<PAGE>
_________________________________________________________________
-----------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------
FORM 10-K
----------------
(Mark One)
[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, 1994
[_] 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 ___________
--------------
<TABLE>
<CAPTION>
I.R.S.
EMPLOYER
COMMISSION REGISTRANT; STATE OF INCORPORATION; IDENTIFICATION
FILE NUMBER ADDRESS; AND TELEPHONE NUMBER NO.
----------- ----------------------------------- -------------
<C> <S> <C>
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 (703) 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<PAGE>
Telephone (216) 456-8173
</TABLE>
---------------
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 X . No X .
--- ---<PAGE>
<PAGE>
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED
---------- ------------------- ---------------------
<C> <S> <C>
AEP Generating
Company None
American Electric Common Stock,
Power Company, $6.50 par value ..... New York Stock
Inc. Exchange
Appalachian Power Cumulative Preferred Stock,
Company Voting, no par value:
4-1/2% ............ Philadelphia Stock
Exchange
4.50% ............. Philadelphia Stock
Exchange
7.40% ............. New York Stock
Exchange
Columbus Southern None
Power Company
Indiana Michigan Cumulative Preferred Stock,
Power Company Non-Voting, $100 par value:
4-1/8% ............ Chicago Stock Exchange
7.08% ............. New York Stock
Exchange
Kentucky Power None
Company
Ohio Power Cumulative Preferred Stock,
Company Voting, $100 par value:
7.60% ............. New York Stock
Exchange
7-6/10% ........... New York Stock
Exchange
8.04% ............. New York Stock
Exchange
</TABLE>
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K ((S)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 or
information statements incorporated by reference in Part III of
this Form 10-K or any amendment to this Form 10-K. X
----<PAGE>
<PAGE>
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
<TABLE>
<CAPTION>
REGISTRANT TITLE OF EACH CLASS
---------- -------------------
<S> <C>
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
</TABLE>
<TABLE>
<CAPTION>
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 3, 1995 FEBRUARY 3, 1995
---------------------- ------------------
<S> <C> <C>
AEP Generating None 1,000
Company ($1,000 par value)
American Electric $6,621,000,000 185,235,000
Power Company, Inc. ($6.50 par value)
Appalachian Power $38,000,000 13,499,500
Company (no par value)
Columbus Southern None 16,410,426
Power Company (no par value)
Indiana Michigan None 1,400,000
Power Company (no par value)
Kentucky Power None 1,009,000
Company ($50 par value)
Ohio Power Company $129,000,000 27,952,473
(no par value)
</TABLE>
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<PAGE>
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 553,848 shares of
Cumulative Preferred Stock, no par value; and (ii) Ohio Power
Company consists of 1,712,403 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 3,
1995 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>
<PAGE>
DOCUMENTS INCORPORATED BY REFERENCE
<TABLE>
<CAPTION>
PART OF FORM 10-K
INTO WHICH DOCUMENT
DESCRIPTION IS INCORPORATED
----------- -----------------
<S> <C>
Portions of Annual Reports of the following
companies for the fiscal year ended
December 31, 1994: 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,
1995, for Annual Meeting of Shareholders Part III
Portions of Information Statements of the
following companies for 1995 Annual Meeting
of Shareholders, to be filed within 120 days
after December 31, 1994: Part III
Appalachian Power Company
Ohio Power Company
</TABLE>
---------------
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>
<PAGE>
<TABLE>
TABLE OF CONTENTS
<CAPTION>
PAGE
NUMBER
------
<S> <C> <C>
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 .......................... 35
Executive Officers of the Registrants ................. 35
Part II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters ................. 38
Item 6. Selected Financial Data ...................... 38
Item 7. Management's Discussion and Analysis of
Results of Operations and Financial Condition 38
Item 8. Financial Statements and Supplementary Data .. 39
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure ..... 39
Part III
Item 10. Directors and Executive Officers of the
Registrants ................................ 40
Item 11. Executive Compensation ....................... 41
Item 12. Security Ownership of Certain Beneficial
Owners and Management ..................... 45
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
/TABLE
<PAGE>
<PAGE>
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text
of this report, they have the meanings indicated below.
<TABLE>
<CAPTION>
TERM MEANING
---- -------
<C> <S>
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.<PAGE>
PCB's .................... Polychlorinated biphenyls.
PFBC ..................... Pressurized fluidized-bed combustion,
a process in which sulfur is removed
during coal combustion and nitrogen
oxide formation is minimized.
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.
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.
/TABLE
<PAGE>
<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 operating electric utility
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. At December 31, 1994, the subsidiaries of
AEP had a total of 19,660 employees. AEP, as such, has no
employees. The principal 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 848,000 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, 1994, APCo and its
wholly owned subsidiaries had 4,637 employees. A generating
subsidiary of APCo, Kanawha Valley Power Company, which owns
and operates under Federal license three hydroelectric
generating stations located on Government lands adjacent to
Government-owned navigation dams on the Kanawha River in West
Virginia, sells its net output to APCo. Kanawha Valley Power
Company has requested regulatory approval to merge into APCo.
Among the principal industries served by APCo are coal mining,
primary metals, chemicals, textiles, paper, stone, clay,
glass, 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 588,000 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, 1994, CSPCo had 2,323
employees. CSPCo's service area is comprised of two areas in<PAGE>
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 531,000 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, 1994, I&M had 3,817
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 163,000 customers in an area
in eastern Kentucky, and in supplying electric power at
wholesale to other utilities and municipalities in Kentucky.
At December 31, 1994, KEPCo had 823 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 41,000 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, 1994,
Kingsport Power Company had 104 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 662,000
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, 1994, OPCo and its wholly
owned subsidiaries had 5,404 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,<PAGE>
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, 1994, Wheeling Power Company had
141 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,
computer, engineering, financial, legal and other services at
cost to the AEP System companies. The executive officers of AEP
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 November 8, 1994, the SEC issued a release in which it
discussed the need to modernize PUHCA, particularly in light of
increasing competition in the electric utility industry (see
Competition). It also requested comments on a broad range of
issues, including whether PUHCA should be repealed or some of its
restrictions eliminated. AEP filed comments indicating its
belief that PUHCA is unnecessary and should be repealed. If
PUHCA is repealed or amended to remove some restrictions,
registered holding company systems, including the AEP System,<PAGE>
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.
On December 28, 1994, the SEC also proposed revisions to its
rules governing transactions between associated companies in a
registered holding company system. PUHCA and the rules and
orders of the SEC currently require that these transactions 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.
These proposed revisions to the rules would price transactions
governed by SEC rules at a market-based price if it is lower than
cost. Because prices charged in most AEP intra-system
transactions are governed by SEC orders relating specifically to
such transactions, not general SEC rules, the proposed revisions
would not apply to them. However, the SEC could modify or amend
the orders governing AEP intra-system transactions. 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 recent
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, 1994 are as follows:<PAGE>
<PAGE>
<TABLE>
<CAPTION>
AEP
AEGCo APCo CSPCo I&M KEPCo OPCo System (a)
(in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Retail
Residential
Without Electric Heating . . $ -- $ 233,540 $ 305,189 $ 227,358 $ 42,613 $ 251,382 $1,079,865
With Electric Heating . . . . -- 312,508 109,086 107,523 58,047 132,799 755,577
Total Residential . . . . . -- 546,048 414,275 334,881 100,660 384,181 1,835,442
Commercial . . . . . . . . . . . -- 275,262 361,947 247,938 55,899 241,566 1,217,921
Industrial . . . . . . . . . . . -- 367,130 144,722 291,527 92,993 619,055 1,578,579
Miscellaneous . . . . . . . . . . -- 30,821 15,433 6,316 832 8,079 64,668
Total Retail . . . . . . . . -- 1,219,261 936,377 880,662 250,384 1,252,881 4,696,610
Wholesale (sales for resale) . . . 235,974 291,412 78,820 352,889 53,785 452,146 714,076
Total from KWH Sales . . . . 235,974 1,510,673 1,015,197 1,233,551 304,169 1,705,027 5,410,686
Provision for Revenue Refunds . . . -- 5,560 -- -- -- -- 5,560
Total Net of Provision for
Revenue Refunds . . . . . . 235,974 1,516,233 1,015,197 1,233,551 304,169 1,705,027 5,416,246
Other Operating Revenues . . . . . 67 19,267 15,954 17,758 3,274 33,699 88,424
Total Electric
Operating Revenues . . . . . $236,041 $1,535,500 $1,031,151 $1,251,309 $307,443 $1,738,726 $5,504,670
_______________
(a) Includes revenues of other subsidiaries not shown and elimination of intercompany transactions.
</TABLE>
AEP SYSTEM POWER POOL AND OFF-SYSTEM POWER SALES
AEP's electric utility subsidiaries operate their generating
plants and transmission lines as a single interconnected and
coordinated electric utility system. 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.
The following table shows the net credits or (charges)
allocated among the parties under the Interconnection Agreement
during the years ended December 31, 1992, 1993 and 1994:
<TABLE>
<CAPTION>
1992 1993 1994
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
APCo ........................ $(243,000) $(260,000) $(254,000)
CSPCo ....................... (118,000) (141,000) (105,000)
I&M ......................... 71,000 183,000 107,000
KEPCo ....................... 26,000 1,000 12,000
OPCo ........................ 264,000 217,000 240,000
</TABLE>
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 emission allowances. The<PAGE>
IAA provides for and governs the terms of the following allowance
transactions among the parties beginning January 1, 1995: (1) an
annual reallocation of certain allowances initially allocated by
the Federal EPA to OPCo's Gavin Plant; (2) transfer of allowances
associated with energy transactions among the members of the AEP
Power Pool; (3) a monthly cash settlement for allowances consumed
in connection with power sales to non-affiliated electric
utilities; and (4) transfers of 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
allowances to or from non-affiliated companies. The IAA was
accepted by the FERC on December 30, 1994.
AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo also sell electric
power on a wholesale basis to non-affiliated electric utilities.
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, 1992, 1993 and
1994:
<TABLE>
<CAPTION>
1992(A) 1993(A) 1994(A)
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
AEGCo (b) ................ $ 33,000 $ 32,500 $ 30,800
APCo (c) ................. 18,100 23,600 25,000
CSPCo (c) ................ 9,100 12,000 11,700
I&M (c)(d) ............... 31,300 35,300 34,600
KEPCo (c) ................ 3,700 4,900 4,800
OPCo (c) ................. 15,700 20,700 20,000
-------- -------- --------
Total System .......... $110,900 $129,000 $126,900
======== ======== ========
</TABLE>
---------------
(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 1992, 1993 and
1994 were made on a short-term basis, except that
$11,500,000, $16,800,000 and $21,800,000, 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 1992,
1993 and 1994 amounts for I&M include $20,800,000,
$21,600,000 and $21,600,000 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 will be supplying 205 megawatts of electric power<PAGE>
to an unaffiliated utility for 15 years. The AEP System
continues to seek appropriate long-term wholesale power
agreements and will sell available power on a short-term basis.
The future results of operations of AEP and its operating
companies will be affected by their ability to make cost-
effective wholesale sales or, if such sales are reduced, their
ability to timely raise retail rates.
