PLANT MANAGER
INCENTIVE AWARDS FOR THE TIDD PLANT MANAGER ARE FROM TWO SOURCES:
--AEP CORPORATE PERFORMANCE - WEIGHTED 25%;
AND
--PERFORMANCE AS DETERMINED BY THE TIDD PFBC
INCENTIVE COMPENSATION PLAN - WEIGHTED 75%.
9.0 FUEL SUPPLY PERFORMANCE CRITERIA
THERE ARE THREE OVERALL FUEL SUPPLY PERFORMANCE MEASURES, WHICH
ARE WEIGHTED TO DETERMINE A SINGLE FUEL SUPPLY PERFORMANCE FACTOR.
THESE ARE AS FOLLOWS:
--ADJUSTED COST OF COAL PRODUCED FROM AFFILIATED MINES,
MEASURED BY CENTS PER MILLION BTU (<cent>/MM BTU)
FOR THE CURRENT YEAR AS REDUCED TO REFLECT EXTRAORDINARY
COSTS DUE TO DOWNSIZING AND/OR OTHER SPECIAL EXPENSES AND
A<plus-minus> VOLUME ADJUSTMENT OF 50<cent>/MM BTU FOR
VARIANCE FROM BUDGETED TONS - WEIGHTED AT 50%; AND
--PERFORMANCE RELATIVE TO THE PUCO NEGOTIATED EFC CAP -
WEIGHTED AT 25%; AND
--SAFETY INCIDENCE RATE AS A PERCENT OF THE INDUSTRY
INCIDENCE RATE FOR THE CURRENT YEAR - WEIGHTED AT 25%.
THE FOLLOWING DESCRIBES EACH IN GREATER DETAIL.
9.1 ADJUSTED COST OF COAL PRODUCED FROM AFFILIATED MINES
The adjusted cost of coal produced as measured by
<cent>/MM BTU is a measure of how efficiently
affiliated mines produce clean coal for use in the
System's power plants. Performance factors relate
to achievement as follows:
Fuel Supply Target Award Payment Schedule
Affiliated Mine Costs
<TABLE>
<CAPTION>
<cent>/MM BTU Performance Factor*
<S> <C>
178.2 or lower 1.50
180.2 1.25
182.2 1.00
184.2 .75
186.2 .50
188.2 .25
190.2 or higher 0
*Interpolate at intermediate performance.
</TABLE>
9.2 PUCO CAP PERFORMANCE
The PUCO cap performance measures the
amount of operating loss as defined
in the Settlement Agreement dated
February 28, 1995.
Fuel Supply Target Award Payment Schedule
PUCO CAP PERFORMANCE
<TABLE>
<CAPTION>
CAP PERFORMANCE Performance Factor*
<S> <C>
$ 0 1.50
$ 5 million 1.25
$ 10 million 1.00
$ 15 million .75
$ 20 million .50
More than $ 20 million 0
</TABLE>
*Interpolate at intermediate Performance
Example: If the average cap performance was $8.0 million,
the performance factor would be:
( 10-8)
(______ x.25)+1.00=1.10
( 10-5)
9.3 SAFETY PERFORMANCE
Achievement of the safety objective is measured by comparing the
incidence rate for the current year with the comparable coal
industry incidence rate (including Fuel Supply). Performance
factors relate to achievement as follows:
Fuel Supply Target Award Payment Schedule
Safety - Incidence Rate vs. Coal Industry
<TABLE>
<CAPTION>
Incidence Rate - Percent Performance Factor*
Industry Rate
<S> <C>
55 or lower 1.50
65 1.25
75 1.00
85 .75
90 .50
95 .25
higher than 95 0
*Interpolate at intermediate performance.
Example: If Fuel Supply's incidence rate were 92% of the coal
industry rate, the performance factor is:
(95%-92%)
(_______x.25)+.25=.40
(95%-90%)
</TABLE>
9.4 SENIOR VICE PRESIDENT AND SENIOR STAFF-FUEL SUPPLY - DELIVERED
FUEL PRICES
In addition to the awards allocated to Corporate performance and
Fuel Supply performance, the Senior Vice President and Senior
Staff-Fuel Supply are assigned a 25% award allocated to delivered
fuel prices, (spot/contract) composited change as a percent of the
GDP price index (fixed weight). (See Page A-4 for the target award
payment schedule.)
9.5 VICE PRESIDENT - FUEL PROCUREMENT MEASURES
In addition to the Corporate performance measures weighted 25% and
the overall Fuel Supply performance measure weighted 25%, the Vice
President - Fuel Procurement has two Department performance measures
which are weighted to determine a single Department performance
weighting of 50%. These are as follows:
--Delivered fuel prices (spot/contract) composited change as
a percent of the GDP price index (fixed weight), a national
index which measures inflation of price for the current year -
weighted 75%; and
--Sum total of present value benefits from renegotiation of existing
contracts for coal and transportation outside of existing contract
price adjustment provisions - weighted at 25%.
Tables showing the performance factors and how they relate to
achievement begin on page A-4 of the Addendum.
9.6 GENERAL MINE MANAGERS/GENERAL SUPERINTENDENT (MEIGS) MEASURES
In addition to the Corporate performance measures weighted 25%
and the overall Fuel Supply performance measures weighted 25%, the
Fuel Supply General Mine Managers and General Superintendent (Meigs)
have two Division/Mine performance measures which are weighted to
determine a single Division/Mine performance award weighting of 50%
for the mines for which they are responsible.
These are as follows:
--Adjusted cost of coal produced from affiliated mines, measured by
cents per million BTU (<cent>/MM BTU) for the current year as
reduced to reflect extraordinary costs due to downsizing and/or
other special expenses and a<plus-minus> volume adjustment of
50<cent>/MM BTU for variance from budgeted tons - weighted at 75%;
and
--Safety incidence rate for the current year as a percent of the
comparable industry incidence rate for either underground or
surface mines (whichever is applicable) - weighted at 25%.
Tables showing the performance factors and how they relate to
achievement begin on page A-6 of the Addendum.
The performance factor shall be zero for any mine whose lost
workdays charged for any single occurrence total 6,000 days
or higher.
9.7 MANAGER - RIVER TRANSPORTATION MEASURES
The Manager-River Transportation has, in addition to the overall
Corporate performance measures weighted 25%, two Department
performance measures which are weighted to determine a single
Department performance weighting of 75% for River Transportation.
These are:
--Operating costs measured by adjusted mils per ton mile (mils/ton
mile-$0.00x) for the current year, excluding cost for fuel,
associated taxes and other fixed and special expenses, as
approved by the SVP-Fuel Supply, with a<plus-minus> volume
adjustment of 1.5 mils/ton mile for variance from budgeted
mils per ton mile - weighted 75%;
and
--Safety incidence rate for the current year as a percent of the
most recently published incidence rate for the water transportation
industry - weighted 25%.
The performance factor shall be zero for any operation whose lost
workdays charged for any single occurrence total 6,000 days or higher.
Tables showing the performance factors and how they relate to
achievement are on page A-8 of the Addendum.
9.8 MANAGER - COOK COAL TERMINAL MEASURES
The Manager-Cook Coal Terminal has, in addition to the overall Corporate
performance measures weighted 25%, two Department performance measures
which are weighted to determine a single Department performance weighting
of 75% for Cook Coal Terminal. These are:
--Adjusted expenses measured by total costs incurred less rental
expenses, other fixed and special expenses (e.g., harbor dredging),
as approved by SVP-Fuel Supply, <plus-minus> adjustment volumes
times 25<cent>/ton - weighted 75%;
and
--Safety incidence rate at CCT for the current year as a percent of
the most recently published incidence rate for the coal preparation
plants - weighted 25%.
The performance factor shall be zero for any operation whose lost
workdays charged for any single occurrence total 6,000 days or higher.
Tables showing the performance factors and how they relate to
achievement are on page A-9.
9.9 MANAGING DIRECTOR - TRANSPORTATION MEASURES
In addition to the Corporate performance measures weighted 25%
and the overall Fuel Supply performance measure weighted 25%,
there are two overall transportation department performance
criteria which are weighted to determine a single department
performance factor. These are:
--Transportation cost of fuel delivered comprised of performance
at Cook Coal Terminal (adjusted expenses), River Transportation
(adjusted cost per ton mile) and delivered fuel prices
(spot/contract) - each weighted 25%; and
--Safety incidence rate at River Transportation and Cook Coal for
the current year as a percent of the most recently published
comparable industry rate for each location (RTD vs water
transportation industry; CCT vs coal preparation plants) -
each weighted 12.5%.
Tables showing the performance factors and how they relate to
achievement are on page A-10.
10.0 DEPARTMENT OBJECTIVES
Performance criteria, with appropriate weightings, may be established each
year based on agreed objectives in each department in AEPSC, the Operating
Companies, or Fuel Supply.
The performance rating scale is similar to those used in other measures,
with ratings from 0 to 1.5, and 1.0 as target performance. Managers who
set department objectives which are subjective in nature will determine
the degree of accomplishment in accordance with the 0 to 1.5 scale, taking
into consideration such factors as timeliness, degree of accomplishment,
acceptability of results, etc.
In situations where a participant who has been assigned department
objectives leaves the position during a Plan year, his successor will
generally assume the same objectives and both participants will share the
final performance factor score.
11.0 THE MICP IN ACTION
Following is an illustration to demonstrate how the mechanics of the MICP
work. For purposes of this example, assume that an Operating Company
Division Manager with annual base salary earnings of $90,000 has a target
award of 20%, or $18,000. This individual's target award is allocated among
the following performance criteria:
--AEP Corporate Performance: 25%, or $4,500
--Operating Company Performance: 25%, or $4,500
--Division Performance: 50%, or $9,000
11.1 In determining the AEP Corporate portion of the MICP award, results
are measured for three separate Corporate performance criteria to
arrive at a single Corporate performance factor. ROE is measured in
two ways, averaged, and given a 25% weighting; Total Investor Return
(TIR) is given a 25% weighting; and Realization Ratio is given a 50%
weighting.
ROE 14% actual ROE = 1.00
S&P ranking (7th) = 1.40
_______________________________
Average 1.20 x 25% = .30
TIR S&P ranking (12th) = .80 x 25% = .20
Realization
Ratio AEP ratio (.80) = 1.25 x 50% = .625
______
Corporate Performance Factor = 1.125
The AEP Corporate award, then, is 1.125 x $4,500, or $5,062.50.
11.2 IN DETERMINING THE OPERATING COMPANY PORTION OF THE MICP AWARD, RESULTS
ARE MEASURED AGAINST FOUR OPERATING COMPANY PERFORMANCE CRITERIA TO
ARRIVE AT THE OPERATING COMPANY PERFORMANCE FACTOR. ALL FOUR PERFORMANCE
CRITERIA ARE WEIGHTED EQUALLY AT 25% EACH:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Marketing Performance Result = 105% = 1.25 x 25% = .3125
Safety Performance Result = 22.5% = .75 x 25% = .1875
O&M Expense Performance
vs. Budget Result = 93% = 1.00 x 25% = .2500
Customer Service
Reliability Index Result = 97% = 1.10 x 25% = .2750
______
Operating Company Performance Factor = 1.025
The Operating Company Award, then, is 1.025 x $4,500, or $4,612.50
</TABLE>
11.3 IN DETERMINING THE DIVISION PORTION OF THE MICP AWARD, WE MEASURE
RESULTS AGAINST FOUR PERFORMANCE CRITERIA TO ARRIVE AT THE PERFORMANCE
FACTOR--AGAIN GIVING EQUAL WEIGHTING TO ALL FOUR CRITERIA.
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Marketing Performance Result = 107% = 1.35 x 25% = .3375
Safety Performance Result = 22.5% = 1.25 x 25% = .3125
O&M Expense Performance
vs. Budget Result = 97% = 1.50 x 25% = .3750
Customer Service
Reliability Index Result = 100% = 1.00 x 25% = .2500
______
Performance Factor = 1.275
The Division award, then, is 1.275 x $9,000, or $11,475.00
</TABLE>
11.4 THE OPERATING COMPANY DIVISION MANAGER IN OUR EXAMPLE EARNED A TOTAL
AWARD OF $21,150.00, AS FOLLOWS:
--AEP CORPORATE $ 5,062.50
--OPERATING COMPANY 4,612.50
--DIVISION 11,475.00
___________
$ 21,150.00
Of that amount, 80%, or $16,920.00 is paid during the first part of the
following year, assuming the participant has not elected to defer receipt
of that payment under Section 15.2. The balance, $4,230.00, is deferred
in AEP common stock units for three years. (No actual shares of stock
are purchased--the amount deferred is merely treated as if shares had
been purchased with these funds.) During that time dividends, which
are credited on the deferred stock units, are used to "purchase"
additional deferred stock units. After three years, the individual will
receive a cash payment in the amount of the deferred units' value,
which shall be equal to the average daily high and low market price of
AEP common stock for the quarter preceding the payment date. (See
page A-1 in the Addendum for further details.)
12.0 PAYMENT RIGHTS AT TERMINATION OF ACTIVE EMPLOYMENT
12.1 TERMINATION AFTER COMPLETION OF PLAN YEAR
A participant who is actively employed on December 31 of the Plan year
is entitled to receive the regular cash award (80%) for that year and,
if applicable, the value of his deferred award that has met the three
calendar year requirement. For example, an employee who is actively
employed on 12/31/95, and subsequently terminates is entitled to the
80% cash award for Plan year 1995, and if applicable, the value of his
1992 Plan year deferred amount.
Alternatively, a participant may elect to defer receipt of awards in
accordance with Section 15.2.
12.2 TERMINATION DUE TO DEATH, RETIREMENT, OR DISABILITY
If a participant should leave active employment during a Plan year
because of death, retirement, or disability, the award will be pro-
rated based on the time the participant was actively employed in
positions covered by the Plan during that year. Full payment of
100% of the pro-rated award will be made as soon as practicable in
the following year.
The mandatory deferrals of the 20% portions of any awards are normally
paid as soon as practicable after the participant's death, retirement,
or disability. For purposes of the MICP, disability shall mean the
employee meets the definition of permanent and total disability under
the AEP System Retirement Plan. For purposes of this Section 12.2 and
Section 12.4, "retirement" occurs on the date an employee who is at
least age 55 and who has five or more years of vesting service, ceases
active employment with the company.
In situations where a participant retires, plan participation ends on
the date that full control and responsibility for the function ceased.
The manager who is on vacation prior to and extending immediately into
retirement has effectively ended his responsibility for managing the
unit.
Upon the death of an active or terminated participant, all deferred
awards are immediately payable to the participant's surviving spouse.
If the participant's spouse is not living, the deferred awards are
immediately payable to the participant's estate.
12.3 INVOLUNTARY TERMINATION DURING PLAN YEAR
If a participant is involuntarily terminated from employment during a
Plan year because of (1) the permanent closing of an office, plant or
other facility, or (2) as a direct result of restructuring,
consolidation, change in control of the corporation or downsizing, the
award will be pro-rated based on the time the participant was actively
employed in positions covered by the Plan during that year. Full
payment of 100% of the pro-rated award will be made as soon as
practicable in the following year. Deferred awards are payable as
soon as practicable after the participant's involuntary termination.