In addition to System sales, APCo, CSPCo, I&M, KEPCo and OPCo
serve wholesale customers that are full/partial requirement
customers. The aggregate maximum demand for these customers in
1994 was 485, 83, 420, 17 and 125 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 June 1993, certain municipal customers of APCo filed an
application with the FERC for transmission service in order to
reduce by 50 megawatts the power these customers purchase under
existing 10-year Electric Service Agreements (ESAs) and 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 December 1, 1993, the administrative law judge issued an
initial decision 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 February 10, 1994, the FERC
issued an order affirming, in part, the administrative law
judge's initial decision. 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. On August 1, 1994, AEP System
companies filed petitions for rehearing of these FERC orders.
Effective August 1, 1994, these municipal customers reduced their
purchases by 40 megawatts. Certain of these customers also have
notified APCo that they intend to reduce their purchases by an
additional 21 megawatts effective February 1996.
AEP SYSTEM TRANSMISSION POOL AND OFF-SYSTEM TRANSMISSION
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 AEP System
Power Pool and Off-System Power Sales.
The following table shows the net credits or (charges)
allocated among the parties to the Transmission Agreement during
the years ended December 31, 1992, 1993 and 1994:
<TABLE>
<CAPTION>
1992 1993 1994
-------- -------- --------
(IN THOUSANDS)<PAGE>
<S> <C> <C> <C>
APCo ..................... $ (8,000) $ (3,200) $(10,200)
CSPCo .................... (29,900) (31,200) (30,100)
I&M ...................... 48,200 47,400 50,300
KEPCo .................... 4,200 3,800 4,300
OPCo ..................... (14,500) (16,800) (14,300)
</TABLE>
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, 1992, 1993 and 1994:
<TABLE>
<CAPTION>
1992 1993 1994
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
APCo ..................... $ 3,000 $ 2,900 $ 4,100
CSPCo .................... 2,500 2,500 3,100
I&M ...................... 6,500 7,700 6,700
KEPCo .................... 600 600 800
OPCo ..................... 10,000 9,900 15,700
------- ------- -------
Total System ............. $22,600 $23,600 $30,400
======= ======= =======
</TABLE>
The Energy Policy Act of 1992 amended the Federal Power Act to
authorize 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. Effective August 1, 1994 and under a FERC order,
the AEP System began to provide transmission services for 40
megawatts of power delivered to certain municipal customers of
APCo as discussed above under AEP System Power Pool and Off-
System Power Sales.
FERC Transmission Access Filing: 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
any "eligible utility." The tariff covers the terms and
conditions of the service, as well as the price which "eligible
utilities" pay to wheel power on the AEP transmission system,
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 August 26, 1994, AEP System companies submitted to the FERC
their comparability filing supplementing the April 12 filing,
following the guidelines stated in the May 11 FERC ruling. They
indicated their willingness to offer network transmission service
under terms and conditions comparable to those enjoyed by members
of the AEP System. Network users could import and export power<PAGE>
through the network, with power deliveries occurring without
separate arrangements for each transmission delivery point.
Network users would participate in transmission planning and
share transmission costs proportionately. In addition, the
supplemental filing would expand the availability of point-to-
point transmission service, including permitting such services to
be offered at a discounted rate on an hourly, nondiscriminatory
basis. A FERC hearing began in February 1995 and was recessed
until April 24, 1995 for settlement discussions.
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 1,878,000 kilowatts and is scheduled
to remain at about that level through the remaining term of the
contract. The proceeds from the sale of power by OVEC,
aggregating $308,000,000 in 1994, 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 1994. 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 299 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 880,000 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.<PAGE>
AEGCO
Since its formation, AEGCo's business has consisted of the
ownership and financing of its 50% interest in the Rockport Plant
and, more recently, 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 36% of AEGCo's operating revenue in
1994 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<PAGE>
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, revise
the rules and responsibilities under which new generating
capacity is supplied and open access to an electric utility's
transmission system; 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<PAGE>
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
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 alternative sources of energy, 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 capacity 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 alternative 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 have considered or are considering "retail wheeling"
which, in general terms, means the transmission by an electric
utility of energy produced by another entity 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 any other electric utility or
independent power producer.
The MPSC began a proceeding on September 11, 1992 to
investigate a proposal by certain industrial companies for an
experiment in retail wheeling in certain service territories in
Michigan, not including those of I&M. On April 11, 1994, the
MPSC approved an experimental five-year retail wheeling program
and ordered Consumers Power Company and Detroit Edison Company,
unaffiliated utilities, to make transmission services available
to a group of industrial customers, to be limited to 60 megawatts<PAGE>
and 90 megawatts, respectively, of retail delivery capacity. The
MPSC remanded to the administrative law judge the issue of
determining appropriate rates and charges for retail delivery
service. 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 August
1994, Detroit Edison filed a declaratory judgment complaint in
the U.S. District Court, Western District of Michigan,
challenging the jurisdiction of the MPSC to order retail
wheeling.
On April 15, 1994, the Ohio Energy Strategy Task Force
released its final report. The report contains seven broad
implementation strategies along with 53 specific initiatives to
be undertaken by government and the private sector. One strategy
recommends 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.
In addition, a retail wheeling bill was introduced in the Ohio
House of Representatives in February 1994.
Because adoption of retail wheeling would require resolution
of complex issues, such as who would pay for the unused
generating plant of the utility wheeling such power, it is not
clear what effects will flow from its adoption in any state.
However, if retail wheeling is adopted, the public utility
subsidiaries of AEP believe that they have a favorable
competitive position because of their relatively low costs.
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.
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.
Upon resolution of the issues regarding the transmission access
filing before the FERC (discussed under AEP System Transmission
Pool and Off-System Transmission), the public utility
subsidiaries of AEP expect to be able to satisfy FERC criteria to
obtain approval to sell wholesale power at market rates.<PAGE>
On June 29, 1994, the FERC issued a proposed rulemaking to
provide the regulatory framework for dealing with utility assets
that are stranded as a result of the transition to a competitive
electric industry. Stranded costs are those costs incurred by a
utility when a customer stops buying power from the utility and,
instead, purchases transmission services from that utility to
obtain power purchased from another supplier. If stranded costs
are not recovered from customers, the AEP System, like all
electric utilities, will be required by existing accounting
standards to recognize stranded investment losses. The write-off
of such stranded investment, which could include regulatory
assets, would materially adversely affect results of operations
and financial condition.
New Generation
When the AEP System needs new generation, the public utility
subsidiaries of AEP which wish to provide it may have 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. AEP and
its subsidiaries believe that they can be competitive as to both
of these factors. However, no additional generating capacity is
expected to be needed by the AEP System until about the year
2000. See Construction and Financing Program.
Indiana: In August 1994, the IURC reissued a notice of
proposed rulemaking for integrated resource planning guidelines,
including consideration of resource bidding and independent power
producers, and for demand-side management.
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 Clean Air Act
emission 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 emission
allowances, because existing federal laws address such concerns.
Virginia: The Virginia SCC 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. <PAGE>
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.
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 wholesale and retail
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, is involved in preliminary
development of some projects, has submitted jointly with a non-
affiliate a bid to provide power through an exempt wholesale
generator, and has entered into a letter of intent which may
result in the development of two 1,300-megawatt generating
stations in China. In addition, AEP and Resources have received
approval from the SEC under PUHCA to finance up to $300,000,000
for investment in exempt wholesale generators and foreign utility
companies.
AEPES offers consulting services using AEP System expertise
both domestically and internationally. AEPES contracts with
other public utilities, commercial concerns and government
agencies for the rendition of services and the licensing of
intellectual property.
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 AND FINANCING PROGRAM<PAGE>
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 growing demands for electric service.
At the present time, there are no specific commitments for new
capacity additions 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, AEP's current resource
plan indicates no need for new generation until about 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 2005. The size
of any new coal-fired generation will most likely be
significantly smaller than the 1,300-megawatt units recently
added to the AEP System, to better match projected load growth.
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.
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. The extent and timing of construction expenditures and
the nature of future financing activities may be dependent on,
among other things, the timing and amount of additional rate
relief received. See Competition -- New Generation and Rates.
PFBC Projects
Tidd Plant: In November 1990, OPCo began operating a 70,000-
kilowatt PFBC demonstration plant at the deactivated Tidd Plant
on the Ohio River at Brilliant, Ohio. The Tidd Plant was built
and operated to demonstrate that the combined-cycle PFBC
technology is a cost-effective, reliable, and environmentally
superior alternative to conventional coal-fired electric power
generation with a flue-gas desulfurization system. Through
December 31, 1994, the Tidd Plant achieved 10,297 hours of coal-
fired operation while demonstrating the viability of the PFBC
process in the reduction of targeted sulfur dioxide and nitrogen
oxide emissions. See Environmental and Other Matters for
information regarding restrictions on sulfur dioxide and nitrogen
oxide emissions from coal-fired power plants in the AEP System.
The Tidd Plant operated for a four-year period, which is expected
to conclude not later than March 31, 1995. The plant is planned
to be deactivated at the conclusion of the test program.
Total Tidd Plant construction costs (including PFBC
development costs) and total Tidd operating costs incurred
through December 31, 1994 were $182,489,000 and $36,497,000,
respectively. At such date, OPCo had received funding from DOE
and the State of Ohio in the aggregate amounts of $65,232,000 and
$11,336,000, respectively, and had recovered $125,543,000 from
its retail customers.
PFBC Utility Demonstration Project: DOE is cost sharing with
APCo development of a 340,000-kilowatt commercial-size PFBC plant
adjacent to APCo's Mountaineer Plant in New Haven, West Virginia.
DOE has agreed to continue funding the design of the plant<PAGE>
through at least January 1996; however, the program can be
terminated sooner with mutual consent of the parties. The
present four-year effort to refine the PFBC design extends
through January 1996. The ultimate decision to proceed with the
construction of the commercial PFBC plant will hinge on the
confirmation of the need for new coal-fired baseload capacity,
the readiness of PFBC technology, and other applicable market
conditions.
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 1992, 1993 and 1994
and their current estimate of 1995 construction expenditures, in
each case including AFUDC but excluding nuclear fuel and other
assets acquired under leases. The construction expenditures for
the years 1992-1994 were applied, and it is anticipated that the
estimated construction expenditures for 1995 will be applied,
approximately as follows to construction of the following classes
of assets:
<TABLE>
<CAPTION>
1992 1993 1994 1995
Actual Actual Actual Estimate
-------- -------- -------- --------
(in thousands)
<S> <C> <C> <C> <C>
AEGCO
Generating plant and facilities .. $ 3,600 $ 3,100 $ 3,900 $ 4,600
-------- -------- -------- --------
TOTAL ......................... $ 3,600 $ 3,100 $ 3,900 $ 4,600
======== ======== ======== ========
APCO
Generating plant and
facilities (a) ................ $ 34,400 $ 51,200 $ 65,600 $ 58,600
Transmission lines and facilities 54,200 36,700 38,700 38,300
Distribution lines and facilities 91,600 98,200 116,500 103,100
General plant and other facilities 11,500 4,800 9,500 14,600
-------- -------- -------- --------
TOTAL ......................... $191,700 $190,900 $230,300 $214,600
======== ======== ======== ========
CSPCO
Generating plant and facilities .. $ 21,900 $ 33,300 $ 24,800 $ 38,700
Transmission lines and facilities 11,600 10,100 3,600 9,000
Distribution lines and facilities 40,800 40,700 50,800 50,000
General plant and other facilities 1,100 2,200 2,300 10,200
-------- -------- -------- --------
TOTAL ......................... $ 75,400 $ 86,300 $ 81,500 $107,900
======== ======== ======== ========
I&M
Generating plant and facilities .. $ 66,400 $ 50,200 $ 49,700 $ 59,000
Transmission lines and facilities 17,300 10,100 20,300 30,300
Distribution lines and facilities 39,200 41,300 42,300 44,900
General plant and other facilities 3,500 6,700 2,200 7,300
-------- -------- -------- --------
TOTAL ......................... $126,400 $108,300 $114,500 $141,500
======== ======== ======== ========
KEPCO
Generating plant and facilities .. $ 4,100 $ 8,100 $ 22,600 $ 8,600
Transmission lines and facilities 8,700 6,700 6,400 8,500
Distribution lines and facilities 17,500 20,300 23,700 22,200
General plant and other facilities 1,500 0 500 4,300<PAGE>
-------- -------- -------- --------
TOTAL ......................... $ 31,800 $ 35,100 $ 53,200 $ 43,600
======== ======== ======== ========
OPCO
Generating plant and
facilities (b)(c) ............. $124,900 $112,700 $ 83,800 $ 35,900
Transmission lines and facilities 18,900 28,600 15,300 28,300
Distribution lines and facilities 42,800 46,000 45,200 48,000
General plant and other facilities 5,900 10,500 4,700 14,700
-------- -------- -------- --------
TOTAL ......................... $192,500 $197,800 $149,000 $126,900
======== ======== ======== ========
AEP SYSTEM (d)
Generating plant and
facilities (a)(b)(c) .......... $255,300 $258,600 $250,400 $205,400
Transmission lines and facilities 111,900 92,800 85,400 120,700
Distribution lines and facilities 237,700 252,300 286,900 276,100
General plant and other facilities 23,700 24,400 19,400 52,000
-------- -------- -------- --------
TOTAL ......................... $628,600 $628,100 $642,100 $654,200
======== ======== ======== ========
</TABLE>
----------
(a) Excludes expenditures for PFBC Utility Demonstration
Project. See PFBC Projects.
(b) Includes expenditures for Tidd Plant. See PFBC Projects.
(c) 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 1992, 1993 and 1994 and the current
estimate for 1995 are $93,653,000, $256,673,000,
$176,220,000 and $129,771,000, respectively. See
Environmental and Other Matters -- CAAA-AEP System
Compliance Plan.
(d) 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. If the System receives adequate rate relief in
future periods, and is able to finance additional construction
expenditures, and if the loads which are served by the System
increase above the levels currently projected, additional
expenditures may be incurred in subsequent years in amounts which
would be substantial but which cannot be accurately predicted at
this time.
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.
Proposed Transmission Facilities: 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<PAGE>
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 energy between the two companies and relieve
present constraints on the transmission of electric energy 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. A decision by the
Virginia SCC is pending.
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 1995 or early
1996, with a decision expected in 1996.
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 October 1995 and the final EIS
in 1996.
Environmental Expenditures: Expenditures related to
compliance with air and water quality standards, included in the
gross additions to plant of the System, during 1992, 1993 and
1994 and the current estimate for 1995 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 may have been or may be
adopted.
<TABLE>
<CAPTION>
1992 1993 1994 1995
Actual Actual Actual Estimate
------ ------ ------ --------
(in thousands)
<S> <C> <C> <C> <C>
AEGCo ............... $ 0 $ 0 $ 0 $ 0
APCo (a) ............ 11,200 16,800 32,000 15,000
CSPCo ............... 6,500 15,800 13,700 12,100
I&M ................. 0 0 0 1,800
KEPCo ............... 100 1,000 9,500 3,300
OPCo (b)(c) ......... 61,600 31,600 8,000 300
------- ------- ------- -------
AEP System (a)(b)(c) $79,400 $65,200 $63,200 $32,500
======= ======= ======= =======
</TABLE>
---------------<PAGE>
(a) Excludes expenditures for PFBC Utility Demonstration
Project. See PFBC Projects.
(b) Includes expenditures for Tidd Plant which have been or are
expected to be funded through Federal/state grants and the
fuel clause mechanism. See PFBC Projects.
(c) 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 1992, 1993 and 1994 and the current
estimate for 1995 are $93,653,000, $256,673,000,
$176,220,000 and $129,771,000, respectively. See
Environmental and Other Matters -- CAAA-AEP System
Compliance Plan.
Financing
It has been the practice of AEP's operating subsidiaries to
finance current construction expenditures in excess of available
internally generated funds by initially issuing unsecured short-
term debt, principally commercial paper and bank loans, at times
up to levels authorized by regulatory agencies, and then to
reduce the short-term debt with the proceeds of subsequent sales
by such subsidiaries of long-term debt securities and preferred
stock, and cash capital contributions by AEP to the subsidiaries.
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 1994, AEP issued 700,000 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
capital requirements.
During the period 1992-1994, external funds from financings
and capital contributions by AEP amounted, with respect to APCo,
CSPCo and KEPCo to approximately 37%, 1.6% and 37%, 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, 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, 1995, 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)<PAGE>
--------------- ---- ----- ---- ----- ---- ----- ---- ----------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Amount authorized .. $150 $40 $213 $163 $130 $100 $218 $1,080
==== === ==== ==== ==== ==== ==== ======
Amount outstanding:
Notes payable ... $ -- $ 7 $ -- $ -- $ -- $ 21 $ -- $ 43
Commercial paper 52 -- 120 -- 51 34 17 274
---- --- ---- ---- ---- ---- ---- ------
$ 52 $ 7 $120 $ -- $ 51 $ 55 $ 17 $ 317
==== === ==== ==== ==== ==== ==== ======
</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 long-term debt 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, debenture indentures and charters. The
most restrictive of these provisions in each instance generally
requires (1) for the issuance of additional long-term debt by
APCo, I&M and OPCo, for purposes other than the refunding of
outstanding long-term debt securities, a minimum, before income
tax, earnings coverage of twice the pro forma annual interest
charges on long-term debt, (2) for the issuance of first mortgage
bonds by CSPCo and KEPCo 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 (3) 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 long-term debt and preferred stock coverages of
APCo, CSPCo, I&M, KEPCo and OPCo under their respective debenture
indenture, 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:
<TABLE>
<CAPTION>
December 31,
----------------------
1992 1993 1994
---- ---- ----
<S> <C> <C> <C>
APCo<PAGE>
Debt coverage .............. 3.50 3.62 3.10
Preferred stock coverage ... 1.99 2.04 1.65
CSPCo
Mortgage coverage .......... 2.16 2.91 3.64
I&M
Debt coverage .............. 3.55 4.59 5.08
Preferred stock coverage ... 2.06 2.48 2.74
KEPCo
Mortgage coverage .......... 3.34 2.19 2.60
OPCo
Debt coverage .............. 3.36 4.65 4.55
Preferred stock coverage ... 2.22 2.88 2.58
</TABLE>
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 respective construction
programs 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.
CONSERVATION AND LOAD MANAGEMENT
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 electricity as opposed to
electricity supply. The AEP System utilizes integrated resource
planning and has in place a detailed analysis procedure in which<PAGE>
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. Recovery of demand-side
program expenditures through rates is being reviewed by AEP's
respective regulatory commissions.
RATES
General
In recent years the operating subsidiaries of AEP have filed a
series of rate increase applications with their respective state
commissions and the FERC and expect that they will continue to do
so as competitive conditions permit, whenever necessary, as
increases in operating, construction and capital costs exceed
increases in revenues resulting from previously granted rate
increases and increased customer demand.
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<PAGE>
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. A hearing has been scheduled to
begin in July 1995.
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,
estimated to be 1998. In 1994, $18,500,000 of net phase-in
deferrals were collected through the surcharge which reduced the
deferrals from $93,900,000 at December 31, 1993 to $75,400,000 at
December 31, 1994. 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.
Other Ohio Regulatory Matters: Reference is made to
Environmental and Other Matters -- Clean Air Act Amendments of
1990 for a discussion of emission allowances. On March 25, 1993,
the PUCO issued its final guidelines concerning emission
allowances. The final guidelines state that the PUCO expects<PAGE>
that Ohio utilities will take advantage of the allowance trading
market, and encourages all trades that can be economically
justified. The final guidelines include the proposed guideline
that gains or losses on transactions involving emission
allowances created by rate base assets should generally flow
through to ratepayers. The final guidelines also provide that
allowance plans, procedures, practices, trading activity, and
associated costs should be reviewed annually in the electric fuel
component since the cost of these allowances are part of the
acquisition and delivery costs of fuel.
Reference is made to the caption Environmental and Other
Matters -- Clean Air Amendments of 1990 -- AEP System Compliance
Plan for information regarding AEP's compliance plan which has
been filed with the PUCO.
On September 3, 1992, the PUCO began an investigation into
incentive based ratemaking under Ohio's existing ratemaking
statutes. Joint comments were filed in November 1992 by CSPCo
and OPCo.
I&M
FERC: In October 1987, a wholesale customer filed a complaint
with the FERC for a refund based on the reasonableness of coal
costs pursuant to a seven-year contract, beginning in 1986, from
an unaffiliated supplier who has leased a Utah mining operation
from I&M. In February 1993, the FERC dismissed the complaint.
The wholesale customer has appealed the FERC order to the U.S.
Court of Appeals for the District of Columbia Circuit.
KEPCo
FERC: On October 28, 1993, KEPCo filed an application to
begin serving the City of Vanceburg as a full requirements
customer, effective January 1, 1994, which will yield annual
revenues of $1,448,000. On June 9, 1994, the FERC issued a
letter order accepting for filing KEPCo's application.
On July 24, 1992, the KPSC began an investigation into the
feasibility of implementing demand-side management cost recovery
and incentive mechanisms. A Kentucky law enacted in April 1994
provides the KPSC with authority to establish cost recovery
mechanisms outside of base rate cases. On July 14, 1994, the
KPSC issued an order stating that Kentucky utilities should
pursue cost-effective DSM.
OPCo
Reference is made to Rates -- CSPCo regarding generic
proceedings by the PUCO relating to emission allowance trading
and incentive-based ratemaking.
In April 1991, the municipal wholesale customers of OPCo filed
a complaint with the FERC seeking refunds back to 1982 for
alleged overcharges for certain affiliated fuel costs. The
complaint contends that the price of coal from two of OPCo's
affiliated mines violated the FERC's market price requirement for
affiliate coal pricing. In February 1993, the FERC issued an
order dismissing the complaint and, in January 1995, the U.S.
Court of Appeals for the Sixth Circuit affirmed the FERC's order,
ending the matter.<PAGE>
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 -- Clean Air Act
Amendments of 1990 -- AEP System Compliance Plan).