12.4 Any potential award for the current Plan year, and all mandatory
deferrals of the 20% portions of any awards that have not met the
three calendar year requirement pursuant to Section 15.1, are forfeited
when a participant terminates active employment during the Plan year for
reasons other than (1) death, retirement, disability, or (2) involuntary
termination as described in Section 12.3.
13.0 CHANGES IN SALARY / POSITION / PARTICIPATION
Awards are paid as a percentage of the performance year's annual base
earnings, including merit and promotional increases.
In situations where participation changes as a result of job assignment,
the employee will be entitled to a pro-rata share of any incentive award
earned during the period he or she is employed in a position covered by
the Plan.
In the event an MICP participant is transferred from a position covered by
the Plan to another such covered position within the AEP System, the
participant will be entitled to a pro-rata share of any incentive award
earned during the period he or she is employed in each of the positions.
If the participant is subject to different target awards as a percent of
base salary in the same performance year, each target award percentage will
be applied to the base salary earned during the period employed in the
related position.
14.0 PLAN ADMINISTRATION
The MICP is administered by the Human Resources Committee of the American
Electric Power Company, Inc. Board of Directors through the Executive
Compensation Committee of AEPSC. Subject to the approval of the Chief
Executive Officer, the Executive Compensation Committee's interpretation
of the Plan's provisions are conclusive and binding on all participants.
Participation in the MICP in any Plan year shall not be viewed as conferring
any right to continued employment, or to continued participation in the MICP.
Subject to the approval of the Chief Executive Officer, the Executive
Compensation Committee of AEPSC may vary performance criteria, weightings,
and/or performance factor schedules from time to time when appropriate,
enlarge or diminish the number of participants, or make other adjustments
or amendments to improve the workings of the Plan.
The Board of Directors reserves a right to amend or terminate the MICP.
Amendment or termination of the Plan will not adversely affect any funds
deferred into stock unit accounts prior to the amendment or termination.
For good and sufficient cause, on petition by an Operating Company president
or by a senior officer of the Company, and with the approval of the Chief
Executive Officer, any performance factor(s) for any participant(s) may be
varied not more than plus or minus 25% to reflect exceptional circumstance.
15.0 MICP AWARD DISTRIBUTIONS AND DEFERRALS
15.1 WHEN ALL OF THE NECESSARY DATA ARE AVAILABLE AFTER THE END OF THE PLAN
YEAR, PERFORMANCE RESULTS WILL BE CALCULATED AND AWARDS MADE AS SOON
AS PRACTICABLE. UNLESS THE PARTICIPANT HAS MADE AN ELECTION TO DEFER
RECEIPT OF AN ADDITIONAL PORTION OF THE ENTIRE AWARD IN ACCORDANCE
WITH SECTION 15.2, EIGHTY PERCENT OF THE AWARD EARNED WILL BE PAID IN
CASH, EXCEPT FOR VARIABLE PAY PLAN PARTICIPANTS AS NOTED IN SECTION
1.0. TWENTY PERCENT OF ANY AWARDS MADE UNDER THE MICP WILL BE
DEFERRED. ALL DEFERRALS ARE INVESTED IN AEP STOCK UNIT ACCOUNTS. NO
AEP STOCK IS ACTUALLY PURCHASED -- THE AMOUNT DEFERRED IS TREATED AS
IF ACTUAL SHARES HAD BEEN PURCHASED.
THE NUMBER OF STOCK UNITS IS DETERMINED BY DIVIDING THE AMOUNT
DEFERRED BY THE AVERAGE OF THE DAILY HIGH AND LOW AEP COMMON STOCK
PRICES DURING THE PLAN YEAR IN WHICH THE INCENTIVE AWARD WAS EARNED.
AN AMOUNT EQUAL TO AEP COMMON STOCK DIVIDENDS IS CREDITED ON THE DATE
PAYABLE EACH CALENDAR QUARTER COMMENCING WITH THE FIRST QUARTER OF THE
YEAR FOLLOWING THE YEAR IN WHICH THE AWARD WAS EARNED. THOSE AMOUNTS
ARE "REINVESTED" TO "PURCHASE" ADDITIONAL DEFERRED STOCK UNITS AT THE
AVERAGE OF THE DAILY HIGH AND LOW MARKET PRICE FOR THE QUARTER IN
WHICH THE STOCK DIVIDEND APPLIES.
AMOUNTS DEFERRED IN STOCK UNITS ARE PAYABLE IN CASH TO PARTICIPANTS
AFTER THE END OF THREE CALENDAR YEARS FOLLOWING THE END OF THE YEAR
FOR WHICH THE 80% PORTION OF THE AWARD WAS SCHEDULED TO BE PAID.
HOWEVER, A PARTICIPANT MAY ELECT TO DEFER RECEIPT AS OUTLINED IN
SECTION 15.2.
THE VALUE OF STOCK UNITS PAID IS BASED ON THE AVERAGE DAILY HIGH AND
LOW MARKET PRICE OF AEP COMMON STOCK FOR THE QUARTER IMMEDIATELY
PRECEDING THE DATE OF PAYMENT.
BECAUSE AMOUNTS HELD IN DEFERRED STOCK UNIT ACCOUNTS DO NOT INVOLVE
THE ACTUAL PURCHASE OF STOCK, PLAN PARTICIPANTS ARE NOT ENTITLED TO
VOTING OR CERTAIN OTHER RIGHTS APPLICABLE TO AN ACTUAL SHAREHOLDER.
AMOUNTS HELD IN DEFERRED STOCK UNIT ACCOUNTS MAY NOT BE ASSIGNED,
TRANSFERRED, OR PLEDGED BY A PLAN PARTICIPANT NOR WILL THEY BE SUBJECT
TO EXECUTION, ATTACHMENT OR OTHER SIMILAR PROCESS.
IF THE EXECUTIVE COMPENSATION COMMITTEE DETERMINES THAT THE OCCURRENCE
OF ANY MERGER, RECLASSIFICATION, CONSOLIDATION, RECAPITALIZATION,
STOCK DIVIDEND OR STOCK SPLIT REQUIRES AN ADJUSTMENT IN ORDER TO
PRESERVE THE BENEFITS INTENDED UNDER THE PLAN, THEN THE COMMITTEE MAY,
IN ITS DISCRETION, MAKE EQUITABLE PROPORTIONATE ADJUSTMENTS IN THE
NUMBER OF DEFERRED STOCK UNITS HELD BY PARTICIPANTS.
15.2 ELECTIONS TO DEFER RECEIPT OF A PORTION OF THE PLAN'S 80% CASH AWARD
(UP TO THE FULL AMOUNT) OR ANY PREVIOUSLY DEFERRED 20% AWARDS MUST BE
EXECUTED ONE YEAR PRIOR TO THE DATE EACH AWARD WOULD OTHERWISE BE
PAYABLE. THE INITIAL ELECTIVE DEFERRAL PERIOD IS ONE 3-YEAR TERM FOR
THE 80% CASH AWARD. SUBSEQUENT DEFERRALS, FOLLOWING THE INITIAL
DEFERRAL PERIOD, SHALL APPLY TO THE AGGREGATE AMOUNTS INITIALLY
DEFERRED AND SHALL BE FOR PERIODS OF NOT LESS THAN ONE YEAR; HOWEVER,
IF THE PARTICIPANT'S ELECTIVE DEFERRAL PERIOD EXTENDS BEYOND THE
PARTICIPANT'S EMPLOYMENT TERMINATION DATE AND THE PARTICIPANT'S
TERMINATION OCCURRED UNDER CIRCUMSTANCES OTHER THAN THOSE DESCRIBED IN
SECTION 12.3, PAYMENT WILL BE MADE NO LATER THAN FIVE YEARS AFTER THE
PARTICIPANT'S TERMINATION OF EMPLOYMENT.
ALL AMOUNTS DEFERRED IN ACCORDANCE WITH THE PRECEDING ARE REINVESTED
IN AEP STOCK UNIT ACCOUNTS DESCRIBED IN SECTION 15.1.
16.0 POSSIBLE ADJUSTMENTS TO CORPORATE PERFORMANCE DATA
IF ESTIMATED DATA ARE REQUIRED TO CALCULATE CORPORATE PERFORMANCE AWARDS, OR
IF CORRECTIONS ARE MADE TO DATA PREVIOUSLY REPORTED AS FINAL, ADJUSTMENTS TO
AWARDS MAY BE MADE WHEN FINAL DATA ARE AVAILABLE.
17.0 FUEL SUPPLY PAYMENT SCHEDULES
17.1 SENIOR VICE PRESIDENT - FUEL SUPPLY
17.2 Fuel Supply Target Award Payment Schedule
Composited Change in Price of Purchased Coal as Percent
of GDP Price Index (Fixed Weight)
<TABLE>
<CAPTION>
Percent of GDP Price Index Performance Factor*
<S> <C>
60 or lower 1.50
70 1.25
80 1.00
100 .50
110 .25
Higher than 110 0
*Interpolate at intermediate performance.
Example: If the average percentage increase in the price of purchased coal is 85%
of the GDP price index, the performance factor is .875.
</TABLE>
17.3 VICE PRESIDENT - FUEL PROCUREMENT
17.4 Fuel Supply Target Award Payment Schedule
Composited Change in Price of Purchased Coal as
Percent of GDP Price Index (Fixed Weight)
<TABLE>
<CAPTION>
Percent of GDP Price Index Performance Factor*
<S> <C>
60 or lower 1.50
70 1.25
80 1.00
100 .50
110 .25
Higher than 110 0
*Interpolate at intermediate performance.
Example: If the average percentage increase in the price of purchased coal is 85%
of the GDP price index, the performance factor is .875.
</TABLE>
17.5 Fuel Supply Target Award Payment Schedule
Sum Total of PV Benefits
Special Contract Renegotiations
<TABLE>
<CAPTION>
PV Benefits
Total Dollars Performance Factor*
<S> <C>
$64 million or higher 1.50
$32 million 1.25
$16 million 1.00
$8 million .75
$4 million .50
$2 million .25
0 0
*Interpolate at intermediate performance.
</TABLE>
Example: If the sum total of PV benefits from special
contract negotiations were $1.6 million, the performance
factor would be 0.20.
17.6 GENERAL MINE MANAGERS/GENERAL SUPERINTENDENT (MEIGS)
17.7 Southern Ohio Coal Company - Meigs
Adjusted Cost of Coal Produced
<TABLE>
<CAPTION>
<cent>/MM BTU Performance Factor*
<S> <C>
173.6 or lower 1.50
175.6 1.25
177.6 1.00
179.6 .75
181.6 .50
183.6 .25
185.6 or higher 0
*Interpolate at intermediate performance.
</TABLE>
17.8 Central Ohio Coal Company
Adjusted Cost of Coal Produced
<TABLE>
<CAPTION>
<cent>/MM BTU Performance Factor*
<S> <C>
207.8 or lower 1.50
209.8 1.25
211.8 1.00
213.8 .75
215.8 .50
217.8 .25
219.8 or higher 0
*Interpolate at intermediate performance.
</TABLE>
17.9 Windsor Coal Company
Adjusted Cost of Coal Produced
<TABLE>
<CAPTION>
<cent>/MM BTU Performance Factor*
<S> <C>
168.6 or lower 1.50
170.6 1.25
172.6 1.00
174.6 .75
176.6 .50
178.6 .25
180.6 or higher 0
*Interpolate at intermediate performance.
</TABLE>
17.10 All Coal Mines
Safety Incidence Rate
<TABLE>
<CAPTION>
Incidence Rate - Percent Industry Rate Performance Factor*
<S> <C>
55 or lower 1.50
65 1.25
75 1.00
85 .75
90 .50
95 .25
Higher than 95 0
*Interpolate at intermediate performance.
</TABLE>
17.11 MANAGER - RIVER TRANSPORTATION
17.12 River Transportation
Operating Cost Per Ton Mile
<TABLE>
<CAPTION>
Mils/Ton Mile
($.00x) Performance Factor*
<S> <C>
3.544 or lower 1.50
3.681 1.25
3.818 1.00
3.955 .75
4.092 .50
4.229 .25
4.366 or higher 0
*Interpolate at intermediate performance.
</TABLE>
17.13 River Transportation
Safety Incidence Rate
<TABLE>
<CAPTION>
Incidence Rate - % Industry Rate Performance Factor*
<S> <C>
55 or lower 1.50
65 1.25
75 1.00
85 .75
90 .50
95 .25
Higher than 95 0
*Interpolate at intermediate performance.
</TABLE>
17.14 MANAGER - COOK COAL TERMINAL
17.15 Cook Coal Terminal
Adjusted Expenses
<TABLE>
<CAPTION>
Adjusted Expenses Performance Factor*
<S> <C>
$7.30 million or better 1.50
$7.50 1.25
$7.70 1.00
$7.90 .75
$8.10 .50
$8.30 .25
$8.50 million or higher 0
*Interpolate at intermediate performance.
</TABLE>
17.16 Cook Coal Terminal
Safety Incidence Rate
<TABLE>
<CAPTION>
Incidence Rate - % Industry Rate Performance Factor*
<S> <C>
55 or better 1.50
65 1.25
75 1.00
85 .75
90 .50
95 .25
Higher than 95 0
*Interpolate at intermediate performance.
</TABLE>
17.17 MANAGING DIRECTOR - TRANSPORTATION
17.18 Cook Coal Terminal
Adjusted Expenses
<TABLE>
<CAPTION>
Adjusted Expenses Performance Factor*
<S> <C>
$7.30 million or better 1.50
$7.50 1.25
$7.70 1.00
$7.90 .75
$8.10 .50
$8.30 .25
$8.50 million or higher 0
*Interpolate at intermediate performance.
</TABLE>
17.19 River Transportation
Operating Cost Per Ton Mile
<TABLE>
<CAPTION>
Mils/Ton Mile ($.00x) Performance Factor*
<S> <C>
3.544 or lower 1.50
3.681 1.25
3.818 1.00
3.955 .75
4.092 .50
4.229 .25
4.366 or higher 0
*Interpolate at intermediate performance.
</TABLE>
17.20 Composited Change in Purchased Coal As
Percent of GDP Price Index (Fixed Weight)
<TABLE>
<CAPTION>
PERCENT OF GDP PRICE INDEX (FIXED WEIGHT) PERFORMANCE FACTOR*
<S> <C>
60 or lower 1.50
70 1.25
80 1.00
100 .50
110 .25
Higher than 110 0
</TABLE>
*Interpolate at intermediate performance
Example: If the average percentage increase in the price of purchased coal
is 85% of the GDP Price Index, the performance factor is .875.