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:
<TABLE>
<CAPTION>
1990 1991 1992 1993 1994
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Coal ...................... 90% 86% 93% 86% 91%
Nuclear ................... 9% 13% 6% 13% 8%<PAGE>
Hydroelectric and other ... 1% 1% 1% 1% 1%
</TABLE>
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 -- Air Pollution Control -- CAAA-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 energy 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,<PAGE>
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 3,763 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>
1990 1991 1992 1993 1994
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Total coal delivered to
AEP operated plants
(thousands of tons) ...... 52,087 45,232 44,738 40,561 49,024
Sources (percentage):
Subsidiaries ............. 25% 28% 25% 20% 15%
Long-term contracts ...... 58% 62% 65% 66% 65%
Spot or short-term
purchases ............. 17% 10% 10% 14% 20%
Average price per ton of
spot-purchased coal ...... $26.75 $25.40 $23.88 $23.55 $23.00
</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>
1990 1991 1992 1993 1994
------ ------ ------ ------ ------
Dollars per ton
<S> <C> <C> <C> <C> <C>
AEP System Companies ....... $35.23 $35.16 $34.31 $33.57 $33.95
AEGCo ...................... 21.05 20.65 20.11 17.74 18.59
APCo ....................... 39.77 41.99 43.00 42.65 39.89<PAGE>
CSPCo ...................... 37.01 35.18 33.87 33.87 32.80
I&M ........................ 27.18 25.57 24.23 23.80 22.85
KEPCo ...................... 30.71 31.38 30.24 27.08 26.83
OPCo ....................... 40.13 40.18 38.36 38.12 41.10
<CAPTION>
Cents per Million Btu's
AEP System Companies ....... 158.10 158.88 154.41 150.89 152.41
AEGCo ...................... 126.21 123.33 120.90 107.71 112.06
APCo ....................... 160.94 169.48 173.05 173.32 161.37
CSPCo ...................... 159.83 152.55 143.94 143.66 140.45
I&M ........................ 143.43 139.16 135.11 129.39 123.62
KEPCo ...................... 129.72 132.25 126.92 113.90 113.40
OPCo ....................... 171.10 171.65 163.89 161.25 173.51
</TABLE>
The coal supplies at AEP System plants vary from time to time
depending on various factors, including customers' usage of
electric energy, space limitations, the rate of consumption at
particular plants, labor unrest and weather conditions which may
interrupt deliveries. At December 31, 1994, the System's coal
inventory was approximately 65 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
1994 of the coal-fired generating units of AEP's principal
operating subsidiaries, coal requirements of these units over the
remainder of their useful lives and the average sulfur content of
coal delivered in 1994 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>
<CAPTION>
ESTIMATED
TOTAL REQUIREMENTS AVERAGE SULFUR CONTENT
CONSUMPTION FOR REMAINDER OF DELIVERED COAL
DURING 1994 OF USEFUL LIVES ----------------------------
(IN THOUSANDS (IN MILLIONS POUNDS OF SO/2/
OF TONS) OF TONS)(A) BY WEIGHT PER MILLION BTU'S
------------- --------------- --------- -----------------
<S> <C> <C> <C> <C>
AEGCo (b) ..... 5,377 258 0.3% 0.7
APCo .......... 9,455 406 0.7% 1.2
CSPCo (c) ..... 6,137 253 3.2% 5.5
I&M (d) ....... 6,865 295 0.6% 1.3
KEPCo ......... 2,315 89 1.3% 2.1
OPCo .......... 17,613 627 2.5% 4.1
</TABLE>
---------------
(a) Preliminary estimates of the effects of the Clean Air Act
Amendments of 1990 are included.
(b) Reflects AEGCo's 50% interest in the Rockport Plant.
(c) Includes coal requirements for CSPCo's interest in Beckjord,
Stuart and Zimmer Plants.
(d) 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.<PAGE>
APCo: APCo, or its subsidiaries formerly engaged in coal
mining, control coal reserves in the State of West Virginia which
contain approximately 42,000,000 tons of clean recoverable coal,
ranging in sulfur content between 1.0% and 3.5% sulfur by weight
(weighted average, 2.6% sulfur by weight).
Substantially all of the coal consumed at APCo's generating
plants is obtained from unaffiliated suppliers under long-term
contracts or on a spot purchase basis.
The average sulfur content by weight of the coal received by
APCo at its generating stations approximated 0.7% during 1994,
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 owns an undivided one-half interest in
24,000,000 tons of clean recoverable deep-mineable coal in the
State of Ohio which is located in the vicinity of its
decommissioned Poston Plant and has an average sulfur content of
2.4% by weight. Peabody Coal Company (Peabody), which owns the
remaining one-half interest, has the right to mine and sell all
of the jointly owned coal to any party on terms negotiated by
Peabody. CSPCo has an option and right of first refusal
(exercisable within a specified period after tender by Peabody)
which will permit it to purchase this coal on the same terms as
those of any contract which Peabody may negotiate with a third
party. In the event that CSPCo does not exercise such right, it
is entitled to receive a royalty on the coal from this reserve
which Peabody sells to others. However, in such a case, this
coal will not be available for CSPCo's use.
CSPCo also owns coal reserves in eastern and southeastern Ohio
which contain approximately 46,000,000 tons of clean recoverable
coal with a sulfur content of approximately 4.5% sulfur by weight
and reserves that contain approximately 10,000,000 tons of clean
recoverable coal with a sulfur content of approximately 2.4%
sulfur by weight.
CSPCo has a coal supply agreement with an unaffiliated
supplier for the delivery of 1,272,000 tons of coal per year
through March 1999. Such coal contains approximately 4% sulfur
by weight and 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.
I&M: I&M has acquired surface ownership interest in lands in
Wyoming which, it is estimated, are underlaid by approximately
730,000,000 tons of clean recoverable coal with an average sulfur
content by weight of approximately 0.5%. Federal and state coal
leases which would provide the rights and authorization to
extract this coal have not been obtained. I&M is attempting to
sell its interest in these lands.<PAGE>
I&M has entered into 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. A contract with
remaining deliveries of 72,500,000 tons expires on December 31,
2014 and a contract with remaining deliveries of 60,000,000 tons
expires on December 31, 2004.
I&M or its subsidiaries own or control coal reserves in Carbon
County, Utah, which are estimated to contain 227,000,000 tons of
clean recoverable coal with an average sulfur content by weight
of approximately 0.5% sulfur. In 1986, I&M and its two
subsidiaries signed agreements under which certain of such coal
rights, land, and related mining and preparation equipment and
facilities were leased or subleased on a long-term basis to
unaffiliated interests. In 1993, the remainder of those land and
coal rights containing approximately 108,000,000 tons of clean
recoverable coal were leased on a long-term basis to unaffiliated
interests. Mining operations in Carbon County formerly conducted
by I&M were suspended in 1984.
KEPCo: Substantially all of the coal consumed at KEPCo's Big
Sandy Plant is obtained from unaffiliated suppliers under long-
term contracts or on a spot purchase basis. KEPCo has entered
into coal supply agreements with unaffiliated suppliers pursuant
to which KEPCo will receive approximately 2,718,000 tons of coal
in 1995. 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: OPCo and certain of its coal-mining subsidiaries own or
control coal reserves in the State of Ohio which contain
approximately 218,000,000 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 107,000,000 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 30,000,000 tons
can be recovered based upon existing mining plans and projections
and employing current mining practices and techniques.
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<PAGE>
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 market
until it decides that deliveries under 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 1998 ---
Unit 2 .... --- --- 2000 1998 ---
</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. I&M also has a
contract with Cogema, Inc. for the supply of enrichment
services through 1995, depending on market conditions.
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 $82,013,000 at December 31,
1994. This amount has been recorded as long-term debt with an
offsetting regulatory asset. The regulatory asset at December
31, 1994 of $8,400,000 is being amortized as rate recovery
occurs. 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 this fee. At December 31, 1994,
funds collected from customers to dispose of spent nuclear fuel
and related earnings totaled $145,600,000.<PAGE>
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.
Studies completed in 1994 estimate decommissioning and low-
level radioactive waste disposal costs to range from $634,000,000
to $988,000,000 in 1993 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. 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 and Michigan rate cases 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
$26,000,000 in 1994, $13,000,000 in 1993 and $12,000,000 in 1992.
At December 31, 1994, I&M had recognized a decommissioning
liability of $212,000,000. 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 radiological decommissioning may be
materially different from the amounts derived from the estimates
contained in the site-specific study 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) limited experience to date 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 1994, the Financial Accounting Standards Board (FASB) added
Accounting for Nuclear Decommissioning Liabilities to its agenda.
Among the topics to be studied by the FASB is the question of
when future decommissioning liabilities should be recognized.
I&M and the electric utility industry accrue such costs over the
service life of their nuclear facilities as recovered in rates.
A new requirement from the FASB could cause the annual provisions
for decommissioning to increase should the estimate of the
remaining unaccrued decommissioning costs be greater than the
regulators' allowed recovery level. Management believes that the<PAGE>
industry's life of the plant accrual accounting method is
appropriate and should be accepted by the FASB. Until the FASB
completes its study and reaches a conclusion, the impact, if any,
on results of operations and financial condition cannot be
determined.
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 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 1990, Nevada, South Carolina and Washington, the three
states with operating disposal sites, determined that Michigan
was out of compliance with milestones established by the LLWPA
which were designed to force development of new disposal sites by
the end of 1992. Failure of a state or compact region to have met
a milestone could result in denial of access to operating sites
for waste generators within the state. Since November 1990, the
Cook Plant has been denied access to these operating sites. The
Cook Plant's low-level radioactive waste is currently 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.
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.
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 $48,598,000, subject to
inflation adjustments, and is payable in annual assessments over
the next 12 years. I&M recorded a regulatory asset concurrent
with the recording of the liability. The payments are being
recorded and recovered as fuel expense.<PAGE>
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
operating subsidiaries and that, in the long term, AEP's
operating 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 for which management is
seeking recovery 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 and Financing Program --
Construction Expenditures.
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. A utility or utility system will be deemed to
operate in compliance with the legislation if its aggregate
annual emissions do not exceed the total number of allowances
that are allocated to the utility or utility system by the
federal government and net acquisitions through purchases.
Effective January 1, 2000, the legislation establishes a maximum
national aggregate ceiling on allowances allocated to fossil
fuel-fired units larger than 25 megawatts. The allowance cap is
set at 8.95 million tons.
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 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 and Picway Unit 5; and OPCo's Gavin Units 1-
2, Muskingum River Units 1-5, Cardinal Unit 1, Mitchell Units 1-2
and Kammer Units 1-3.
The CAAA contemplate four general methods of compliance: (i)
fuel switching; (ii) technological methods of control such as
scrubbers; (iii) capacity utilization adjustments; and (iv)
acquisition of allowances to cover anticipated emissions levels.
The AEP System permit application and compliance plan filings<PAGE>
reflect, to some extent, each method of compliance.
On January 11, 1993, Federal EPA published final regulations
in the Federal Register which cover the Acid Rain Permit Program,
Allowance System, Continuous Emission Monitoring, Excess
Emissions Penalties and Offset Plans and Appeal Procedures.
These regulations included allocation of allowances for Phase I
sources. On March 12, 1993, several environmental groups, the
State of New York and a number of utilities (including APCo,
CSPCo, I&M, KEPCo and OPCo) filed petitions in the U.S. Court of
Appeals for the District of Columbia Circuit seeking a review of
the regulations. The parties have settled a number of issues,
including those relating to Substitution Unit, Compensation Unit
and Reduced Utilization plans. Oral argument has not been
scheduled for the remaining issues. Phase I permits have been
issued for all Phase I-affected units in the AEP System.