17.21 River Transportation and Cook Coal Terminal
Safety Incidence Rate
<TABLE>
<CAPTION>
INCIDENCE RATE - % INDUSTRY RATE PERFORMANCE FACTOR*
<S> <C>
55 or lower 1.50
65 1.25
75 1.00
85 .75
90 .50
95 .25
Higher than 95 0
</TABLE>
*Interpolate at intermediate performance
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
<TABLE>
<CAPTION>
Year Ended December 31, 1995 1994 1993 1992 1991
<S> <C> <C> <C> <C> <C>
INCOME STATEMENTS DATA
(in millions):
Operating Revenues $5,670 $5,505 $5,269 $5,045 $5,047
Operating Income 965 932 929 883 918
Net Income 530 500 354 468 498
<CAPTION>
December 31, 1995 1994 1993 1992 1991
<S> <C> <C> <C> <C> <C>
BALANCE SHEETS DATA (in millions):
Electric Utility Plant $18,496 $18,175 $17,712 $17,509 $17,148
Accumulated Depreciation
and Amortization 7,111 6,827 6,612 6,281 5,952
Net Electric Utility Plant $11,385 $11,348 $11,100 $11,228 $11,196
Total Assets $15,902 $15,739 $15,362 $14,217 $13,824
Common Shareholders' Equity 4,340 4,229 4,151 4,245 4,221
Cumulative Preferred Stocks
of Subsidiaries:
Not Subject to Mandatory Redemption 148 233 268 535 535
Subject to Mandatory Redemption* 523 590 501 234 141
Long-term Debt* 5,057 4,980 4,995 5,311 5,029
Obligations Under Capital Leases* 405 400 284 300 273
*Including portion due within one year
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31, 1995 1994 1993 1992 1991
<S> <C> <C> <C> <C> <C>
COMMON STOCK DATA:
Earnings per Share $2.85 $2.71 $1.92 $2.54 $2.70
Average Number of Shares
Outstanding (in thousands) 185,847 184,666 184,535 184,535 184,535
Market Price Range: High $40-5/8 $37-3/8 $40-3/8 $35-1/4 $34-1/4
Low 31-1/4 27-1/4 32 30-3/8 26-5/8
Year-end Market Price 40-1/2 32-7/8 37-1/8 33-1/8 34-1/4
Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio 84.1% 88.6% 125.2% 94.6% 88.9%
Book Value per Share $23.25 $22.83 $22.50 $23.01 $22.88
</TABLE>
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Business Conditions
The prospect for market driven rates is powering a movement to introduce
direct competition to the generation function of the electric utility
industry. As a result we expect that competition will be a factor
influencing AEP s future results of operations. Other important factors that
could affect future results of operations are environmental laws, affiliated
coal mining costs, nuclear fuel storage and disposal costs and nuclear
decommissioning costs. Management will be working to prepare for a
transition to greater competition and to manage the other major factors that
could impact future results of operations.
Competition at the Wholesale Level
The Energy Policy Act of 1992 (Energy Act) was designed, among other
things, to foster competition in the wholesale market through amendments to
(a) the Public Utility Holding Company Act, facilitating the ownership and
operation of generating facilities by independent power producers including
non-electric utilities and (b) the Federal Power Act, authorizing the Federal
Energy Regulatory Commission (FERC) under certain conditions to order
utilities which own transmission facilities to provide wholesale transmission
services to other utilities and entities generating electric power. While
the Energy Act gave the FERC broad authority to mandate transmission access
in the wholesale market, it prohibited the FERC from ordering retail
transmission access.
Customer Choice
The demand for customer choice of electric supplier is mainly coming
from large industrial energy users. Transmission access in the retail
marketplace will allow an electric customer within a particular utility s
service territory to buy power directly from another source using the power
lines of the local electric utility for delivery.
Financial Implications of Competition
A significant expansion of competition in the generation of electricity
would require the resolution of many complex issues, including the obligation
to serve and the recovery of stranded costs which, if not properly addressed,
could adversely impact future results of operations and possibly the
financial condition of electric utilities.
Stranded costs occur when a customer switches to a new supplier for its
electric energy needs creating the issue of who pays for plant investment,
purchased power or fuel contracts both non-affiliated and affiliated,
inventories, construction work in progress, nuclear decommissioning costs,
and other investments and commitments that are no longer needed, economic or
recoverable in a competitive market. The amount of any losses the Company
may experience from stranded costs depends on the extent to which direct
competition is introduced to its business and the market price of energy.
Cost-based regulation traditionally results in the recognition of
revenues and expenses in accordance with rate commission orders which can
result in revenue and expense recognition in different time periods than for
enterprises that are not regulated. As a result, regulatory assets have been
recorded by regulated utility companies representing the deferral of costs
for recovery in future periods. The Company has approximately $2 billion in
regulatory assets. In order to maintain regulatory assets, the Company s
rates must be cost- based regulated. Management has reviewed the evidence
currently available and concluded that AEP continues to meet the requirements
to apply rate-regulated accounting standards. In the event a portion of the
Company s business no longer met these requirements, regulatory assets would
have to be written off for that portion of the business.
Whether future results of operations are adversely affected by losses or
write-offs also will depend on whether and how equitable recovery is
provided for by the applicable regulators. We intend to seek appropriate
recovery of any stranded costs and regulatory assets.
AEP s Response to Competitive Pressures
AEP has the financial strength, geographic reach,location and cost
structure to be an able competitor. However, no assurance can be given that
AEP can maintain this position in the future.
In 1995 AEP took steps to prepare for competition by realigning into
functional business units, expanding our marketing and customer service
efforts and proposing a plan for an orderly transition to retail competition.
Previously, AEP had proposed open access transmission rates.
In order to better position AEP for increasing competition among
electricity suppliers, we realigned from separate operating company
organizations to distinct Power Generation, Nuclear Generation, Energy
Delivery and Corporate Development operating units. We are realigning into
separate functional units in order (a) to facilitate the unbundling of
electric services to the extent required or permitted by the evolving
regulatory structure and (b) to operate more efficiently and effectively to
meet customers needs. The legal, financial, rate and regulatory
relationships of the subsidiary operating companies will not change.
To facilitate reliable, safe and efficient access for customers, AEP
supports the creation of an Independent System Operator (ISO) to operate a
multi-state transmission grid. Under AEP s proposal each electric company,
while retaining ownership, would place its portion of the transmission grid
under the management of the ISO who would be responsive to the needs of all
parties using the transmission grid. AEP also supports the evolution of a
Regional Power Exchange, which would establish a competitive marketplace for
generation. Generators and resellers of electricity would be permitted to
sell power into a spot market operated by the Regional Power Exchange. The
Regional Power Exchange would accept offers to buy and sell power and would
settle transactions based on the price at which supply and demand are
balanced. State regulators would continue to determine the terms, standards
and prices for the delivery service. Under our proposed plan regulators
would be authorized to establish distribution service charges which would
provide, as appropriate, for the recovery of stranded costs and regulatory
assets. These charges would be collected by electric companies from all new
and existing distribution services customers within a company s service
territory.
AEP has also offered access to its transmission grid at 142
interconnections under the same costs and terms available to AEP itself. The
unbundled transmission service for wholesale customers will provide AEP with
greater opportunities for transmission service revenues. Also, AEP has
responded to its retail customers by introducing new rate designs
(interruptible buy-through and real-time pricing) to provide lower cost-based
rates, to meet specific customers needs, and to offer customer choice.
AEP's proposals to pave the way for retail competition were issued to
enable the Company to participate in a meaningful way in the debate with
other interested parties so that we can build consensus and form coalitions
to shape the form of the future playing field. We plan to enhance
shareholder value by making AEP the supplier of choice. Our success will
depend on our ability to obtain a level playing field, improve and expand on
our energy sales and services and maintain and improve our relatively low
cost structure.
New Business Opportunities
We continue to seek and consider new business opportunities,
particularly those which permit the use of our expertise and core
competencies. In the non-rate-regulated environment, AEP offers consulting
services both domestically and internationally and contracts with other
public utilities and government agencies for the licensing of intellectual
property and the delivery of energy services. In addition, AEP is pursuing
investments in power generation, transmission and distribution projects. In
1995 AEP announced a strategic alliance with Cogentrix Energy and Zurn
Industries to pursue industrial power projects in the United States and
Canada. Cogentrix is one of the largest independent power producers in the
U.S., while Zurn is the largest turnkey engineer and constructor of both
biomass power plants and mid-sized gas turbine combined cycle plants in the
U.S.
AEP has been pursuing several other possible power generation,
transmission and distribution investment projects overseas. These investment
opportunities offer the potential for earning returns which exceed those of
the domestic rate-regulated operations. However, they also involve a higher
degree of risk which must be carefully considered and assessed. AEP may make
investments in these and other new business opportunities after management
carefully assesses the risks involved versus the potential for enhanced
shareholder value. Appropriate new business investments are part of AEP s
strategic plan for enhancing shareholder value and will be the full time
responsibility of our newly formed corporate development operating unit.
Affiliated Coal Cost
Fuel is 80% of the production cost of electricity. Although our fuel
costs have declined by one half in constant dollars since 1986, we must
continue to manage our coal costs to effectively compete. As long-term
contracts expire we are negotiating with suppliers to lower purchased coal
costs. We will continue to supplement our affiliated and long-term coal
supplies with spot market coal as favorable market conditions permit.
Approximately 13% of the coal we burn is supplied by affiliated mines; the
remainder is acquired under long-term contracts and in the spot market.
Efforts continue to reduce the cost of affiliated coal.
In recent years Ohio Power Company (OPCo) has been limited in its
recovery of the cost of coal produced by its affiliated mines in its Ohio
jurisdiction. Under the terms of a 1992 stipulation agreement a
predetermined price of $1.575 per million Btu s for coal burned at the Gavin
Plant was established effective December 1, 1994 for a 15-year period subject
to adjustment for inflation. A subsequent Settlement Agreement sets an
overall predetermined electric fuel component rate for OPCo at 1.465 cents
per kwh for the period June 1, 1995 through November 30, 1998. The Gavin
Plant predetermined price remains effective as escalated from the original
$1.575 per million Btu s. 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 prices provide OPCo with an opportunity to accelerate
recovery of its Ohio jurisdictional investment in and liabilities and closing
costs of the Company s Meigs, Muskingum and Windsor mining operations to the
extent the actual cost of coal burned at the Gavin Plant is less than the
predetermined prices. Based on the estimated future cost of coal at Gavin
Plant, we believe that OPCo should be able to recover under the terms of the
1992 stipulation agreement and in conjunction with the Settlement Agreement,
the Ohio jurisdictional portion of the cost of the affiliated mining
operations including mine closure costs. Management intends to seek from
ratepayers recovery of the non-Ohio jurisdictional portion of the investment
in and the liabilities and closing costs of the affiliated Meigs, Muskingum
and Windsor mines. The non-Ohio jurisdictional portion of shutdown costs for
these mines which includes the investment in the mines, leased asset buy-
outs, reclamation costs and employee benefits is estimated to be
approximately $195 million after tax at December 31, 1995. The affiliated
Muskingum and Windsor mines may have to close by January 2000 as part of
compliance with Phase II requirements of the Clean Air Act Amendments of
1990. Should it become apparent that the costs of the affiliated mines
including future mine closure costs will not be recoverable, the mines could
be closed and results of operations adversely affected.
Nuclear Cost
The Company s only nuclear plant, the Donald C. Cook Nuclear Plant, has
recently achieved a superior rating from the Institute of Nuclear Power
Operations, a nuclear industry oversight group, and received improved
Nuclear Regulatory Commission (NRC) performance ratings. Refueling outage
costs have been reduced by $20 million compared to 1992 outage expense
levels. In an effort to continue to reduce costs and enhance organizational
efficiency, we announced in November that during the summer of 1996 we will
consolidate our Columbus-based nuclear management and support staff with the
plant staff at or near the Cook Nuclear Plant in Bridgman, Michigan.
The cost to operate and maintain the two-unit Cook Nuclear Plant is
impacted by federal laws and NRC requirements. The Nuclear Waste Policy Act
of 1982 established federal responsibility for the permanent off-site
disposal of spent nuclear fuel and high-level radioactive waste. By law we
participate in the Department of Energy s (DOE s) Spent Nuclear Fuel (SNF)
disposal program which is described in Note 4 of the Notes to Consolidated
Financial Statements. Since 1983 our consumers of nuclear generated
electricity have paid $237 million for the disposal of spent nuclear fuel
consumed at the Cook Nuclear Plant. Under the provisions of the Nuclear
Waste Policy Act, collections from customers are to provide the DOE with
money to build a permanent repository for spent fuel. The federal
government has not made sufficient progress towards a permanent repository
and as long as there is a delay in the permanent storage repository for spent
nuclear fuel, the cost of a temporary or permanent repository will continue
to increase.
The cost to decommission the Cook Plant is affected by NRC regulations
and the DOE s SNF disposal program. Studies completed in 1994 estimate the
cost to decommission the plant and dispose of low-level nuclear waste
accumulation to range from $634 million to $988 million in 1993 dollars. The
decommissioning estimate could escalate due to uncertainty in the DOE s SNF
disposal program and the length of time that SNF may need to be stored at the
plant site delaying decommissioning. Presently we are recovering the
estimated cost of decommissioning the Cook Plant over its remaining life.
However, AEP s future results of operations and possibly its financial
condition could be adversely affected if the cost of spent nuclear fuel
disposal and decommissioning continues to increase and if for some reason
such costs cannot be recovered.
Environmental Concerns
Clean Air Act
To comply with the Clean Air Act Amendments of 1990 (CAAA) which
requires substantial reductions in sulfur dioxide and nitrogen oxides emitted
from electric generating plants, an AEP System wide least-cost compliance
plan was developed reflecting various methods of compliance. The corner
stone of the compliance strategy is the installation of flue gas
desulfurization systems (scrubbers) on the two-unit Gavin Plant which has
been responsible for about 25% of the System s total sulfur dioxide
emissions. By selecting scrubbers, the compliance plan allows the use of
Ohio high-sulfur coal at the Gavin Plant. The scrubbers for the Gavin units
are completed and operational. The PUCO approved the compliance plan as the
least cost compliance strategy and approved recovery of the compliance costs
under the terms of the Settlement Agreement.
Through the CAAA emission allowance program in which utilities are
authorized to emit a designated quantity of sulfur dioxide, measured in tons
per year, AEP, on a system wide or aggregate basis, will bank a substantial
number of Phase I allowances due to over compliance. To meet the stricter
standards of Phase II of the CAAA, AEP has the option to use banked Phase I
allowances, buy low sulfur com-pliance coal, purchase additional allowances
and/or build additional scrubbers. We also have the option to sell Phase I
allowances saved due to the installation of the scrubbers and the acquisition
of low sulfur coal.
Hazardous Material
By-products from the generation of electricity include materials such as
ash, slag, sludge, low-level radioactive waste and spent nuclear fuel. Coal
combustion by-products, which constitute the overwhelming percentage of these
materials, are typically disposed of or treated in captive disposal
facilities or are beneficially utilized. In addition, the AEP generating
plants and transmission and distribution facilities have used asbestos,
polychlorinated biphenyls (PCBs) and other hazardous and non-hazardous
materials. The AEP System is currently incurring costs to safely dispose of
such substances, and additional costs could be incurred to comply with new
laws and regulations if enacted.
The Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA or Superfund legislation) addresses clean-up of hazardous substances
at disposal sites and authorizes the United States Environmental Protection
Agency (Federal EPA) to administer the clean-up programs. As of year-end
1995, AEP companies are currently involved in litigation with respect to five
sites being overseen by the Federal EPA and have been named by the Federal
EPA as Potentially Responsible Parties (PRPs) for five other sites. There
are 11 additional sites for which AEP companies have received information
requests which could lead to PRP designation. Also, AEP companies have
received information requests with respect to four sites administered by
state authorities. AEP companies liability has been resolved for a number
of sites with no significant effect on results of operations. In those
instances where an AEP company has been named a PRP or defendant, the
disposal or recycling activity of the AEP company was in accordance with
applicable laws and regulations. CERCLA does not recognize compliance as a
defense, but imposes strict liability on parties who fall within its broad
statutory categories.
While the potential liability for each Superfund site must be evaluated
separately, several general statements can be made regarding such potential
liability. The disposal at a particular site by the AEP companies is often
unsubstantiated; the quantity of material the AEP companies disposed of at a
site was generally small; and the nature of the material AEP generally
disposed of was non-hazardous. Typically, an AEP subsidiary is one of
many parties named as PRPs for a site and,
although liability is joint and several, generally some of the other parties
are financially sound enterprises. Therefore, AEP s present estimates do not
anticipate material cleanup costs for identified sites for which AEP
subsidiaries have been declared PRPs. However, if for reasons not currently
identified significant costs are incurred for cleanup, future results of
operations and possibly financial condition would be adversely affected
unless the costs can be recovered.
Results of Operations
Earnings Increase
The 6% increase in net income to $530 million or $2.85 per share for
1995 from $500 million or $2.71 per share in 1994 was primarily due to
increased energy sales. Total sales of energy were 120.7 billion
kilowatthours in 1995 compared with 116.7 billion kilowatthours in 1994
reflecting increased usage and additional customers. Unseasonably warm
weather in the summer of 1995 and colder weather in the fourth quarter of
1995, compared with milder weather in the prior year s fourth quarter, were
the primary factors causing the increased usage. The positive earnings
impact of the increased sales was partly offset by the unfavorable effect of
$27 million in after-tax expenses related to severance pay charges.
In 1994 earnings increased 41% to $500 million or $2.71 per share from
$354 million or $1.92 per share in 1993. The increase was due to the effect
of a $145 million after-tax loss recorded in 1993 as a result of a
disallowance of a portion of the Company's Zimmer Plant investment. Without
the disallowance, 1993 earnings and earnings per share would have been $498
million and $2.70, respectively. Excluding the disallowance, 1994 earnings
increased slightly as compared to 1993 earnings predominately due to the
favorable effect of rate increases in several jurisdictions which were
heavily offset by the related amortization of Zimmer Plant deferrals and
increased operating expenses largely as a result of significant storm damage.
<PAGE>
<PAGE>
Revenues And Sales Increase
Operating revenues increased 3% in 1995 and more than 4% in 1994
reflecting increased energy usage by retail customers, growth in the number
of retail customers and the effects of rate increases. The change in
revenues is analyzed as follows:
<TABLE>
<CAPTION>
Increase (Decrease)
From Previous Year
(Revenues in Millions) 1995 1994
Amount % Amount %
<S> <C> <C> <C> <C>
Retail:
Price Variance $ 46.5 $ 90.7
Volume Variance 173.0 53.8
Fuel Cost
Recoveries (22.9) 40.5
196.6 4.2 185.0 4.1
Wholesale:
Price Variance (39.3) 68.6
Volume Variance 10.8 (49.7)
Fuel Cost Recoveries (4.6) 8.1
(33.1)(4.6) 27.0 3.9
Other Operating Revenues 2.2 23.8
Total $165.7 3.0 $235.8 4.5
</TABLE>
The increase in 1995 operating revenues resulted from a 4% increase in
energy sales to retail customers primarily due to increased usage and
continued growth in the number of customers in all retail customer classes.
Energy sales to residential customers, which is the most weather-sensitive
customer class, rose over 6% in 1995 mainly as a result of increased weather
related usage in the last half of the year. Sales to commercial and
industrial customers rose 5% and 2%, respectively, reflecting additional
customers, the effects of weather and the expanding economy.
Although revenues from wholesale customers declined in 1995, wholesale
energy sales increased by more than 1% largely due to increased sales made on
an hourly basis to unaffiliated utilities. This type of short-term sale is
typically made when the unaffiliated utility can purchase energy at a lower
cost than the cost at which that utility can generate the energy. Such sales
usually take place as a result of increased weather-related demand. The
increase in 1995 wholesale energy sales occurred during the last six months
of the year when the summer weather was unseasonably warm and fall
temperatures were colder compared with the prior year. While wholesale
energy sales increased, wholesale revenues declined in 1995 reflecting
increasing competition.
Although demand and generation increased, fuel cost revenues declined in
1995 due to operation of the fuel clause mechanisms.
Operating revenues increased in 1994 primarily due to increased revenues
from retail customers reflecting retail rate increases in several
jurisdictions and an increase in retail energy sales and fuel cost
recoveries. A 2% increase in retail energy sales in 1994 was offset by a 7%
decline in wholesale sales resulting in a slight decline in net energy sales.
The 2% increase in retail energy sales in 1994 resulted from growth in
the number of residential, commercial and industrial customers served and
increased usage by industrial and commercial customers. Energy sales to
residential customers remained constant in 1994 due to mild weather during
most of the year.
Wholesale revenues increased 4% in 1994, on a 7% decrease in sales,
reflecting an increase in take-or-pay capacity charges to unaffiliated
utilities. Capacity charges are to reserve a specified quantity of AEP
System generating capacity and must be paid even when the energy is not
taken. The increase in capacity charges resulted from increased capacity
reserved under a long-term contract and short-term contracts with
unaffiliated utilities in the summer of 1994 because of a forced generating
unit outage. The increase in capacity reservation did not lead to a
corresponding increase in energy sold in 1994 due to mild weather throughout
most of 1994. The mild weather in 1994, combined with increased competition
in the wholesale market, reduced short-term wholesale sales for 1994.
Fuel cost recoveries increased in 1994 in both the retail and wholesale
jurisdictions resulting from increased fuel costs.
Future levels of short-term wholesale sales will be affected by the
competitive nature of the short-term energy market and other factors, such as
unaffiliated generating plant availability, the weather and the economy, all
of which are not generally within management's control. The Company's future
results of operations will be affected by its ability to make cost-effective
wholesale sales or, if such sales are reduced, the ability to raise retail
rates to reflect the loss of wholesale sales credits.
Future results of operations also will depend in part on the weather
since sales to residential and commercial customers are weather-sensitive.
<PAGE>
Operating Expenses Increase
Changes in the components of operating expenses are shown in the table.
<TABLE>
<CAPTION>
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1995 1994
Amount % Amount %
<S> <C> <C> <C> <C>
Fuel and Purchased Power $(119.7) (6.9) $ 97.7 5.9
Other Operation 181.3 18.1 31.9 3.3
Maintenance (2.4) (0.5) 21.2 4.1
Depreciation and Amortization 20.8 3.6 41.5 7.8
Taxes Other Than Federal Income
Taxes (5.0) (1.0) 25.9 5.5
Federal Income Taxes 58.6 27.5 13.8 6.8
Total $ 133.6 2.9 $232.0 5.3
</TABLE>
Although generation increased 3% in 1995, fuel and purchased power
expense declined as a result of a decrease in the average cost of fossil fuel
resulting from reduced coal prices reflecting the renegotiation of certain
long-term coal contracts and other lower priced purchases under existing and
new contracts. Other factors which reduced fuel and purchased power expense
were increased utilization of low-cost nuclear generation in 1995; operation
of fuel clause mechanisms; and decreased energy purchases due to the mild
weather during the first half of 1995. Changes in fuel expense are generally
deferred pending recovery in various fuel recovery mechanisms, and as such
they generally do not affect earnings.
The increase in fuel and purchased power expense in 1994 was mainly the
result of increased utilization of coal-fired generation while the Cook Plant
nuclear units were unavailable during refueling and maintenance outages in
1994, and increased purchases of energy from unaffiliated utilities for pass-
through sales to other unaffiliated utilities.
The significant increase in other operation expense during 1995 was
primarily due to rent and other operating costs of the Gavin Plant scrubbers
which went into service in December 1994 and the first quarter of 1995; a $41
million ($27 million after-tax) provision for severance pay recorded in 1995
related mainly to a functional realignment of operations; and costs related
to the development of a new activity based budgeting system. Other operation
expense increased in 1994 as a result of regulatory-approved increases in
accruals and amortization, concurrent with rate recovery, of nuclear plant
decommissioning expense and certain low-income residential customers' payment
programs.
Maintenance expense increased in 1994 due to significant storm damage
caused by snow and ice storms during the first three months of 1994.
The increase in depreciation and amortization expense in 1994 was
primarily due to the court-ordered discontinuance of the Zimmer Plant phase-
in plan deferrals effective in February 1994 and the subsequent monthly
amortization of such costs as they were recovered in rates.
Taxes other than federal income tax expense rose in 1994 mainly due to
an increase in revenue-based gross receipts taxes of several states
reflecting the increase in 1994 revenues and an increase in generation-based
West Virginia taxes reflecting an increase in generation at West Virginia
power plants in 1994. Effective June 1995, the West Virginia tax is based on
generating capacity in West Virginia rather than on generation in West
Virginia which will result in a less volatile level of West Virginia taxes.
The increase in 1995 federal income tax expense attributable to
operations was primarily due to an increase in pre-tax operating income;
changes in certain book/tax differences accounted for on a flow-through basis
and the effects of accrual adjustments for prior year tax returns. The 1994
increase was mainly due to an increase in pre-tax operating income.
Deferred Carrying Charges and Nonoperating Income
The decrease in deferred Zimmer Plant carrying charges in 1995 and 1994
resulted from the cessation of deferrals commensurate with inclusion of the
full plant investment in rate base effective February 1, 1994 and the monthly
reduction in the deferred balance on which a return is earned. The deferred
balance declined due to its amortization to depreciation and amortization
expense commensurate with recovery through a rate surcharge.
The increase in other nonoperating income in 1995 and the decrease in
1994 was mainly due to the 1994 recordation of a provision for loss of $8.2
million after-tax on an investment. Also contributing to the 1994 decrease
was the effect of interest income recorded in March 1993 on tax refunds from
the Internal Revenue Service (IRS) in connection with the settlement of
audits of prior years' tax returns.
Interest Charges Increase
Interest charges increased in 1995 mainly due to an increase in interest
on short-term debt resulting from a higher average interest rate in 1995 on
larger levels of outstanding short-term debt during the year. Refinancing
programs of several subsidiaries during the early part of 1994 and 1993
reduced the average interest rate on outstanding
long-term debt in 1994 as well as the levels of long-term debt causing the
decline in interest expense in 1994.
Common Dividend Remains Constant, Payout Ratio Decreases
The Company paid a quarterly dividend in 1995 of 60 cents a share
maintaining the annual dividend rate at $2.40 per share. The payout ratio
improved to 84% in 1995 from 89% in 1994. In 1993 the payout ratio was also
89% before the Zimmer disallowance.
Construction Spending Declining
Construction expenditures have been declining in recent years.
Management estimates cumulative construction expenditures for utility
operation to be $2 billion over the next three years with no major new plant
construction planned. Approximately 80% of the construction expenditures for
the next three years will be financed internally.
Liquidity and Capital Resources
The operating subsidiaries generally issue short-term debt to provide
for interim financing of capital expenditures that exceed internally
generated funds. They periodically reduce their outstanding short-term debt
through issuances of long-term debt and preferred stock and with additional
capital contributions by the parent company. In 1995 short-term borrowing
increased by $48 million. At December 31, 1995, American Electric Power and
its subsidiaries had unused short-term lines of credit of $372 million. The
sources of funds available to the parent company are dividends from its
subsidiaries, short-term and long-term borrowings and, when necessary,
proceeds from the issuance of common stock. American Electric Power issued
1,400,000 shares of common stock in 1995 and 700,000 in 1994 through a
Dividend Reinvestment Program raising $49 million and $22 million,
respectively. As a result of the common stock issuance in 1995 and 1994 and
a reduction in long-term debt over the past several years, the common equity
to capitalization ratio has steadily improved. At December 31,1995 the ratio
increased to 43.1% from 42.1% at year end 1994 and has improved from 41.1% in
1992.
At December 31, 1995 the subsidiaries had outstanding $5.06 billion of
long-term debt and $671 million of preferred stock. The subsidiaries have
regulatory approval to issue up to $1.2 billion of long-term debt.
Management expects to use the proceeds of future long-term financing to
retire short-term debt, refinance maturing and other long-term debt, refund
cumulative preferred stock and fund construction expenditures.
<PAGE>
Principal Operating Subsidiaries
Debt & Preferred Stock Coverage
<TABLE>
<CAPTION>
Mortgage Preferred
December 31, 1995 Debt Stock
<S> <C> <C>
Appalachian Power Co. 3.47 1.78
Columbus Southern Power Co. 3.90 N/A
Indiana Michigan Power Co. 6.25 2.63
Kentucky Power Co. 2.86 N/A
Ohio Power Co. 6.17 3.04
N/A - Not Applicable
</TABLE>
Unless the subsidiaries meet certain earnings or coverage tests, they
cannot issue additional mortgage bonds or preferred stock. In order to issue
mortgage bonds (without refunding existing debt), each subsidiary must have
pre-tax earnings equal to at least two times the annual interest charges on
mortgage bonds after giving effect to the issuance of the new debt.
Generally, issuance of additional preferred stock requires an after-tax gross
income at least equal to one and one-half times annual interest and preferred
stock dividend requirements after giving effect to the issuance of the new
preferred stock. The subsidiaries presently exceed these minimum coverage
requirements.
Litigation
AEP is involved in a number of legal proceedings and claims. While we
are unable to predict the outcome of such litigation, it is not expected that
the ultimate resolution of these matters will have a material adverse effect
on the results of operations and/or financial condition.
Effects of Inflation
Inflation affects AEP s cost of replacing utility plant and the cost of
operating and maintaining its plant. The rate-making process limits our
recovery to the historical cost of assets resulting in economic losses when
the effects of inflation are not recovered from customers on a timely basis.
However, economic gains that results from the repayment of long-term debt
with inflated dollars partly offset such losses.
New Accounting Rules
The Financial Accounting Standards Board (FASB) issued a new accounting
standard, SFAS 121 Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of, in 1995 effective for 1996
accounting periods. The initial implementation of this new standard is not
expected to have a significant impact on the Company.
In 1996 the FASB issued an exposure draft Accounting for Certain
Liabilities Related to Closure or Removal of Long-Lived Assets. This
document proposes that the present value of any decommissioning or other
closure or removal obligation be recorded as a liability when the obligation
is incurred. A corresponding asset would be recorded in the plant investment
account and recovered through depreciation charges over the asset s life. A
proposed transition rule would require that an entity report in income the
cumulative effect of initially applying the new standard. The Company is
currently studying the impact of the proposed rules and evaluating its
potential impact.