All fossil fuel-fired 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 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. These regulations 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. On December 16, 1994, OPCo and CSPCo filed
appeals seeking the suspension of NOx limits contained in acid
rain permits for Conesville, Picway and Mitchell plants pending
the reissuance of NOx regulations. On February 7, 1995, Federal
EPA published a notice in the Federal Register advising that the
NOx limitations contained in the permits for these plants were
suspended pending the remanded rulemaking.
For wet bottom wall-fired boilers, cyclone boilers, units
applying cell burner technology and all other types of boilers,
emission limitations comparable in cost to the controls
applicable to tangentially fired boilers and non-cell burner dry
bottom wall-fired boilers are to be adopted no later than January
1, 1997. The 1997 nitrogen oxides emission limitations are
required to be met by Phase II-affected sources as of January 1,
2000.
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 nonattainment of ambient air quality
standards, establishes a tiered system for classifying degrees of
nonattainment with air quality standards for ozone and mandates
that Federal EPA in cooperation with the states issue, within 240<PAGE>
days of enactment, ozone "attainment" or "nonattainment"
designations for airsheds throughout the country. Depending upon
the severity of nonattainment within a given nonattainment 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. The
deadlines for submission of new state plans and the
accomplishment of mandated emission reductions, as well as the
nature of stationary source nitrogen oxides control requirements,
also depend upon the severity of a given airshed's nonattainment.
While ozone nonattainment is largely restricted to urban areas,
several 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 NOx
emissions from the midwest must be reduced in order to achieve
the National Ambient Air Quality Standard for ozone in the
northeast. Plants currently located in areas being evaluated for
imposition of additional emission controls include Zimmer and
Beckjord Unit 6 (both partially owned by CSPCo), I&M's Tanners
Creek Plant, KEPCo's Big Sandy Plant, OPCo's Gavin Plant and
APCo's Amos, Sporn, Kanawha River and Mountaineer plants. 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.
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 has
received a court order to complete the study and submit it by
November 1995. 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 by November 1995 to prevent serious adverse effects
to public health and serious or widespread environmental effects.
It is possible that emissions from electric utility 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<PAGE>
administrative civil provisions, adding a citizens 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.
CAAA-AEP System Compliance Plan: In 1992, the PUCO approved a
systemwide Phase I CAAA 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 has emitted
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 are being 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. Fuel
switching is planned for Muskingum River Units 1-4 in 2000 and
Cardinal Unit 1 in 2001 for Phase II 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. Central Ohio Coal Company reduced
its operating level by approximately 50% in 1994. Windsor Coal
Company has also reduced its operating level to comply with the
CAAA.
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.
Management currently expects that the cost of the leased
scrubbers will be approximately $675,000,000. See Construction
and Financing Program -- Construction Expenditures. The<PAGE>
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.
The lease term is for 34 years, subject to certain termination
provisions. OPCo may purchase the scrubbers during the last 19
years of the lease term and may renew the lease for an additional
20 years.
Rent will be payable quarterly and will reflect, among other
factors, amortization of the final cost of the scrubbers and the
costs of JMG's equity and debt capital. OPCo's rental obligation
under the lease has been pledged by JMG as security for the debt
portion of its financing.
Recovery of compliance costs is being 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. 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. 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. The proponents of the theory of
global climate change maintain that the increasing concentrations
of man-made greenhouse gases will cause some of the sun's energy
that is normally radiated back into space to be trapped in the
atmosphere and that, as a result, the global temperature will
increase. 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
before new restrictions are imposed. Management is concerned
that new laws may be passed or new regulations promulgated
without sufficient scientific study and support.
At the Earth Summit in Rio de Janeiro, Brazil in June 1992,
over 150 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 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<PAGE>
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 voluntary partnerships between the
Federal government and U.S. industry. One such collaboration is
between the electric utility industry and DOE. Known as the
Utility Climate Challenge, this initiative is intended to
identify voluntary, 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 is intended to lead to reductions
in future greenhouse gas emissions through cost-effective
actions. On February 3, 1995, the AEP System entered into the
Climate Challenge Participation Accord with DOE. The Accord
contains a wide diversity 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.
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 severe command-and-
control limitations on carbon dioxide emissions if the compliance
costs incurred are not fully recovered from ratepayers. In
addition, any such severe program to stabilize or reduce carbon
dioxide emissions could impose substantial costs on industry and
society and seriously erode the economic base that AEP's
operations serve.
Ohio: On July 29, 1988, Federal EPA issued a notice of
violation alleging that OPCo's Muskingum River Plant operated in
violation of Ohio EPA's regulation governing visible emissions
during 1987. At a November 1988 enforcement conference pursuant
to Clean Air Act Section 113, OPCo representatives presented
evidence to Federal EPA indicating that the notice of violation
was not supported by factual evidence nor by law. Federal EPA
has yet to take further action.
West Virginia: The West Virginia Air Pollution Control
Commission 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. The West
Virginia Air Pollution Control Commission 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 also 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 and separate proceedings have been
initiated by OPCo with both the West Virginia Division of
Environmental Protection and Region III, Federal EPA in an effort<PAGE>
to obtain approval for utilization of the existing fuel supply
beyond September 1, 1995. The outcome of this initiative cannot
be predicted at this time.
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 is in the process of initiating administrative proceedings
under the 1985 stack height rules 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 substantially 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.<PAGE>
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 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 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.
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 Resource 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.
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
1995.
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. Recently renewed
thermal variances for Conesville and Muskingum River plants were
more stringent in their controls, but the cost impacts are not
expected to be significant.
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<PAGE>
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. 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 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.
The Comprehensive Environmental Response, Compensation, and
Liability Act 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
this Act 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 as parties responsible for clean-up at
eight federal sites, including I&M at four sites, KEPCo at one
site, OPCo at two sites and Wheeling Power Company at one site.
I&M also has been named as a party responsible for clean-up at
one state site. The companies' share of clean-up costs, however,
is not expected to be significant. AEP System companies,
including I&M and OPCo, also have been named as defendants in
contribution lawsuits for two additional sites.
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<PAGE>
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 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 three epidemiological studies of EMF and utility
workers published from 1993 through early 1995 -- each with
results that contradicted the others. One reported a weak
association between EMF and a type of adult leukemia, but not
brain cancer; while another reported a weak association with
brain cancer, but not leukemia. However, the third found no
evidence of increased deaths from cancer, including leukemia and
brain cancer. A conclusion cannot be drawn from these three
studies. The researchers are collaborating to reexamine their
data collection techniques, exposure assessments, and statistical<PAGE>
analyses to possibly reconcile their conflicting findings by
looking at the three studies together.
In addition, the research 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<PAGE>
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 operation and
financial condition of AEP and its operating subsidiaries could
be materially adversely affected unless these costs can be
recovered from rate payers.
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. See Construction and Financing Program -- PFBC
Projects.
AEP System operating companies have elected to join 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 will be phased in from
1994 through 1996. AEP's operating companies are seeking
recovery of these dues through rates, which recovery is
anticipated to closely relate to each company's membership date.
Total research and development expenditures by AEP and its
subsidiaries were approximately $7,700,000 for the year ended
December 31, 1994, $13,800,000 for the year ended December 31,
1993 and $14,200,000 for the year ended December 31, 1992,
including $2,200,000, $10,900,000 and $12,000,000, respectively,
for Tidd Plant and related PFBC costs. 1994 expenditures also
included $3,200,000 for EPRI dues.
Item 2. PROPERTIES
-----------------------------------------------------------------
At December 31, 1994, 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<PAGE>
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
Niagara Roanoke, Virginia 3,000
Reusens Lynchburg, Virginia 12,000
Hydroelectric -- Pumped Storage:
Smith Mountain Penhook, Virginia 565,000
----------
5,807,000
----------
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
----------
Kanawha Valley Power Company:
Hydroelectric -- Conventional:
London Montgomery, West Virginia 16,000(e)
Marmet Marmet, West Virginia 16,000(e)
Winfield Winfield, West Virginia 19,000(e)
----------
51,000
----------
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(f)
Kammer Captina, West Virginia 630,000
Mitchell Captina, West Virginia 1,600,000
Steam -- Coal-Fired:
Muskingum River Beverly, Ohio 1,425,000<PAGE>
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) Kanawha Valley Power Company has requested regulatory
approval to merge into APCo.
(f) The scrubber facilities at the Gavin Plant are leased. The
lease terminates in 2029 unless extended or terminated
earlier.
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:
<TABLE>
<CAPTION>
TOTAL CIRCUIT MILES
OF TRANSMISSION AND CIRCUIT MILES OF
DISTRIBUTION LINES 765,000-VOLT LINES
------------------- ------------------
<S> <C> <C>
AEP System (a) ...... 124,251(b) 2,022
APCo ................ 48,532 641
CSPCo (a) ........... 14,050 ---
I&M ................. 20,688 614
KEPCo ............... 9,854 258
OPCo ................ 28,082 509
</TABLE>
---------------<PAGE>
(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 119 high-voltage
transmission interconnections with 29 neighboring electric
utility systems. The all-time and 1994 one-hour peak System
demand was 25,940,000 kilowatts (which included 7,314,000
kilowatts 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. The net
dependable capacity to serve the System load on such date,
including power available under contractual obligations, was
23,457,000 kilowatts. The all-time and 1994 one-hour internal
peak demand was 19,236,000 kilowatts and occurred on January 19,
1994. The net dependable capacity to serve the System load on
such date, including power dedicated under contractual
arrangements, was 23,995,000 kilowatts. The all-time one-hour
integrated and internal net system peak demands and 1994 peak
demands for AEP's generating subsidiaries are shown in the
following tabulation:
<TABLE>
<CAPTION>
ALL-TIME ONE-HOUR INTEGRATED 1994 ONE-HOUR INTEGRATED
NET SYSTEM PEAK DEMAND NET SYSTEM PEAK DEMAND
---------------------------- --------------------------
(IN THOUSANDS)<PAGE>
NUMBER OF NUMBER OF
KILOWATTS DATE KILOWATTS DATE
--------- ---------------- --------- ----------------
<S> <C> <C> <C> <C>
APCo .......... 8,203 January 19, 1994 8,203 January 19, 1994
CSPCo ......... 4,172 June 17, 1994 4,172 June 17, 1994
I&M ........... 5,027 June 17, 1994 5,027 June 17, 1994
KEPCo ......... 1,575 January 19, 1994 1,575 January 19, 1994
OPCo .......... 7,291 June 17, 1994 7,291 June 17, 1994
<CAPTION>
ALL-TIME ONE-HOUR INTEGRATED 1994 ONE-HOUR INTEGRATED
NET INTERNAL PEAK DEMAND NET INTERNAL PEAK DEMAND
---------------------------- ---------------------------
(IN THOUSANDS)
NUMBER OF NUMBER OF
KILOWATTS DATE KILOWATTS DATE
--------- ---------------- --------- ----------------
<S> <C> <C> <C> <C>
APCo .......... 6,887 January 19, 1994 6,887 January 19, 1994
CSPCo ......... 3,179 June 20, 1994 3,179 June 20, 1994
I&M ........... 3,605 June 16, 1994 3,605 June 16, 1994
KEPCo ......... 1,363 February 9, 1995 1,309 January 19, 1994
OPCo .......... 5,436 January 21, 1994 5,436 January 21, 1994
</TABLE>
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.
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 71.0% during 1994
and 100% during 1993. 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 54.3% during 1994 and 96.6% during 1993. The
availability of Units 1 and 2 was affected in 1994 by outages to
refuel.
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 have continued to increase and
become less predictable, in large part due to changing regulatory
requirements and safety standards and experience gained in the<PAGE>
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 $34,000,000. 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<PAGE>
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 operation and the financial condition of AEP, I&M
and other AEP System companies.
Item 3. LEGAL PROCEEDINGS
-----------------------------------------------------------------
In February 1990, the Supreme Court of Indiana overturned an
order of the IURC, affirmed by the Indiana Court of Appeals,
which had awarded I&M the right to serve a General Motors
Corporation light truck manufacturing facility located in Fort
Wayne. In August 1990, the IURC issued an order transferring the
right to serve the GM facility to an unaffiliated local
distribution utility. In October 1990, the local distribution
utility sued I&M in Indiana under a provision of Indiana law that
allows the local distribution utility to seek damages equal to
the gross revenues received by a utility that renders retail
service in the designated service territory of another utility.
On November 30, 1992, the DeKalb Circuit Court granted I&M's
motion for summary judgment to dismiss the local distribution
utility's complaint. The local distribution utility has appealed
the decision to the Indiana Court of Appeals. I&M received
revenues of approximately $29,000,000 from serving the GM
facility. It is not clear whether the plaintiffs claim will be
upheld on appeal because the service was rendered in accordance
with an IURC order I&M believed in good faith to be valid.
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 has appealed to the Mine Safety and Health
Review Commission the July 20, 1993 and April 20, 1994
administrative law judge decisions. All remaining cases,<PAGE>
including the citations involving OPCo's mines, have been stayed.
On October 4, 1993, I&M was served with a complaint issued by
Region V, Federal EPA which alleged violations by Breed Plant of
the Clean Water Act and proposed a penalty of $70,000, which
demand was subsequently reduced to $40,000.
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 Contracts.
Pursuant to the Clean Air Act Amendments of 1990, OPCo received
sulfur dioxide emission allowances for its Kammer Plant. See
Environmental and Other Matters. Ormet's complaint seeks a
declaration that it is the owner of approximately 89% of the
Phase I and Phase II allowances issued for use by the Kammer
Plant. On May 2, 1994, AEP, OPCo and AEP Service Corporation and
its two employee defendants filed a motion seeking to dismiss the
complaint filed by Ormet Corporation. On May 2, 1994, the
Federal EPA defendants also filed a motion to dismiss. OPCo
believes that since it is the owner and operator of Kammer Plant
and Ormet is a contract power customer, Ormet is not entitled to
any of the allowances attributable to the Kammer Plant.
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<PAGE>
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. On July 27, 1994, West Virginia filed an
answer to SOCCo's complaint disputing SOCCo's entitlement to a
declaratory judgement and asserting a counterclaim seeking an
award of $2,550,000 in civil penalties, reimbursement of
monitoring costs and compensation for unspecified natural
resources damage. On October 27, 1994, SOCCo filed a motion for
summary judgement or alternatively to dismiss West Virginia's
counterclaim.
SOCCo is currently negotiating a resolution of federal and
West Virginia claims. The resolution of these legal actions is
not expected to have a material adverse impact on results of
operations.
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 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 for the Northern District of West Virginia.
At that time, a consent decree entered into by Federal EPA and
OPCo specifying compliance by the Kammer Plant with the federally
enforceable sulfur dioxide emission limit by September 1, 1995
was lodged with the court. On January 23, 1995, the consent
decree was entered by the court.
The portion of the NOV relating to penalties will be addressed
independently. At this time, management is unable to estimate
the amount of any civil penalties that may be imposed by Federal
EPA. 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, 1995.
<TABLE>
<CAPTION>
NAME AGE OFFICE (A)
------ --- ------------
<C> <C> <S>
E. Linn Draper, Jr. ... 53 Chairman of the Board, President and Chief<PAGE>
Executive Officer of AEP and of the Service
Corporation
Peter J. DeMaria ...... 60 Treasurer of AEP; Executive Vice President-
Administration and Chief Accounting Officer of
the Service Corporation
William J. Lhota ...... 55 Executive Vice President of the Service
Corporation
Charles A. Ebetino, Jr. 42 Senior Vice President-Fuel Supply of the Service
Corporation
Gerald P. Maloney ..... 62 Vice President and Secretary of AEP; Executive
Vice President-Chief Financial Officer of the
Service Corporation
James J. Markowsky .... 50 Executive Vice President-Engineering &
Construction of the Service Corporation
</TABLE>
----------
(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, 1995, 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
------ --- ------------ ------
<C> <C> <S> <C>
E. Linn Draper, Jr. ... 53 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
Joseph H. Vipperman ... 54 Director 1985-Present
President and Chief Operating
Officer 1990-Present
Executive Vice President 1989-1990
Peter J. DeMaria ...... 60 Director 1988-Present
Vice President 1991-Present
Treasurer 1978-Present
Treasurer of AEP 1978-Present
Executive Vice President-<PAGE>
Administration and Chief
Accounting Officer of the
Service Corporation 1984-Present
Treasurer of the Service
Corporation 1989-1990
William J. Lhota 55 Director 1990-Present
Vice President 1989-Present
Executive Vice President of
the Service Corporation 1993-Present
Executive Vice President-
Operations of the Service
Corporation 1989-1993
Gerald P. Maloney ..... 62 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 .... 50 Director 1993-Present
Executive Vice President-
Engineering and Construction
of the Service Corporation 1993-Present
Senior Vice President and Chief
Engineer of the Service
Corporation 1988-1993
Charles A. Ebetino, Jr. 42 Senior Vice President-Fuel Supply
of the Service Corporation 1993-Present
Vice President-Fuel Procurement
and Transportation of the
Service Corporation 1990-1993
Managing Director-Coal Procurement
of the Service Corporation 1986-1990
</TABLE>
---------------
(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, 1995, 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>
<CAPTION>
NAME AGE POSITION (A) PERIOD
------ --- ------------ ------
<C> <C> <S> <C>
E. Linn Draper, Jr. ... 53 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<PAGE>
and Chief Executive Officer of
Gulf States Utilities Company 1987-1992
Carl A. Erikson ....... 44 Director, President and Chief
Operating Officer 1993-Present
Vice President 1990-1992
President and Chief Operating
Officer of CSPCo 1993-Present
Vice President of the Service
Corporation and Executive
Assistant to E. Linn Draper, Jr. 1992-1994
Assistant to Executive Vice
President-Operations of the
Service Corporation 1989-1990
Peter J. DeMaria ...... 60 Director and Treasurer 1978-Present
Vice President 1991-Present
Treasurer of AEP 1978-Present
Executive Vice President-
Administration and Chief
Accounting Officer of the
Service Corporation 1984-Present
Treasurer of the Service
Corporation 1989-1990
William J. Lhota ...... 55 Director and Vice President 1989-Present
Executive Vice President of the
Service Corporation 1993-Present
Executive Vice President-
Operations of the Service
Corporation 1989-1993
Gerald P. Maloney ..... 62 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 .... 50 Director 1989-Present
Executive Vice President-
Engineering and Construction
of the Service Corporation 1993-Present
Senior Vice President and Chief
Engineer of the Service
Corporation 1988-1993
Charles A. Ebetino, Jr. 42 Senior Vice President-Fuel Supply
of the Service Corporation 1993-Present
Vice President-Fuel Procurement
and Transportation of the
Service Corporation 1990-1993
Managing Director-Coal Procurement
of the Service Corporation 1986-1990
</TABLE>
---------------
(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 Composite Tape
and the amount of cash dividends paid per share of Common Stock.
<TABLE>
<CAPTION>
PER SHARE
-----------------
MARKET PRICE
-----------------
QUARTER ENDED HIGH LOW DIVIDEND(1)
------------- -------- ------- -----------
<S> <C> <C> <C>
March 1993 ............ $37 $32 $.60
June 1993 ............. 38-1/2 33-3/8 .60
September 1993 ........ 40-3/8 37-1/4 .60
December 1993 ......... 39-5/8 34-5/8 .60
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 30-1/8 .60
</TABLE>
---------------
(1) See Note 5 of the Notes to the Consolidated Financial
Statements of AEP for information regarding restrictions on
payment of dividends.
At December 31, 1994, AEP had approximately 183,000
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.
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 1994 Annual Report (for the fiscal year
ended December 31, 1994).
APCO. The information required by this item is incorporated
herein by reference to the material under Selected Consolidated
Financial Data in the APCo 1994 Annual Report (for the fiscal
year ended December 31, 1994).
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 1994 Annual Report (for the fiscal year
ended December 31, 1994).<PAGE>
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 1994 Annual Report (for the fiscal
year ended December 31, 1994).
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 1994 Annual Report
(for the fiscal year ended December 31, 1994).
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 1994 Annual Report (for the fiscal year ended December
31, 1994).
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 1994 Annual Report (for the fiscal year ended December
31, 1994).
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 1994 Annual Report
(for the fiscal year ended December 31, 1994).
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 1994 Annual Report (for the fiscal year ended December
31, 1994).
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 1994 Annual Report
(for the fiscal year ended December 31, 1994).
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 1994 Annual Report (for the fiscal year ended December
31, 1994).
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.<PAGE>
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>
<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, 1995, for the
1995 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 1995
annual meeting of stockholders, to be filed within 120 days after
December 31, 1994. 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,
1995, 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
------ --- ------------------ ----------
<C> <C> <S> <C>
E. Linn Draper, Jr. ... 53 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
Richard C. Menge ...... 59 Director 1976-Present
President and Chief Operating
Officer 1989-Present
Mark A. Bailey ........ 42 Director and Vice President 1989-Present
Peter J. DeMaria ...... 60 Director 1992-Present
Vice President 1991-Present
Treasurer 1978-Present
Treasurer of AEP 1978-Present
Executive Vice President-
Administration and Chief<PAGE>
Accounting Officer of the
Service Corporation 1984-Present
Treasurer of the Service
Corporation 1989-1990
William N. D'Onofrio .. 47 Director and Vice President 1984-Present
William J. Lhota ...... 55 Director and Vice President 1989-Present
Executive Vice President of the
Service Corporation 1993-Present
Executive Vice President-
Operations of the Service
Corporation 1989-1993
Gerald P. Maloney ..... 62 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 ... 50 Director 1995-Present
Vice President 1993-Present
Executive Vice President-
Engineering & Construction of
the Service Corporation 1993-Present
Senior Vice President and Chief
Engineer of the Service
Corporation 1988-1993
A. H. Potter .......... 47 Director 1994-Present
Transmission and Distribution
Director 1987-Present
D. M. Trenary ......... 58 Director 1994-Present
Indiana Region Manager 1994-Present
Division Manager 1989-1994
W. E. Walters ......... 47 Director 1991-Present
Michiana Region Manager 1994-Present
Executive Assistant to President 1987-1994
Charles A. Ebetino, Jr. 42 Senior Vice President-Fuel Supply
of the Service Corporation 1993-Present
Vice President-Fuel Procurement
& Transportation of the
Service Corporation 1990-1993
Managing Director-Coal Procurement
of the Service Corporation 1986-1990
</TABLE>
(a) Positions are with I&M unless otherwise indicated.