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands - except per share amounts)
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994 1993
<S> <C> <C> <C>
OPERATING REVENUES $5,670,330 $5,504,670 $5,268,842
OPERATING EXPENSES:
Fuel and Purchased Power 1,625,531 1,745,245 1,647,573
Other Operation 1,184,158 1,002,822 970,916
Maintenance 541,825 544,312 523,062
Depreciation and Amortization 593,019 572,189 530,731
Taxes Other Than Federal Income Taxes 489,223 494,210 468,296
Federal Income Taxes 272,027 213,399 199,621
TOTAL OPERATING EXPENSES 4,705,783 4,572,177 4,340,199
OPERATING INCOME 964,547 932,493 928,643
NONOPERATING INCOME:
Deferred Zimmer Plant Carrying Charges (net of tax) 3,089 5,604 25,343
Other Nonoperating Income 17,115 5,881 21,229
TOTAL NONOPERATING INCOME 20,204 11,485 46,572
LOSS FROM ZIMMER PLANT DISALLOWANCE:
Disallowed Cost - - 159,067
Related Income Taxes - - (14,534)
NET ZIMMER LOSS - - 144,533
INCOME BEFORE INTEREST CHARGES AND
PREFERRED DIVIDENDS 984,751 943,978 830,682
INTEREST CHARGES (net) 400,077 389,240 418,064
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES 54,771 54,726 58,849
NET INCOME $ 529,903 $ 500,012 $ 353,769
AVERAGE NUMBER OF SHARES OUTSTANDING 185,847 184,666 184,535
EARNINGS PER SHARE $2.85 $2.71 $1.92
CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(in thousands)
<CAPTION>
Year Ended December 31,
1995 1994 1993
<S> <C> <C> <C>
RETAINED EARNINGS JANUARY 1 $1,325,581 $1,269,283 $1,358,800
NET INCOME 529,903 500,012 353,769
DEDUCTIONS:
Cash Dividends Declared 445,831 443,101 442,891
Other 8 613 395
RETAINED EARNINGS DECEMBER 31 $1,409,645 $1,325,581 $1,269,283
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994 1993
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net Income $ 529,903 $ 500,012 $ 353,769
Adjustments for Noncash Items:
Depreciation and Amortization 578,003 561,188 555,436
Deferred Federal Income Taxes 11,916 (16,033) (62,186)
Deferred Investment Tax Credits (25,819) (31,275) (28,222)
Amortization of Operating Expenses and Carrying Charges (net) 53,479 16,022 2,997
Loss from Zimmer Plant Disallowance - - 159,067
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (71,804) 34,302 (15,641)
Fuel, Materials and Supplies 457 (1,627) 156,464
Accrued Utility Revenues (40,433) 2,419 18,994
Accounts Payable (31,044) (7,959) 47,018
Taxes Accrued 37,515 (26,521) 56,502
Other (net) 14,437 (52,803) 22,469
Net Cash Flows From Operating Activities 1,056,610 977,725 1,266,667
INVESTING ACTIVITIES:
Construction Expenditures (605,974) (643,457) (592,199)
Proceeds from Sale of Property and Other 20,567 49,802 26,669
Net Cash Flows Used For Investing Activities (585,407) (593,655) (565,530)
FINANCING ACTIVITIES:
Issuance of Common Stock 48,707 22,256 -
Issuance of Cumulative Preferred Stock - 88,787 321,168
Issuance of Long-term Debt 523,476 411,869 1,339,227
Retirement of Cumulative Preferred Stock (158,839) (35,949) (333,992)
Retirement of Long-term Debt (469,767) (445,636) (1,696,806)
Change in Short-term Debt (net) 48,140 38,009 25,822
Dividends Paid on Common Stock (445,831) (443,101) (442,891)
Net Cash Flows Used For Financing Activities (454,114) (363,765) (787,472)
Net Increase (Decrease) in Cash and Cash Equivalents 17,089 20,305 (86,335)
Cash and Cash Equivalents January 1 62,866 42,561 128,896
Cash and Cash Equivalents December 31 $ 79,955 $ 62,866 $ 42,561
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In Thousands - Except Share Data)
<TABLE>
<CAPTION>
December 31,
1995 1994
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production $ 9,238,843 $ 9,172,766
Transmission 3,316,664 3,247,280
Distribution 4,184,251 3,966,442
General (including mining assets and nuclear fuel) 1,442,086 1,529,436
Construction Work in Progress 314,118 258,700
Total Electric Utility Plant 18,495,962 18,174,624
Accumulated Depreciation and Amortization 7,111,123 6,826,514
NET ELECTRIC UTILITY PLANT 11,384,839 11,348,110
OTHER PROPERTY AND INVESTMENTS 825,781 747,422
CURRENT ASSETS:
Cash and Cash Equivalents 79,955 62,866
Accounts Receivable:
Customers (less allowance for uncollectible accounts of
$5,430 in 1995 and $4,056 in 1994) 417,854 346,462
Miscellaneous 74,429 74,017
Fuel - at average cost 271,933 306,700
Materials and Supplies - at average cost 251,051 216,741
Accrued Utility Revenues 207,919 167,486
Prepayments and Other 98,717 94,786
TOTAL CURRENT ASSETS 1,401,858 1,269,058
REGULATORY ASSETS 1,979,446 2,040,997
DEFERRED CHARGES 310,377 333,169
TOTAL $15,902,301 $15,738,756
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31,
1995 1994
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock-Par Value $6.50:
1995 1994
Shares Authorized. .300,000,000 300,000,000
Shares Issued. . . .195,634,992 194,234,992
(8,999,992 shares were held in treasury) $ 1,271,627 $ 1,262,527
Paid-in Capital 1,658,524 1,640,661
Retained Earnings 1,409,645 1,325,581
Total Common Shareholders' Equity 4,339,796 4,228,769
Cumulative Preferred Stocks of Subsidiaries:*
Not Subject to Mandatory Redemption 148,240 233,240
Subject to Mandatory Redemption 515,085 590,300
Long-term Debt* 4,920,329 4,686,648
TOTAL CAPITALIZATION 9,923,450 9,738,957
OTHER NONCURRENT LIABILITIES 884,707 794,478
CURRENT LIABILITIES:
Preferred Stock and Long-term Debt Due Within One Year* 144,597 293,756
Short-term Debt 365,125 316,985
Accounts Payable 220,142 251,186
Taxes Accrued 420,192 382,677
Interest Accrued 80,848 88,916
Obligations Under Capital Leases 89,692 93,252
Other 304,466 281,124
TOTAL CURRENT LIABILITIES 1,625,062 1,707,896
DEFERRED INCOME TAXES 2,656,651 2,657,062
DEFERRED INVESTMENT TAX CREDITS 430,041 456,043
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 249,875 259,152
DEFERRED CREDITS 132,515 125,168
CONTINGENCIES (Note 4)
TOTAL $15,902,301 $15,738,756
*See Accompanying Schedules on pages 34 - 35.
</TABLE>
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies:
The American Electric Power System (AEP, AEP System or the Company) is a
public utility engaged in the generation, purchase, transmission and
distribution of electric power to over 2.9 million retail customers in its
seven state service territory which covers portions of Ohio, Michigan,
Indiana, Kentucky, West Virginia, Virginia and Tennessee. Electric power is
also supplied at wholesale to neighboring utility systems.
The organization of the AEP System consists of American Electric Power
Company, Inc., the parent holding company; seven electric utility operating
companies (utility subsidiaries); a generating subsidiary, AEP Generating
Company (AEPGEN); a service company, American Electric Power Service
Corporation (AEPSC); and three active coal-mining companies. The five
largest utility subsidiaries, which pool their generating and transmission
facilities and operate them as an integrated system, are:
- - Appalachian Power Company (APCo)
- - Columbus Southern Power Company (CSPCo)
- - Indiana Michigan Power Company (I&M)
- - Kentucky Power Company (KEPCo)
- - Ohio Power Company (OPCo)
The remaining two utility subsidiaries, Kingsport Power Company and
Wheeling Power Company, are distribution companies that purchase power from
APCo and OPCo, respectively. AEPSC provides management and professional
services to the AEP System. The active coal-mining companies are wholly-
owned by OPCo and sell substantially all of their production to OPCo. AEPGEN
has a 50% interest in the Rockport Plant which is comprised of two of the AEP
System's six 1,300 megawatt (mw) generating units.
Effective January 1, 1996, AEPSC and the seven utility subsidiaries
began operating as American Electric Power. There has been no change to the
legal names of these companies. The AEP System s operations are divided into
four major business units which are managed centrally by AEPSC. The four
business units are Power Generation, Nuclear Generation, Energy Delivery and
Corporate Development.
Rate Regulation - The AEP System is subject to regulation by the Securities
and Exchange Commission (SEC) under the Public Utility Holding Company Act of
1935 (1935 Act). The rates charged by the utility subsidiaries are approved
by the Federal Energy Regulatory Commission (FERC) or one of the state
utility commissions as applicable. The FERC regulates wholesale rates and the
state commissions regulate retail rates.
Principles of Consolidation - The consolidated financial statements include
American Electric Power Company, Inc. (AEPCo., Inc.) and its wholly-owned
subsidiaries consolidated with their wholly-owned subsidiaries. Significant
intercompany items are eliminated in consolidation.
Basis of Accounting - As the owner of cost-based rate-regulated electric
public utility companies, AEPCo., Inc.'s consolidated financial statements
reflect the actions of regulators that result in the recognition of revenues
and expenses in different time periods than enterprises that are not rate
regulated. In accordance with Statement of Financial Accounting Standards
(SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation,
regulatory assets and liabilities are recorded to reflect the economic
effects of regulation.
Use of Estimates - The preparation of these financial statements in
conformity with generally accepted accounting principles requires in certain
instances the use of management s estimates. Actual results could differ
from those estimates.
Utility Plant - Electric utility plant is stated at original cost and is
generally subject to first mortgage liens. Additions, major replacements and
betterments are added to the plant accounts. Retirements from the plant
accounts and associated removal costs, net of salvage, are deducted from
accumulated depreciation.
The costs of labor, materials and overheads incurred to operate and
maintain utility plant are included in operating expenses.
Allowance for Funds Used During Construction (AFUDC) - AFUDC is a noncash
nonoperating income item that is recovered over the service life of utility
plant through depreciation and represents the estimated cost of borrowed and
equity funds used to finance construction projects. The average rates used
to accrue AFUDC were 6.91%, 6.59%, and 5.84% in 1995, 1994 and 1993,
respectively.
Depreciation, Depletion and Amortization - Depreciation is provided on a
straight-line basis over the estimated useful lives of property other than
coal-mining property and is calculated largely through the use of composite
rates by functional class as follows:
Functional Class Composite
of Property Annual Rates
Production:
Steam-Nuclear 3.4%
Steam-Fossil-Fired 3.2% to 4.4%
Hydroelectric-Conventional
and Pumped Storage 2.5% to 3.2%
Transmission 1.7% to 2.7%
Distribution 3.4% to 4.2%
General 2.0% to 3.8%
The utility subsidiaries presently recover amounts to be used for
demolition of non-nuclear plant through depreciation charges included in
rates. Depreciation, depletion and amortization of coal-mining assets is
provided over each asset's estimated useful life, ranging up to 30 years, and
is calculated using the straight-line method for mining structures and
equipment. The units-of-production method is used for coal rights and mine
development costs based on estimated recoverable tonnages at a current
average rate of $1.07 per ton. These costs are included in the cost of coal
charged to fuel expense.
Cash and Cash Equivalents - Cash and cash equivalents include temporary cash
investments with original maturities of three months or less.
Sale of Receivables - Under an agreement that expires in 2000, CSPCo can sell
up to $50 million of undivided interests in designated pools of accounts
receivable and accrued utility revenues with limited recourse. As
collections reduce previously sold pools, interests in new pools are sold. At
December 31, 1995, 1994 and 1993, $50 million remained to be collected and
remitted to the buyer.
Operating Revenues - Revenues include the accrual of electricity consumed but
unbilled at month-end as well as billed revenues.
Fuel Costs - Fuel costs are matched with revenues in accordance with rate
commission orders. Generally in the retail jurisdictions, changes in fuel
costs are deferred or revenues accrued until approved by the regulatory
commission for billing to customers in later months. Wholesale
jurisdictional fuel cost changes are expensed and billed as incurred.
Levelization of Nuclear Refueling Outage Costs - Incremental operation and
maintenance costs associated with refueling outages at the Company s Donald
C. Cook Nuclear Plant (Cook Plant) are deferred for amortization over the
period (generally eighteen months) beginning with the commencement of an
outage until the beginning of the next outage.
Income Taxes - The Company follows the liability method of accounting for
income taxes as prescribed by SFAS 109, Accounting for Income Taxes. Under
the liability method, deferred income taxes are provided for all temporary
differences between book cost and tax basis of assets and liabilities which
will result in a future tax consequence. Where the flow-through method of
accounting for temporary differences is reflected in rates, regulatory assets
and liabilities are recorded in accordance with SFAS 71.
Investment Tax Credits - Investment tax credits have been accounted for under
the flow-through method except where regulatory commissions have reflected
investment tax credits in the rate-making process on a deferral basis.
Deferred investment tax credits are being amortized over the life of the
related plant investment.
Debt and Preferred Stock - Gains and losses on reacquired debt are deferred
and amortized over the remaining term of the reacquired debt in accordance
with rate-making treatment. If the debt is refinanced the reacquisition
costs are deferred and amortized over the term of the replacement debt
commensurate with their recovery in rates.
Debt discount or premium and debt issuance expenses are amortized over
the term of the related debt, with the amortization included in interest
charges.
Redemption premiums paid to reacquire preferred stock are deferred,
debited to paid-in capital and amortized to retained earnings in accordance
with rate-making treatment. The excess of par value over costs of preferred
stock reacquired to meet sinking fund requirements is credited to paid-in
capital.
Other Property and Investments - Securities held in trust funds for
decommissioning nuclear facilities and for the disposal of spent nuclear fuel
are recorded at market value in accordance with SFAS No. 115, Accounting for
Certain Investments in Debt and Equity Securities. Securities in the trust
funds have been classified as available-for-sale due to their long-term
purpose. Due to the rate-making process, adjustments for unrealized gains
and losses are not reported in equity but result in adjustments to regulatory
assets and liabilities.
Excluding the decommissioning and spent nuclear fuel disposal trust
funds, other property and investments are stated at cost.
Reclassifications - Certain prior-period amounts were reclassified to conform
with current-period presentation.
2. Rate Matters:
Base Rate Activity - In March 1995 a Settlement Agreement was approved by the
Public Utilities Commission of Ohio (PUCO) that resolved a July 1994 base
rate case and a pending electric fuel component (EFC) proceeding. Under the
terms of the Settlement Agreement, base rates increased by $66 million
annually in March 1995 which includes recovery of the cost of the flue gas
desulfurization systems (scrubbers) installed at the Gavin Plant; the EFC
rate is fixed at 1.465 cents per kwh from June 1995 through November 1998;
OPCo is provided with the opportunity to recover its Ohio jurisdictional
share of its investment in and the liabilities and the future shut-down costs
of its 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 (CAAA)
compliance plan as filed with the PUCO. The Settlement Agreement allows the
Company to continue to operate the affiliated Muskingum and Windsor mines.
Recovery of Fuel Costs - Under the terms of a 1992 stipulation agreement the
cost of coal burned at the Gavin Plant is subject to a 15-year predetermined
price of $1.575 per million Btu's with quarterly escalation adjustments
through November 2009. (As discussed above the Settlement Agreement fixes the
EFC factor at 1.465 cents per kwh for the period June 1, 1995 through
November 30, 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
stipulation agreement, in conjunction with the above-referenced Settlement
Agreement, provides OPCo with an opportunity to accelerate recovery of its
investment in and the liabilities and closing costs and any operating losses
incurred under the fixed EFC period of 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. Management
intends to seek from ratepayers recovery of the non-Ohio jurisdictional
portion of the investment in and the liabilities and closing costs of the
affiliated Meigs, Muskingum and Windsor mines. The non-Ohio jurisdictional
portion of shutdown costs for these mines which includes the investment in
the mines, leased asset buy-outs, reclamation costs and employee benefits is
estimated to be approximately $195 million after tax at December 31, 1995.
The affiliated Muskingum and Windsor mines may have to close by January
2000 as part of compliance with Phase II requirements of the CAAA. The
Muskingum and/or Windsor mines could close prior to January 2000 depending on
the economics of continued operation under the terms of the above Settlement
Agreement. Unless future shutdown costs and/or the cost of affiliated coal
production of the Meigs, Muskingum and Windsor mines can be recovered,
results of operations would be adversely affected.
<PAGE>
3. Effects of Regulation and Phase-In Plans:
The consolidated financial statements include assets and liabilities recorded
in accordance with regulatory actions to match expenses and revenues in cost-
based rates. The assets are expected to be recovered in future periods
through the rate-making process and the liabilities are expected to reduce
future cost recoveries. The Company has reviewed all the evidence currently
available and concluded that it continues to meet the requirements to apply
SFAS 71. In the event a portion of the Company s business no longer met
these requirements regulatory assets would have to be written off for that
portion of the business.
Regulatory assets and liabilities are comprised of the following:
<TABLE>
<CAPTION>
December 31,
1995 1994
(In Thousands)
<S> <C> <C>
Regulatory Assets:
Amounts Due From
Customers For
Future Income Taxes $1,446,485 $1,458,807
Rate Phase-in Plan
Deferrals 74,402 118,553
Unamortized Loss on
Reacquired Debt 109,551 108,777
Other 349,008 354,860
Total Regulatory Assets $1,979,446 $2,040,997
Regulatory Liabilities:
Deferred Investment
Tax Credits $430,041 $456,043
Other Regulatory
Liabilities* 86,347 76,468
Total Regulatory
Liabilities $516,388 $532,511
* Included in Deferred Credits on Consolidated Balance Sheets
</TABLE>
The rate phase-in plan deferrals are applicable to the Zimmer Plant
Unit and the Rockport Plant Unit 1. The Zimmer Plant is a 1,300 mw coal-
fired plant which commenced commercial operation in 1991. CSPCo owns 25.4%
of the plant with the remainder owned by two unaffiliated companies.
In May 1992 the PUCO issued an order providing for a phased in rate
increase of $123 million to be implemented in three steps over a two-year
period and disallowed $165 million 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 revenues in accordance with the law
and to provide a mechanism to recover the amounts deferred under the phase-in
order.
As a result of the ruling, 1993 net income was reduced by $144.5
million after tax to reflect the disallowance and in January 1994, the PUCO
approved a 7.11% rate increase effective February 1, 1994. The increase is
comprised of a 3.72% base rate increase to complete the rate increase phase-
in and a temporary 3.39% surcharge, which will be in effect until the
deferrals are recovered, estimated to be 1998. In 1995 and 1994 $28.5
million and $18.5 million, respectively, of net phase-in deferrals were
collected through the surcharge which reduced the deferrals from $93.9
million at December 31, 1993 to $75.4 million at December 31, 1994 and $46.9
million at December 31, 1995. In 1993 and 1992, $47.9 million and $46
million, 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 million 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.
The Rockport Plant consists of two 1,300 mw coal-fired units. I&M and
AEPGEN each own 50% of one unit (Rockport 1) and lease a 50% interest in the
other unit (Rockport 2) from unaffiliated lessors under an operating lease.
The gain on the sale and leaseback of Rockport 2 was deferred and is being
amortized, with related taxes, over the initial lease term which expires in
2022.
Rate phase-in plans in I&M's Indiana and FERC jurisdictions for its
share of Rockport 1 provide for the recovery and straight-line amortization
through 1997 of prior-year deferrals. Unamortized deferred amounts under the
phase-in plans were $27.5 million and $43.2 million at December 31, 1995 and
1994, respectively. Amortization was $16 million in 1995, 1994 and 1993.
4. Commitments and Contingencies:
Construction and Other Commitments - The AEP System has made substantial
construction commitments for utility operations. Such commitments do not
presently include any expenditures for new generating capacity. The
aggregate construction program expenditures for 1996-1998 are estimated to be
$2 billion.
Long-term fuel supply contracts contain clauses for periodic
adjustments, and most jurisdictions have fuel clause mechanisms that provide
for recovery of changes in the cost of fuel with the regulators' review and
approval. The contracts are for various terms, the longest of which extend
to the year 2014, and contain various clauses that would release the Company
from its obligation under certain force majeure conditions.
The AEP System has contracted to sell up to 1,300 mw of capacity to
unaffiliated utilities. The Company has an obligation to deliver energy
under certain unit power agreements regardless of whether the unit capacity
is available. The power sales contracts expire from 1997 to 2010.
Nuclear Plant - I&M owns and operates the two-unit 2,110 mw Cook Plant under
licenses granted by a regulatory authority. The operation of a nuclear
facility involves special risks, potential liabilities, and specific
regulatory and safety requirements. Should a nuclear incident occur at any
nuclear power plant facility in the United States, the resultant liability
could be substantial. By agreement I&M is partially liable together with all
other electric utility companies that own nuclear generating units for a
nuclear power plant incident. In the event nuclear losses or liabilities are
underinsured or exceed accumulated funds and recovery is not possible,
results of operations and financial condition could be negatively affected.
Nuclear Incident Liability - Public liability is limited by law to $8.9
billion should an incident occur at any licensed reactor in the United
States. Commercially available insurance provides $200 million of coverage.
In the event of a nuclear incident at any nuclear plant in the United States
the remainder of the liability would be provided by a deferred premium
assessment of $79.3 million on each licensed reactor payable in annual
installments of $10 million. As a result, I&M could be assessed $158.6
million per nuclear incident payable in annual installments of $20 million.
The number of incidents for which payments could be required is not limited.
Nuclear insurance pools and other insurance policies provide $3.6
billion of property damage, decommissioning and decontamination coverage for
the Cook Plant. Additional insurance provides coverage for extra costs
resulting from a prolonged accidental Cook Plant outage. Some of the
policies have deferred premium provisions which could be triggered by losses
in excess of the insurer's resources. The losses could result from claims at
the Cook Plant or certain other non-affiliated nuclear units. I&M could be
assessed up to $40.9 million under these policies.
Spent Nuclear Fuel Disposal - Federal law provides for government
responsibility for permanent spent nuclear fuel disposal and assesses nuclear
plant owners fees for spent fuel disposal. A fee of one mill per
kilowatthour for fuel consumed after April 6, 1983 is being collected from
customers and remitted to the U.S. Treasury. Fees and related interest of
$163 million for fuel consumed prior to April 7, 1983 have been recorded as
long-term debt. I&M has not paid the government the pre-April 1983 fees due
to various factors including continued delays and uncertainties related to
the federal disposal program. At December 31, 1995, funds collected from
customers to eventually pay the pre-April 1983 fee and related earnings
including accrued interest approximated the liability.
Decommissioning and Low Level Waste Accumulation Disposal - Decommissioning
costs are accrued over the service life of the Cook Plant. The licenses to
operate the two nuclear units expire in 2014 and 2017. After expiration of
the licenses the plant is expected to be decommissioned through
dismantlement. The Company s latest estimate for decommissioning and low
level radioactive waste accumulation disposal costs range from $634 million
to $988 million in 1993 nondiscounted dollars. The wide range is caused by
variables in assumptions including the estimated length of time spent nuclear
fuel must be stored at the plant subsequent to ceasing operations. This in
turn depends on future developments in the federal government's spent nuclear
fuel disposal program. Continued delays in the federal fuel disposal program
can result in increased decommissioning costs. I&M is recovering estimated
decommissioning costs in its three rate-making jurisdictions based on at
least the lower end of the range in the most recent decommissioning study at
the time of the last rate proceeding. I&M records decommissioning costs in
other operation expense and records a noncurrent liability equal to the
decommissioning cost recovered in rates; such amount was $30 million in 1995,
$26 million in 1994 and $13 million in 1993. Decommissioning amounts
recovered from customers are deposited in external trusts. Trust fund
earnings increase the fund assets and the recorded liability and decrease the
amount to be recovered from ratepayers. At December 31, 1995 I&M has
recognized a decommissioning liability of $269 million.
Litigation - The Company is involved in a number of legal proceedings and
claims. While management is unable to predict the ultimate outcome of
litigation, it is not expected that the resolution of these matters will have
a material adverse effect on the results of operations or financial
condition.
5. Dividend Restrictions:
Mortgage indentures, debentures, charter provisions and orders of regulatory
authorities place various restrictions on the use of the subsidiaries'
retained earnings for the payment of cash dividends on their common stocks.
At December 31, 1995, $230 million of retained earnings were restricted. To
pay dividends out of paid-in capital the subsidiaries need regulatory
approval.
<PAGE>
<PAGE>
6. Lines of Credit and Commitment Fees:
At December 31, 1995 and 1994 unused short-term bank lines of credit were
available in the amounts of $372 million and $558 million, respectively.
Commitment fees of approximately 1/8 of 1% of the unused short-term lines of
credit are paid each year to the banks to maintain the lines of credit.
Outstanding short-term debt consisted of:
December 31,
(Dollars In Thousands) 1995 1994
Balance Outstanding:
Notes Payable $128,425 $ 42,535
Commercial Paper 236,700 274,450
Total $365,125 $316,985
Year-End Weighted
Average Interest Rate:
Notes Payable 6.1% 6.2%
Commercial Paper 6.1% 6.3%
Total 6.1% 6.3%
7. Benefit Plans:
AEP System Pension Plan - The AEP pension plan is a trusteed, noncontributory
defined benefit plan covering all employees meeting eligibility requirements,
except participants in the United Mine Workers of America (UMWA) pension
plans. Benefits are based on service years and compensation levels. The
funding policy is to make annual trust fund contributions equal to the net
periodic pension cost up to the maximum amount deductible for federal income
taxes, but not less than the minimum required contribution in accordance with
the Employee Retirement Income Security Act of 1974. Net AEP pension plan
costs were computed as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994 1993
(In Thousands)
<S> <C> <C> <C>
Service Cost-Benefits
Earned During
the Year $ 30,400 $ 40,000 $ 37,100
Interest Cost on
Projected Benefit
Obligation 116,700 114,500 112,600
Actual Return on
Assets (416,800) (6,700) (150,000)
Net Amortization
and Deferral 281,800 (123,300) 24,700
Net AEP Pension
Plan Costs $ 12,100 $ 24,500 $ 24,400
</TABLE>
<PAGE>
<PAGE>
AEP pension plan assets and actuarially computed benefit obligations are:
<TABLE>
<CAPTION>
December 31,
1995 1994
(In Thousands)
<S> <C> <C>
AEP Pension Plan
Assets at
Fair Value (a) $1,805,300 $1,480,600
Actuarial Present Value
of Benefit Obligation:
Vested 1,321,600 1,130,000
Nonvested 147,400 120,700
Accumulated
Benefit Obligation 1,469,000 1,250,700
Effects of Salary
Progression 181,000 132,600
Projected Benefit
Obligation 1,650,000 1,383,300
Funded Status - AEP
Pension Plan Assets
in Excess of Projected
Benefit Obligation 155,300 97,300
Unrecognized Prior
Service Cost 147,000 160,800
Unrecognized Net Gain (295,200) (229,000)
Unrecognized Net
Transition Assets
(Being Amortized
Over 17 Years) (78,700) (88,600)
Accrued Net AEP
Pension Plan
Liability $ (71,600) $ (59,500)
</TABLE>
(a) AEP pension plan assets primarily consist of common stocks, bonds and
cash equivalents and are included in a separate entity Trust Fund.
Assumptions used to determine AEP pension plan's funded status were:
<TABLE>
<CAPTION>
December 31,
1995 1994 1993
<S> <C> <C> <C>
Discount Rate 7.25% 8.5% 7.0%
Average Rate of Increase in
Compensation Levels 3.2% 3.2% 3.2%
Expected Long-Term
Rate of Return on Plan Assets 9.0% 8.5% 9.0%
</TABLE>
<PAGE>
<PAGE>
AEP System Savings Plan - An employee savings plan is offered to non-UMWA
employees which allows participants to contribute up to 17% of their salaries
into various investment alternatives, including AEP common stock. An
employer matching contribution, equaling one-half of the employees'
contribution to the plan up to a maximum of 3% of the employees' base salary,
is invested in AEP common stock. The employer's annual contributions totaled
$18.8 million in 1995, $18.6 million in 1994 and $17.6 million in 1993.
UMWA Pension Plans - The coal-mining subsidiaries of OPCo provide UMWA
pension benefits for UMWA employees meeting eligibility requirements.
Benefits are based on age at retirement and years of service. As of June 30,
1995, the UMWA actuary estimates the OPCo coal-mining subsidiaries' share of
the UMWA pension plans unfunded vested liabilities was approximately $35
million. In the event the OPCo coal-mining subsidiaries cease or
significantly reduce mining operations or contributions to the UMWA pension
plans, a withdrawal obligation may be triggered for all or a portion of their
share of the unfunded vested liability. Contributions are based on the
number of hours worked, are expensed when paid and totaled $1.4 million in
1995 and $1.6 million in both 1994 and 1993.
Postretirement Benefits Other Than Pensions (OPEB) - The AEP System provides
certain other benefits for retired employees. Substantially all non-UMWA
employees are eligible for postretirement health care and life insurance if
they have at least 10 service years and are age 55 at retirement.
Postretirement medical benefits for OPCo's UMWA employees who have or
will retire after January 1, 1976 are the liability of the OPCo coal-mining
subsidiaries. They are eligible for postretirement medical and life
insurance benefits if they have at least 10 service years and are age 55 at
retirement. Non-active UMWA employees become eligible at age 55 if they have
had 20 service years.