(b) Dr. Draper is a director of VECTRA Technologies, Inc., Mr.
Lhota is a director of Huntington Bancshares Incorporated
and Mr. Menge is a director of Fort Wayne National
Corporation.
(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.
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
1995 annual meeting of shareholders, to be filed within 120 days
after December 31, 1994. Reference also is made to the
information under the caption Executive Officers of the<PAGE>
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, 1995, for
the 1995 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 1995
annual meeting of stockholders, to be filed within 120 days after
December 31, 1994.
CSPCO. Omitted pursuant to Instruction J(2)(c).
KEPCO. Omitted pursuant to Instruction J(2)(c).<PAGE>
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 1995
annual meeting of shareholders, to be filed within 120 days after
December 31, 1994.
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 1994, 1993 and 1992 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, 1994.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM
ANNUAL COMPENSATION COMPENSATION
___________________ __________________
PAYOUTS ALL OTHER
SALARY BONUS ------------------ COMPENSATION
NAME AND PRINCIPAL POSITION YEAR ($) ($)(1) LTIP PAYOUTS($)(2) ($)(3)
--------------------------- ---- ------- -------- ------------------ ------------
<S> <C> <C> <C> <C> <C>
E. LINN DRAPER, JR. -- chairman of the board and 1994 620,000 209,436 137,362 29,385
and chief executive officer of I&M; chairman of 1993 538,333 148,742 18,180
the board, president and chief executive officer 1992 395,833 8,730 63,700
of AEP and the Service Corporation; chairman
and chief executive officer of other AEP System
subsidiaries
PETER J. DEMARIA -- vice president, treasurer and 1994 305,000 103,029 59,032 18,750
director of I&M; treasurer and director of AEP; 1993 280,000 77,364 17,811
executive vice president -- administration and 1992 273,000 6,021 15,576
chief accounting officer and director of the
Service Corporation; vice president, treasurer
and director of other AEP System subsidiaries
G. P. MALONEY -- vice president and director of 1994 300,000 101,340 58,094 19,745
I&M; vice president, secretary and director of 1993 269,000 74,325 18,000
AEP; executive vice president -- chief financial 1992 261,000 5,757 17,036
officer and director of the Service Corporation;
vice president and director of other AEP System
subsidiaries
WILLIAM J. LHOTA -- vice president and director of 1994 280,000 94,584 54,409 19,185
I&M; executive vice president and director of the 1993 249,000 68,799 17,160
Service Corporation; vice president and director 1992 230,000 5,073 15,116
of other AEP System subsidiaries
JAMES J. MARKOWSKY -- vice president and director 1994 267,000 90,193 51,930 14,755
of I&M; executive vice president -- engineering 1993 247,000 65,259 11,165
and construction and director of the Service 1992 219,000 4,497 7,020
Corporation; vice president and director of
other AEP System subsidiaries
</TABLE>
---------------
(1) Reflects payments under the Management Incentive
Compensation Plan (MICP). Amounts for 1994 are estimates
but should not change significantly. For 1994 and 1993,
these amounts include both cash paid and a portion deferred
in the form of restricted stock units. These units are paid
out in cash after three years based on the price of AEP
Common Stock at that time. Dividend equivalents are paid<PAGE>
during the three-year period. At December 31, 1994, the
deferred amounts (included in the above table) and accrued
dividends for Dr. Draper, Messrs. DeMaria, Maloney and Lhota
and Dr. Markowsky were equivalent to 2,204, 1,109, 1,080,
1,004 and 956 units having values of $72,456, $36,458,
$35,505, $33,006 and $31,428, respectively, based upon a
$32-7/8 per share closing price of AEP's Common Stock as
reported on the New York Stock Exchange. For 1992, MICP
payments were made entirely in cash.
(2) Reflects payments under the Performance Share Incentive Plan
(which became effective January 1, 1994) for the one-year
transition performance period ending December 31, 1994. Dr.
Draper, Messrs. DeMaria, Maloney and Lhota and Dr. Markowsky
received 2,050, 881, 867, 812 and 775 shares of AEP Common
Stock, respectively, representing one-half of their
payments. See the discussion below for additional
information.
(3) For 1994, 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, $14,100; Mr. DeMaria, $4,650; Mr. Maloney, $4,500;
Mr. Lhota, $3,900; and Dr. Markowsky, $3,510; and (iii)
subsidiary companies director fees: Dr. Draper, $10,785;
Mr. DeMaria, $9,600; Mr. Maloney, $10,745; Mr. Lhota,
$10,785; and Dr. Markowsky, $6,745.
Long-Term Incentive Plans -- Awards In 1994
Each of the awards set forth below constitutes a grant of
performance share units, which represent units equivalent to
shares of AEP Common Stock, pursuant to AEP'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 AEP Common Stock are not included in the
table.
The ability to earn performance share units is tied to
achieving specified levels of total shareowner return (TSR)
relative to the S&P Electric Utility Index. Notwithstanding AEP's
TSR ranking, no performance share units are earned unless AEP
shareowners 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.
Payment of awards earned for the one-year transition
performance period ending December 31, 1994 were made 50% in cash
and 50% in AEP Common Stock. For subsequent performance periods,
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. 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 AEP Common Stock.<PAGE>
<PAGE>
<TABLE>
<CAPTION>
ESTIMATED FUTURE PAYOUTS OF
PERFORMANCE SHARE UNITS UNDER
PERFORMANCE NON-STOCK PRICE-BASED PLAN
NUMBER OF PERIOD UNTIL -----------------------------
PERFORMANCE MATURATION THRESHOLD TARGET MAXIMUM
NAME SHARE UNITS OR PAYOUT (#) (#) (#)
---------------------- ----------- ------------ --------- -------- ---------
<S> <C> <C> <C> <C> <C>
E. L. Draper, Jr. .... 2,235 1994 (1) (1) (1)
4,470 1994-1995 1,118 4,470 8,940
6,705 1994-1996 1,676 6,705 13,410
P. J. DeMaria ......... 960 1994 (1) (1) (1)
1,920 1994-1995 480 1,920 3,840
2,885 1994-1996 721 2,885 5,770
G. P. Maloney ......... 945 1994 (1) (1) (1)
1,890 1994-1995 473 1,890 3,780
2,840 1994-1996 710 2,840 5,680
W. J. Lhota ........... 885 1994 (1) (1) (1)
1,770 1994-1995 443 1,770 3,540
2,650 1994-1996 663 2,650 5,300
J. J. Markowsky ....... 845 1994 (1) (1) (1)
1,690 1994-1995 423 1,690 3,380
2,525 1994-1996 631 2,525 5,050
</TABLE>
---------------
(1) For the 1994 transition performance period, the actual
number of performance share units earned was: Dr. Draper
4,100; Mr. DeMaria 1,761; Mr. Maloney 1,734; Mr. Lhota
1,624; and Dr. Markowsky 1,550 (see Summary Compensation
Table for the cash value of these payouts).
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 I&M. 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. The amounts shown in the
table are the straight life annuities payable under the 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.
Pension Plan Table
<TABLE>
<CAPTION>
YEARS OF ACCREDITED SERVICE
HIGHEST AVERAGE --------------------------------------------------------------
ANNUAL EARNINGS 15 20 25 30 35 40<PAGE>
--------------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
$250,000 ...... $ 58,065 $ 77,420 $ 96,775 $116,130 $135,485 $152,110
350,000 ...... 82,065 109,420 136,775 164,130 191,485 214,760
450,000 ...... 106,065 141,720 176,775 212,130 247,485 277,410
600,000 ...... 142,065 189,420 236,775 284,130 331,485 371,385
750,000 ...... 178,065 237,420 296,775 356,130 415,485 465,360
</TABLE>
Compensation upon which retirement benefits are
based consists of the average of the 36 consecutive months of the
employee's highest salary, as listed in the Summary Compensation
Table, out of the employee's most recent 10 years of service.
As of December 31, 1994, the number of full years of service
credited under the Retirement Plan to each of the executive
officers of the Company named in the Summary Compensation Table
were as follows: Dr. Draper, two years; Mr. DeMaria, 35 years;
Mr. Maloney, 39 years; Mr. Lhota, 30 years; and Dr. Markowsky,
23 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 entitlements from prior
employers.
AEP has determined to pay supplemental retirement benefits to
23 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 1995 of the executive officers named in the Summary
Compensation Table, none would be eligible to receive
supplemental benefits.
AEP made available a voluntary deferred-compensation program
in 1982 and 1986, which permitted certain executive employees of
AEP System companies to defer receipt of a portion of their
salaries. Under this program, an executive 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
executive 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 ANNUAL AMOUNT OF ANNUAL ANNUAL AMOUNT OF
AMOUNT SUPPLEMENTAL AMOUNT SUPPLEMENTAL
DEFERRED RETIREMENT DEFERRED RETIREMENT
(4-YEAR PAYMENT (4-YEAR PAYMENT
NAME PERIOD) (15-YEAR PERIOD) PERIOD) (15-YEAR PERIOD)<PAGE>
---- -------- ---------------- -------- ----------------
<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 AEP and the 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 AEP and the Service Corporation on
March 1, 1992. AEP or the 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, the 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.
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, 1995, for the 1995 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, 1994.
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<PAGE>
that were beneficially owned, directly or indirectly, as of
December 31, 1994, 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 set forth opposite his name.
Fractions of shares have been rounded to the nearest whole share.
<TABLE>
<CAPTION>
AMOUNT AND NATURE OF
BENEFICIAL OWNERSHIP (A)
------------------------
<S> <C>
Mark A. Bailey ............ 1,050
Peter J. DeMaria .......... 6,105(b)(c)
William N. D'Onofrio ...... 3,811(b)
E. Linn Draper, Jr. ....... 1,492(b)
William J. Lhota .......... 7,414(b)(c)
Gerald P. Maloney ......... 4,249(b)(c)
James J. Markowsky ........ 4,861(b)
Richard C. Menge .......... 3,011(b)
A. H. Potter .............. 2,795(b)
D. M. Trenary ............. 206
W. E. Walters ............. 4,242
All directors and executive
officers as a group
(12 persons) ............ 127,621(c)(d)
</TABLE>
---------------
(a) The amounts include shares held by the trustee of the AEP
Employees Savings Plan, over which directors, nominees and
executive officers have voting power, but the
investment/disposition power is subject to the terms of such
Plan, as follows: Mr. Bailey, 1,005 shares; Mr. DeMaria,
2,398 shares; Mr. D'Onofrio, 3,251 shares; Mr. Lhota, 5,986
shares; Mr. Maloney, 2,464 shares; Mr. Menge, 2,925 shares;
Mr. Potter, 2,741 shares; Mr. Trenary, 165 shares; Mr.
Walters, 4,197 shares; and all directors and executive
officers as a group, 33,608 shares. Messrs. Bailey's,
DeMaria's, D'Onofrio's, Lhota's, Maloney's, Menge's,
Potter's, Trenary's and Walter's holdings include 44, 83,
59, 60, 85, 62, 41, 41 and 45 shares, respectively; and the
holdings of all directors and executive officers as a group
include 633 shares, each held by the trustee of the AEP
Employee Stock Ownership Plan, over which shares such
persons have sole voting power, but the
investment/disposition power is subject to the terms of such
Plan.