Management has taken several measures to reduce its OPEB costs. First,
a Voluntary Employees Beneficiary Association (VEBA) trust fund for OPEB
benefits for all non-UMWA employees was established. In addition, to help
fund and reduce the future costs of OPEB benefits, a corporate owned life
insurance (COLI) program was implemented, except where restricted by state
law. The insurance policies have a substantial cash surrender value which is
recorded, net of equally substantial policy loans, in other property and
investments. Legislation was passed by Congress which would have
significantly reduced the tax benefits of a COLI program for the future. The
legislation containing this provision was vetoed by the President. At this
time it is uncertain if legislation repealing certain tax benefits from COLI
programs will be enacted. If enacted this legislation would negatively
impact the effectiveness of the COLI program as a funding and cost reduction
mechanism. For jurisdictions where OPEB costs are reflected in cost of
service, the funding policy is to make VEBA trust fund contributions equal to
the increase in OPEB costs resulting from the January 1993 implementation of
SFAS 106, "Employers Accounting for Postretirement Benefits Other Than
Pensions." These contributions include amounts collected from ratepayers and
the net earnings from the COLI program. For jurisdictions where recovery has
not been approved and rates are insufficient to absorb these additional
costs, the funding policy is to contribute cash generated by the COLI
program. Contribution to the VEBA trust fund, including amounts funded by
the COLI program, were $53 million in 1995, $29.5 million in 1994 and $21.5
million in 1993.
The utility subsidiaries received approval in several jurisdictions to
recover their increased OPEB costs resulting from the implementation of SFAS
106. For those jurisdictions where recovery has not been approved and rates
are insufficient to absorb these additional costs, the utility subsidiaries
received regulatory authority to defer the increased OPEB costs which are not
being currently recovered in rates. Future recovery of the deferrals and the
annual ongoing OPEB costs will be sought by the utility subsidiaries in their
next base rate filings. At December 31, 1995 and 1994, $24.6 million and
$28.5 million, respectively, of incremental OPEB costs were deferred.
Aggregate OPEB costs were computed as follows:
Year Ended December 31,
1995 1994 1993
(In Thousands)
Service Cost $ 13,500 $16,500 $15,700
Interest Cost on
Projected
Benefit Obligation 54,900 47,300 45,300
Net Amortization of
Transition Obligation 32,000 31,100 28,200
Return on Plan
Assets (25,400) 900 (1,000)
Net Amortization
and Deferral 16,800 (6,800) -
Net OPEB Costs $ 91,800 $89,000 $88,200
<PAGE>
OPEB assets and actuarially computed benefit obligations are:
December 31,
1995 1994
(In Thousands)
Fair Market Value of
Plan Assets (a) $ 165,600 $ 87,200
Accumulated Postretirement
Benefit Obligation:
Active Employees
Fully Eligible for Benefits 59,200 41,200
Current Retirees 398,400 361,500
Other Active Employees 282,400 245,800
Total Benefit Obligation 740,000 648,500
Unfunded Benefit Obligation (574,400) (561,300)
Unrecognized Net Loss 48,500 8,900
Unrecognized Net Transition
Obligation Being
Amortized Over 20 Years 485,600 517,700
Accrued Net OPEB
Liability $ (40,300) $ (34,700)
(a) Plan assets consist of cash surrender value of life insurance contracts
on certain employees owned by the trust and short-term tax exempt municipal
bonds.
Assumptions used to determine OPEB's funded status were:
December 31,
1995 1994 1993
Discount Rate 7.25% 8.5 % 7.0 %
Expected Long-Term Rate
of Return on Plan Assets 8.75% 8.25% 8.75%
Initial Medical Cost Trend Rate 8.0 % 8.0 % 8.0 %
Ultimate Medical Cost Trend Rate 4.5 % 5.25% 4.25%
Medical Cost Trend Rate
Decreases to Ultimate Rate in Year 2005 2005 2005
Assuming a one percent increase in the medical cost trend rate, the 1995 OPEB
cost for all employees, both non-UMWA and UMWA, would increase by $9 million
and the accumulated benefit obligations would increase by $78 million.
Several UMWA health plans pay the postretirement medical benefits for
the Company's UMWA retirees who retired before January 2, 1976 and their
survivors plus retirees and others whose last employer is no longer a
signatory to the UMWA contract or is no longer in business. The UMWA health
plans are funded by payments from current and former UMWA wage agreement
signatories, the 1950 UMWA Pension Plan surplus and the Abandoned Mine Land
Reclamation Fund Surplus. Required annual payments to the UMWA health funds
made by AEP's active and inactive coal-mining subsidiaries were recognized as
expense when paid and totaled $2.8 million in 1995, $3.1 million in 1994 and
$3.8 million in 1993.
By law excess Black Lung Trust funds may be used to pay certain
postretirement medical benefits under one of the UMWA health plans. Excess
AEP Black Lung Trust funds used to reimburse the coal companies totaled $7.9
million in 1995, $6.9 million in 1994 and $10 million in 1993. The Black
Lung Trust had excess funds at December 31, 1995, 1994 and 1993 of $13
million, $16 million and $18 million, respectively.
8. Fair Value of Financial Instruments:
Nuclear Trust Funds Recorded at Market Value - The trust investments,
reported in other property and investments, are recorded at market value in
accordance with SFAS 115 and consist primarily of long-term tax-exempt
municipal bonds.
At December 31, 1995 and 1994 the fair values of the trust investments
were $434 million and $353 million, respectively. Accumulated gross
unrealized holding gains and losses were $19.1 million and $1.0 million,
respectively, at December 31, 1995. The change in market value was a $24.9
million net holding gain in 1995 and a $27.1 million net holding loss in
1994.
The trust investments' cost basis by security type were:
<TABLE>
<CAPTION>
December 31,
1995 1994
(In Thousands)
<S> <C> <C>
Treasury Bonds $ 14,963 $ 997
Tax-Exempt Bonds 336,073 332,098
Equity Securities 24,101 1,665
Cash, Cash Equivalents and Interest Accrued 40,356 25,304
Total $415,493 $360,064
</TABLE>
Proceeds from sales and maturities of securities of $78.2 million
during 1995 resulted in $1.4 million of realized gains and $0.3 million of
realized losses. Proceeds from sales and maturities of securities of $20.1
million during 1994 resulted in $52,000 of realized gains and $155,000 of
realized losses. The cost of securities for determining realized gains and
losses is original acquisition cost including amortized premiums and
discounts.
At December 31, 1995, the year of maturity of trust fund investments
other than equity securities, was:
(In Thousands)
1996 $ 55,748
1997 - 2000 96,882
2001 - 2005 162,563
After 2005 76,199
Total $391,392
Other Financial Instruments Recorded at Historical Cost - The carrying
amounts of cash and cash equivalents, accounts receivable, short-term debt,
and accounts payable approximate fair value because of the short-term
maturity of these instruments. Fair values for preferred stock subject to
mandatory redemption were $544 million and $537 million and for long-term
debt were $5.3 billion and $4.7 billion at December 31, 1995 and 1994,
respectively. The carrying amounts for preferred stock subject to mandatory
redemption were $523 million and $590 million and for long-term debt were
$5.1 billion and $5.0 billion at December 31, 1995 and 1994, respectively.
Fair values are based on quoted market prices for the same or similar issues
and the current dividend or interest rates offered for instruments of the
same remaining maturities. The carrying amount of the pre-April 1983
spent nuclear fuel disposal liability approximates the Company's best
estimate of its fair value.
<PAGE>
9. Federal Income Taxes:
The details of federal income taxes as reported are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994 1993
(In Thousands)
Charged (Credited) to Operating Expenses (net):
<S> <C> <C> <C>
Current $265,313 $240,655 $270,318
Deferred 22,990 (10,177) (53,462)
Deferred Investment Tax Credits (16,276) (17,079) (17,235)
Total 272,027 213,399 199,621
Charged (Credited) to Nonoperating Income (net):
Current 11,325 (2,907) 8,727
Deferred (11,074) (5,856) 4,603
Deferred Investment Tax Credits (9,543) (14,196) (9,780)
Total (9,292) (22,959) 3,550
Credited to Loss from Zimmer Plant Disallowance (net):
Deferred - - (13,327)
Deferred Investment Tax Credits - - (1,207)
Total - - (14,534)
Total Federal Income Tax as Reported $262,735 $190,440 $188,637
</TABLE>
<PAGE>
The following is a reconciliation of the difference between the amount
of federal income taxes computed by multiplying book income before federal
income taxes by the statutory tax rate, and the amount of federal income
taxes reported.
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994 1993
(In Thousands)
<S> <C> <C> <C>
Income Before Preferred Stock
Dividend Requirements of Subsidiaries $584,674 $554,738 $412,618
Federal Income Taxes 262,735 190,440 188,637
Pre-Tax Book Income $847,409 $745,178 $601,255
Federal Income Tax on Pre-Tax Book
Income at Statutory Rate (35%) $296,593 $260,812 $210,439
Increase (Decrease) in Federal Income Tax
Resulting from the Following Items:
Depreciation 46,453 31,212 27,554
Removal Costs (14,640) (13,818) (17,730)
Corporate Owned Life Insurance (25,506) (22,970) (27,310)
Investment Tax Credits (net) (26,179) (31,273) (28,218)
Zimmer Plant Disallowance - - 42,346
Federal Income Tax Accrual Adjustments - (16,100) (6,500)
Other (13,986) (17,423) (11,944)
Total Federal Income Taxes as Reported $262,735 $190,440 $188,637
Effective Federal Income Tax Rate 31.0% 25.6% 31.4%
</TABLE>
<PAGE>
The following tables show the elements of the net deferred tax liability and
the significant temporary differences:
<TABLE>
<CAPTION>
December 31,
1995 1994
(In Thousands)
<S> <C> <C>
Deferred Tax Assets $ 723,196 $ 657,298
Deferred Tax Liabilities (3,379,847) (3,314,360)
Net Deferred Tax Liabilities $(2,656,651) $(2,657,062)
Property Related Temporary Differences $(2,139,387) $(2,098,304)
Amounts Due From Customers For
Future Federal Income Taxes (442,311) (444,305)
Deferred State Income Taxes (183,981) (183,987)
All Other (net) 109,028 69,534
Total Net Deferred Tax Liabilities $(2,656,651) $(2,657,062)
</TABLE>
The Company has settled with the Internal Revenue Service (IRS) all
issues from the audits of the consolidated federal income tax returns for the
years prior to 1991. Returns for the years 1991 through 1993 are presently
being audited by the IRS. In the opinion of management, the final settlement
of open years will not have a material effect on results of operations.
<PAGE>
<PAGE>
10. Leases:
Leases of property, plant and equipment are for periods up to 35 years and
require payments of related property taxes, maintenance and operating costs.
The majority of the leases have purchase or renewal options and will be
renewed or replaced by other leases.
Lease rentals are primarily charged to operating expenses in accordance
with rate-making treatment. The components of rentals are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994 1993
(In Thousands)
<S> <C> <C> <C>
Operating Leases $259,877 $233,805 $243,190
Amortization of Capital Leases 101,068 79,116 84,226
Interest on Capital Leases 27,542 23,280 23,839
Total Rental Payments $388,487 $336,201 $351,255
</TABLE>
Properties under capital leases and related obligations on the
Consolidated Balance Sheets are as follows:
<TABLE>
<CAPTION>
December 31,
1995 1994
(In Thousands)
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production $ 44,849 $ 44,683
Transmission 7 38
Distribution 14,753 14,717
General:
Nuclear Fuel (net of amortization) 69,442 89,478
Mining Plant and Other 424,952 403,038
Total Electric Utility Plant 554,003 551,954
Accumulated Amortization 179,952 173,641
Net Electric Utility Plant 374,051 378,313
OTHER PROPERTY 34,536 24,724
Accumulated Amortization 3,994 2,838
Net Other Property 30,542 21,886
Net Property under Capital Leases $404,593 $400,199
Obligations under Capital Leases $404,593 $400,199
Less Portion Due Within One Year 89,692 93,252
Noncurrent Capital Lease Liability $314,901 $306,947
</TABLE>
<PAGE>
Properties under operating leases and related obligations are not
included in the Consolidated Balance Sheets.
Future minimum lease rentals, consisted of the following at December 31,
1995:
<TABLE>
<CAPTION>
Noncancelable
Capital Operating
Leases Leases
(In Thousands)
<S> <C> <C>
1996 $ 86,495 $ 244,228
1997 72,576 239,800
1998 56,165 231,449
1999 47,531 229,296
2000 39,547 227,506
Later Years 156,895 4,092,193
Total Future Minimum Lease Rentals 459,209(a) $5,264,472
Less Estimated Interest Element 124,058
Estimated Present Value of Future Minimum
Lease Rentals 335,151
Unamortized Nuclear Fuel 69,442
Total $404,593
</TABLE>
(a) Minimum lease rentals do not include nuclear fuel rentals. The rentals
are paid in proportion to heat produced and carrying charges on the
unamortized nuclear fuel balance. There are no minimum lease payment
requirements for leased nuclear fuel.
11. SUPPLEMENTARY INFORMATION:
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994 1993
(In Thousands)
<S> <C> <C> <C>
Purchased Power -
Ohio Valley Electric Corp. (44.2% owned by AEP) $10,546 $5,755 $19,253
Cash was paid for:
Interest (net of capitalized amounts) $395,169 $379,361 $421,060
Income Taxes $273,671 $312,233 $245,350
Noncash Acquisitions under Capital Leases were $106,256 $227,055 $80,220
</TABLE>
<PAGE>
<PAGE>
12. CAPITAL STOCKS AND PAID-IN CAPITAL:
Changes in capital stocks and paid-in capital during the period January
1, 1993 through December 31, 1995 were:
<TABLE>
<CAPTION>
Cumulative Preferred Stocks
Shares of Subsidiaries
Cumulative Not Subject Subject to
Common Stock- Preferred Stocks Paid-in To Mandatory Mandatory
Par Value $6.50(a) of Subsidiaries Common Stock Capital Redemption Redemption(b)
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C> <C>
January 1, 1993 193,534,992 10,761,675 $1,257,977 $1,628,394 $ 534,978 $233,509
Issues - 3,250,000 - - - 325,000
Retirements and
Other - (6,323,907) - (4,218) (266,738) (57,972)
December 31, 1993 193,534,992 7,687,768 1,257,977 1,624,176 268,240 500,537
Issues 700,000 900,000 4,550 17,706 - 90,000
Retirements and
Other - (351,517) - (1,221) (35,000) (152)
December 31, 1994 194,234,992 8,236,251 1,262,527 1,640,661 233,240 590,385
Issues 1,400,000 - 9,100 39,607 - -
Retirements and
Other - (1,526,500) - (21,744) (85,000) (67,650)
December 31, 1995 195,634,992 6,709,751 $1,271,627 $1,658,524 $ 148,240 $522,735
(a) Includes 8,999,992 shares of treasury stock.
(b) Including portion due within one year.
</TABLE>
<PAGE>
13. Unaudited Quarterly Financial Information:
<TABLE>
<CAPTION>
Quarterly Periods Ended
1995
March 31 June 30 Sept. 30 Dec. 31
(In Thousands - Except
Per Share Amounts)
<S> <C> <C> <C> <C>
Operating Revenues $1,416,169 $1,305,342 $1,523,390 $1,425,429
Operating Income 257,556 211,284 262,548 233,159
Net Income 147,850 96,478 154,156 131,419
Earnings per Share 0.80 0.52 0.83 0.70
</TABLE>
<TABLE>
<CAPTION>
Quarterly Periods Ended
1994
March 31 June 30 Sept. 30 Dec. 31
(In Thousands - Except
Per Share Amounts)
<S> <C> <C> <C> <C>
Operating Revenues $1,488,185 $1,348,563 $1,385,278 $1,282,644
Operating Income 257,517 219,496 247,015 208,465
Net Income 152,954 103,793 139,826 103,439
Earnings per Share 0.83 0.56 0.76 0.56
Fourth quarter 1994 net income includes favorable federal income tax accrual adjustments of $16.1 million
related to the resolution of various issues with the IRS.
</TABLE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
<TABLE>
<CAPTION>
December 31, 1995
Call
Price per Shares Shares Amount (in
Share (a) Authorized(b) Outstanding thousands)
<S> <C> <C> <C> <C>
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 932,403 $ 93,240
7.08% - 7.40% $101.85-$102.11 550,000 550,000 55,000
Total Not Subject to Mandatory
Redemption $148,240
Subject to Mandatory Redemption (c):
4.50% $102 19,625 2,348 $ 235
5.90% - 5.92% (d) 1,950,000 1,950,000 195,000
6.02% - 6-7/8% (e) 1,950,000 1,950,000 195,000
7% - 7-7/8% $107.80-$107.88(f) 1,250,000 1,250,000 125,000
9.50% (g) 750,000 75,000 7,500
Total Subject to Mandatory
Redemption (h) 522,735
Less Portion Due Within One Year 7,650
Long-term Portion $515,085
</TABLE>
_____________________________________________
<PAGE>
<TABLE>
<CAPTION>
December 31, 1994
Call
Price per Shares Shares Amount (in
Share (a) Authorized Outstanding thousands)
<S> <C> <C> <C> <C>
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 932,403 $ 93,240
7.08% - 7.76% $101.85-$102.26 1,250,000 1,250,000 125,000
8.04% $102.58 150,000 150,000 15,000
Total Not Subject to Mandatory
Redemption $233,240
Subject to Mandatory Redemption (c):
4.50% $102 19,625 3,848 $ 385
5.90% - 5.92% (d) 1,950,000 1,950,000 195,000
6.02% - 6-7/8% (e) 1,950,000 1,950,000 195,000
7% - 7-7/8% $107.80-$107.88(f) 1,250,000 1,250,000 125,000
9.50% (g) 750,000 750,000 75,000
Total Subject to Mandatory
Redemption (h) 590,385
Less Portion Due Within One Year 85
Long-term Portion $590,300
NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
(a) At the option of the subsidiary the shares may be redeemed at the call price
(December 31, 1995 price is shown) plus accrued dividends. The involuntary liquidation
preference is $100 per share for all outstanding shares.(b) As of December 31, 1995 the
subsidiaries had 4,255,000, 22,200,000 and 5,547,652 shares of $100, $25 and no par value
preferred stock, respectively, that were authorized but unissued.
(c) With sinking fund. Shares outstanding and related amounts are stated net of applicable
retirements through sinking funds (generally at par) and reacquisitions of shares in
anticipation of future requirements.
(d) Redemption is prohibited prior to 2003; after that the call price is $100 per share.
(e) Redemption is prohibited prior to 2000; after that the call price is $100 per share.
(f) Redemption is restricted prior to 1997.
(g) On February 1, 1996 the outstanding balance of 75,000 shares was redeemed at $100 per share.
(h) The sinking fund provisions of the series subject to mandatory redemption aggregate
$7,650,000, $84,800, $5,000,000, $5,000,000 and $16,000,000 in 1996, 1997, 1998, 1999 and 2000, respectively.
</TABLE>
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
<TABLE>
<CAPTION>
Weighted Average
Maturity Interest Rate Interest Rates at December 31, December 31,
December 31, 1995 1995 1994 1995 1994
(in thousands)
<S> <C> <C> <C> <C> <C>
FIRST MORTGAGE BONDS
1995-1999 7.05% 5%-9.15% 5%-9.15% $ 496,866 $ 526,866
2001-2005 7.28% 6%-9.31% 6%-9.31% 1,530,020 1,450,020
2019-2025 8.26% 7.10%-9-7/8% 7.10%-9-7/8% 1,473,127 1,540,661
INSTALLMENT PURCHASE CONTRACTS(a)
1995-2002 5.65% 5%-7-1/4% 6%-7-1/4% 209,500 174,500
2007-2025 6.45% 5.45%-7-7/8% 5.45%-9-3/8% 756,745 811,745
NOTES PAYABLE(b)
1995-2008 7.87% 5.29%-10.78% 5.29%-10.78% 221,000 313,000
DEBENTURES
1996 - 1999(c) 6.40% 5-1/8%-7-7/8% 5-1/8%-7-7/8% 30,759 30,759
2025 8.35% 8.16%-8.72% - 200,000 -
OTHER LONG-TERM DEBT(d) 172,403 163,896
Unamortized Discount (net) (33,144) (31,128)
Total Long-term Debt
Outstanding (e) 5,057,276 4,980,319
Less Portion Due Within One Year 136,947 293,671
Long-term Portion $4,920,329 $4,686,648
NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
(a) For certain series of installment purchase contracts interest rates are subject to periodic
adjustment. Certain series will be purchased on the demand of the owners at periodic
interest-adjustment dates. Letters of credit from banks and standby bond purchase agreements
support certain series.
(b) Notes payable represent outstanding promissory notes issued under term loan agreements with
a number of banks and other financial institutions. At expiration all notes then issued and
outstanding are due and payable. Interest rates are both fixed and variable. Variable rates
generally relate to specified short-term interest rates.
(c) All sinking fund debentures will be reacquired by March 1, 1996.
(d) Other long-term debt consist primarily of a liability along with accrued interest for disposal
of spent nuclear fuel (see Note 4 of the Notes to Consolidated Financial Statements).
(e) Long-term debt outstanding at December 31, 1995 is payable as follows:
Principal Amount (in thousands)
1996 $ 136,947
1997 86,933
1998 269,266
1999 185,673
2000 168,648
Later Years 4,242,953
Total $5,090,420
</TABLE>
<PAGE>
<PAGE>
Independent Auditors Report
To the Shareholders and Board of Directors
of American Electric Power Company, Inc.:
We have audited the accompanying consolidated balance sheets of American
Electric Power Company, Inc. and its subsidiaries as of December 31, 1995 and
1994, and the related consolidated statements of income, retained earnings,
and cash flows for each of the three years in the period ended December 31,
1995. These financial statements are the responsibility of the Company s
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of American Electric Power
Company, Inc. and its subsidiaries as of December 31, 1995 and 1994, and the
results of their operations and their cash flows for each of the three years
in the period ended December 31, 1995 in conformity with generally accepted
accounting principles.
Deloitte & Touche LLP
Columbus, Ohio
February 27, 1996
<PAGE>
<TABLE>
EXHIBIT 21
Subsidiaries of
American Electric Power Company, Inc.
As of January 1, 1996
<CAPTION>
Percentage
of Voting
Securities
Location of Owned By
Name of Company Incorporation Immediate Parent
<S> <S> <C>
American Electric Power Service Corporation New York 100.0
AEP Energy Services, Inc. Ohio 100.0
AEP Generating Company Ohio 100.0
AEP Investments, Inc. Ohio 100.0
AEP Resources, Inc. Ohio 100.0
AEP Resources International, Ltd. Cayman Islands 100.0
Appalachian Power Company Virginia 96.1 (a)
Cedar Coal Co. West Virginia 100.0
Central Appalachian Coal Company West Virginia 100.0
Central Coal Company West Virginia 50.0 (b)
Central Operating Company West Virginia 50.0 (b)
Southern Appalachian Coal Company West Virginia 100.0
West Virginia Power Company West Virginia 100.0
Columbus Southern Power Company Ohio 100.0
Colomet, Inc. Ohio 100.0
Conesville Coal Preparation Company Ohio 100.0
Simco Inc. Ohio 100.0
Franklin Real Estate Company Pennsylvania 100.0
Indiana Franklin Realty, Inc. Indiana 100.0
Indiana Michigan Power Company Indiana 100.0
Blackhawk Coal Company Utah 100.0
Price River Coal Company Indiana 100.0
Integrated Communications Systems, Inc. Georgia 20.5 (c)
Kentucky Power Company Kentucky 100.0
Kingsport Power Company Virginia 100.0
Ohio Power Company Ohio 97.0 (d)
Cardinal Operating Company Ohio 50.0 (e)
Central Coal Company West Virginia 50.0 (b)
Central Ohio Coal Company Ohio 100.0
Central Operating Company West Virginia 50.0 (b)
Southern Ohio Coal Company West Virginia 100.0
Windsor Coal Company West Virginia 100.0
Ohio Valley Electric Corporation Ohio 44.2 (f)
Indiana-Kentucky Electric Corporation Indiana 100.0
Wheeling Power Company West Virginia 100.0
(a) 13,499,500 shares of Common Stock, all owned by parent, have one vote each and
552,348 shares of Preferred Stock, all owned by public, have one vote each.
(b) Owned 50% by Appalachian Power Company and 50% by Ohio Power Company.
(c) American Electric Power Company, Inc. owns 20.5% of the stock and the remaining
79.5% is owned by unaffiliated companies.
(d) 27,952,473 shares of Common Stock, all owned by parent, have one vote each and
862,403 shares of Preferred Stock, all owned by public, have one vote each.
(e) Ohio Power Company owns 50% of the stock; the other 50% is owned by a corporation not
affiliated with American Electric Power Company, Inc.
(f) American Electric Power Company, Inc. and Columbus Southern Power Company own 39.9%
and 4.3% of the stock, respectively, and the remaining 55.8% is owned by unaffiliated
companies.
</TABLE>
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Post-Effective
Amendment No. 3 to Registration Statement No. 33-01052 of American
Electric Power Company, Inc. on Form S-8 and Post-Effective
Amendment No. 1 to Registration Statement No. 33-01734 of American
Electric Power Company, Inc. on Form S-3 of our reports dated
February 27, 1996, appearing in and incorporated by reference in
this Annual Report on Form 10-K of American Electric Power Company,
Inc. for the year ended December 31, 1995.
Deloitte & Touche LLP
Columbus, Ohio
March 27, 1996<PAGE>
Exhibit 24
POWER OF ATTORNEY
AMERICAN ELECTRIC POWER COMPANY, INC.
ANNUAL REPORT ON FORM 1O-K FOR THE FISCAL YEAR ENDED
__________________DECEMBER_31,_1995_________________
The undersigned directors of AMERICAN ELECTRIC POWER COMPANY,
INC., a New York corporation (the "Company"), do hereby constitute
and appoint E. LINN DRAPER, JR., G. P. MALONEY and P. J. DeMARIA,
and each of them, their attorneys-in-fact and agents, to execute
for them, and in their names, and in any and all of their
capacities, the Annual Report of the Company on Form lO-K, pursuant
to Section 13 of the Securities Exchange Act of 1934, for the
fiscal year ended December 31, 1995, and any and all amendments
thereto, and to file the same, with all exhibits thereto and other
documents in connection therewith, with the Securities and Exchange
Commission, granting unto said attorneys-in-fact and agents, and
each of them, full power and authority to do and perform every act
and thing required or necessary to be done, as fully to all intents
and purposes as the undersigned might or could do in person, hereby
ratifying and confirming all that said attorneys-in-fact and
agents, or any of them, may lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned have signed these presents
this 28th day of February, 1996.
_/s/_P._J._DeMaria____________ _/s/_Angus_E._Peyton__________
P. J. DeMaria Angus E. Peyton
_/s/_E._Linn_Draper,_Jr.______ _/s/_Toy_F._Reid______________
E. Linn Draper, Jr. Toy F. Reid
_/s/_Robert_M._Duncan_________ _/s/_Donald_G._Smith__________
Robert M. Duncan Donald G. Smith
_/s/_Robert_W._Fri____________ _/s/_Linda_Gillespie_Stuntz___
Robert W. Fri Linda Gillespie Stuntz
_/s/_Arthur_G._Hansen_________ _/s/_Morris_Tanenbaum_________
Arthur G. Hansen Morris Tanenbaum
_/s/_Lester_A._Hudson,_Jr.____ _/s/_Ann_Haymond_Zwinger______
Lester A. Hudson, Jr. Ann Haymond Zwinger
_/s/_G._P._Maloney____________
G. P. Maloney
[ANNUAL\103.96C]<PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000004904
<NAME> AMERICAN ELECTRIC POWER COMPANY, INC.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 11,384,839
<OTHER-PROPERTY-AND-INVEST> 825,781
<TOTAL-CURRENT-ASSETS> 1,401,858
<TOTAL-DEFERRED-CHARGES> 310,377
<OTHER-ASSETS> 1,979,446
<TOTAL-ASSETS> 15,902,301
<COMMON> 1,271,627
<CAPITAL-SURPLUS-PAID-IN> 1,658,524
<RETAINED-EARNINGS> 1,409,645
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4,339,796
515,085
148,240
<LONG-TERM-DEBT-NET> 4,920,329
<SHORT-TERM-NOTES> 128,425
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 236,700
<LONG-TERM-DEBT-CURRENT-PORT> 136,947
7,650
<CAPITAL-LEASE-OBLIGATIONS> 314,901
<LEASES-CURRENT> 89,692
<OTHER-ITEMS-CAPITAL-AND-LIAB> 5,064,536
<TOT-CAPITALIZATION-AND-LIAB> 15,902,301
<GROSS-OPERATING-REVENUE> 5,670,330
<INCOME-TAX-EXPENSE> 289,432
<OTHER-OPERATING-EXPENSES> 4,416,351
<TOTAL-OPERATING-EXPENSES> 4,705,783
<OPERATING-INCOME-LOSS> 964,547
<OTHER-INCOME-NET> 20,204
<INCOME-BEFORE-INTEREST-EXPEN> 984,751
<TOTAL-INTEREST-EXPENSE> 400,077
<NET-INCOME> 529,903
54,771<F1>
<EARNINGS-AVAILABLE-FOR-COMM> 529,903
<COMMON-STOCK-DIVIDENDS> 445,831
<TOTAL-INTEREST-ON-BONDS> 271,924
<CASH-FLOW-OPERATIONS> 1,056,610
<EPS-PRIMARY> $2.85
<EPS-DILUTED> $2.85
<FN>
<F1>Represents preferred stock dividend requirements of
subsidiaries; deducted before computation of net income.
</FN>
</TABLE>