(b) Includes shares with respect to which such directors,
nominees and executive officers share voting and investment
power as follows: Mr. DeMaria, 3,624 shares; Mr. D'Onofrio,
500 shares; Dr. Draper, 124 shares; Mr. Lhota, 1,368 shares;
Mr. Maloney, 1,700 shares; Mr. Menge, 24 shares; and Mr.
Potter, 13 shares; and all directors and executive officers
as a group, 4,956 shares. Mr. DeMaria disclaims beneficial
ownership of 2,392 shares.
(c) 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<PAGE>
(they disclaim beneficial ownership of such shares), are not
included in their individual totals, but are included in the
group total.
(d) Represents less than 1 percent of the total number of shares
outstanding on December 31, 1994.
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 1995 annual meeting of shareholders, to
be filed within 120 days after December 31, 1994.
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, 1995, for the 1995 annual meeting of shareholders.
APCO, I&M AND OPCO. None.
AEGCO, CSPCO, AND KEPCO. Omitted pursuant to Instruction
J(2)(c).<PAGE>
<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:
<TABLE>
<CAPTION>
<S> <C>
1. Financial Statements: PAGE
----
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, 1994, 1993 and 1992; Statements of Retained
Earnings for the years ended December 31, 1994, 1993 and 1992;
Statements of Cash Flows for the years ended December 31, 1994,
1993 and 1992; Balance Sheets as of December 31, 1994 and 1993;
Notes to Financial Statements.
AEP and its subsidiaries consolidated:
Consolidated Statements of Income for the years ended December 31,
1994, 1993 and 1992; Consolidated Statements of Retained
Earnings for the years ended December 31, 1994, 1993 and 1992;
Consolidated Balance Sheets as of December 31, 1994 and 1993;
Consolidated Statements of Cash Flows for the years ended
December 31, 1994, 1993 and 1992; Notes to Consolidated
Financial Statements; Schedule of Consolidated Cumulative
Preferred Stocks of Subsidiaries at December 31, 1994 and 1993;
Schedule of Consolidated Long-term Debt of Subsidiaries at
December 31, 1994 and 1993; Independent Auditors' Report.
APCo:
Independent Auditors' Report; Consolidated Statements of Income
for the years ended December 31, 1994, 1994 and 1993;
Consolidated Balance Sheets as of December 31, 1994 and 1993;
Consolidated Statements of Cash Flows for the years ended
December 31, 1994, 1993 and 1992; Consolidated Statements of
Retained Earnings for the years ended December 31, 1994, 1993
and 1992; Notes to Consolidated Financial Statements.
CSPCo:
Independent Auditors' Report; Consolidated Statements of Income
for the years ended December 31, 1994, 1993 and 1992;
Consolidated Balance Sheets as of December 31, 1994 and 1993;
Consolidated Statements of Cash Flows for the years ended
December 31, 1994, 1993 and 1992; Consolidated Statements of
Retained Earnings for the years ended December 31, 1994, 1993
and 1992; Notes to Consolidated Financial Statements.
I&M:
Independent Auditors' Report; Consolidated Statements of Income
for the years ended December 31, 1994, 1993 and 1992;
Consolidated Balance Sheets as of December 31, 1994 and 1993;
Consolidated Statements of Cash Flows for the years ended
December 31, 1994, 1993 and 1992; Consolidated Statements of
Retained Earnings for the years ended December 31, 1994, 1993<PAGE>
and 1992; Notes to Consolidated Financial Statements.
KEPCo:
Independent Auditors' Report; Statements of Income for the years
ended December 31, 1994, 1993 and 1992; Statements of Retained
Earnings for the years ended December 31, 1994, 1993 and 1992;
Balance Sheets as of December 31, 1994 and 1993; Statements of
Cash Flows for the years ended December 31, 1994, 1993 and
1992; Notes to Financial Statements.
OPCo:
Consolidated Statements of Income for the years ended December 31,
1994, 1993 and 1992; Consolidated Balance Sheets as of December
31, 1994 and 1993; Consolidated Statements of Cash Flows for
the years ended December 31, 1994, 1993 and 1992; Consolidated
Statements of Retained Earnings for the years ended December
31, 1994, 1993 and 1992; Notes to Consolidated Financial
Statements; Independent Auditors' Report.
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
</TABLE>
(b) No Reports on Form 8-K were filed during the quarter ended
December 31, 1994.<PAGE>
<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 23, 1995
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.
SIGNATURE TITLE DATE
--------- ----- ----
(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 23, 1995
----------------------- and Director
(G. P. MALONEY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ P. J. DeMaria Vice President, March 23, 1995
----------------------- Treasurer and
(P. J. DEMARIA) 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 23, 1995
-----------------------
(G. P. MALONEY, ATTORNEY-IN-FACT)<PAGE>
<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 23, 1995
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.
SIGNATURE TITLE DATE
--------- ----- ----
(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 23, 1995
----------------------- Secretary and
(G. P. MALONEY) Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ P. J. DeMaria Treasurer and March 23, 1995
----------------------- Director
(P. J. DEMARIA)
(IV) A MAJORITY OF THE DIRECTORS:
*Robert M. Duncan
*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 23, 1995
-----------------------
(G. P. MALONEY, ATTORNEY-IN-FACT)<PAGE>
<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 23, 1995
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.
SIGNATURE TITLE DATE
--------- ----- ----
(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 23, 1995
----------------------- and Director
(G. P. MALONEY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ P. J. DeMaria Vice President, March 23, 1995
----------------------- Treasurer and
(P. J. DEMARIA) Director
(IV) A MAJORITY OF THE DIRECTORS:
*Henry Fayne
*Luke M. Feck
*Wm. J. Lhota
*James J. Markowsky
*J. H. Vipperman
*By: /s/ G. P. Maloney March 23, 1995
-----------------------
(G. P. MALONEY, ATTORNEY-IN-FACT)<PAGE>
<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 23, 1995
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.
SIGNATURE TITLE DATE
--------- ----- ----
(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 23, 1995
----------------------- and Director
(G. P. MALONEY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ P. J. DeMaria Vice President, March 23, 1995
----------------------- Treasurer and
(P. J. DEMARIA) Director
(IV) A MAJORITY OF THE DIRECTORS:
*C. A. Erikson
*Henry Fayne
*Wm. J. Lhota
*James J. Markowsky
*By: /s/ G. P. Maloney March 23, 1995
-----------------------
(G. P. MALONEY, ATTORNEY-IN-FACT)<PAGE>
<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 23, 1995
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.
SIGNATURE TITLE DATE
--------- ----- ----
(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 23, 1995
----------------------- and Director
(G. P. MALONEY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ P. J. DeMaria Vice President, March 23, 1995
----------------------- Treasurer and
(P. J. DEMARIA) Director
(IV) A MAJORITY OF THE DIRECTORS:
*Mark A. Bailey
*W. N. D'Onofrio
*Wm. J. Lhota
*James J. Markowsky
*Richard C. Menge
*A. H. Potter
*D. M. Trenary
*W. E. Walters
*By: /s/ G. P. Maloney March 23, 1995
-----------------------
(G. P. MALONEY, ATTORNEY-IN-FACT)<PAGE>
<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 23, 1995
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.
SIGNATURE TITLE DATE
--------- ----- ----
(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 23, 1995
----------------------- and Director
(G. P. MALONEY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ P. J. DeMaria Vice President, March 23, 1995
----------------------- Treasurer and
(P. J. DEMARIA) Director
(IV) A MAJORITY OF THE DIRECTORS:
*C. R. Boyle, III
*Wm. J. Lhota
*James J. Markowsky
*Ronald A. Petti
*By: /s/ G. P. Maloney March 23, 1995
-----------------------
(G. P. MALONEY, ATTORNEY-IN-FACT)<PAGE>
<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 23, 1995
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.
SIGNATURE TITLE DATE
--------- ----- ----
(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 23, 1995
----------------------- and Director
(G. P. MALONEY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ P. J. DeMaria Vice President, March 23, 1995
----------------------- Treasurer and
(P. J. DEMARIA) Director
(IV) A MAJORITY OF THE DIRECTORS:
*C. A. Erikson
*Henry Fayne
*Wm. J. Lhota
*James J. Markowsky
*By: /s/ G. P. Maloney March 23, 1995
-----------------------
(G. P. MALONEY, ATTORNEY-IN-FACT)<PAGE>
<PAGE>
<TABLE>
<CAPTION>
INDEX TO FINANCIAL STATEMENT SCHEDULES
PAGE
----
<C> <C> <S> <C>
INDEPENDENT AUDITORS' REPORT .............................. S-2
The following financial statement schedules for the years ended
December 31, 1994, 1993 and 1992 are included in this report on
the pages indicated.
</TABLE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
<C> <C> <S> <C>
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>
</TABLE>
<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, 1994 and 1993, and for each
of the three years in the period ended December 31, 1994, and
have issued our reports thereon dated February 21, 1995; such
financial statements and reports are included in your respective
1994 Annual Report to Shareowners 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.
/s/ Deloitte & Touche
Deloitte & Touche LLP
Columbus, Ohio
February 21, 1995<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
<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
(in thousands)
<S> <C> <C> <C> <C> <C>
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
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
Year Ended December 31, 1992. . . . . . . . . . . . $ 9,599 $12,888 $ 4,096(a) $19,296(b) $ 7,287
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
</TABLE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
<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
(in thousands)
<S> <C> <C> <C> <C> <C>
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
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
Year Ended December 31, 1992. . . . . . . . . . . . . $ 987 $1,810 $ 672(a) $2,745(b) $ 724
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
</TABLE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
<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 <PAGE>
(in thousands)
<S> <C> <C> <C> <C> <C>
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
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
Year Ended December 31, 1992. . . . . . . . . $1,134 $ 4,593 $1,981(a) $6,376(b) $1,332
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
/TABLE
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
<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
(in thousands)
<S> <C> <C> <C> <C> <C>
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
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
Year Ended December 31, 1992. . . . . . . . . . . . $629 $1,736 $ 650(a) $ 2,453(b) $ 562
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
</TABLE>
<TABLE>
KENTUCKY POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
<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
(in thousands)
<S> <C> <C> <C> <C> <C>
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1994. . . . . . . . . . . . . $ 208 $ 600 $ 84(a) $ 632(b) $ 260
Year Ended December 31, 1993. . . . . . . . . . . . . $ 248 $ 390 $ 179(a) $ 609(b) $ 208
Year Ended December 31, 1992. . . . . . . . . . . . . $ 352 $ 630 $ 106(a) $ 840(b) $ 248
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
</TABLE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
<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 <PAGE>
Description of Period Expenses Accounts Deductions Period
(in thousands)
<S> <C> <C> <C> <C> <C>
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
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
Year Ended December 31, 1992. . . . . . . . . . . . $ 4,815 $ 4,084 $ 618(a) $ 5,164(b) $ 4,353
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
/TABLE
<PAGE>
<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 201.24 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 (+), 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.
AEGCO
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
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 1994 Annual Report
(for the fiscal year ended December 31, 1994) which are
incorporated by reference in this filing.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
AEP++
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,<PAGE>
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)].
+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)].
+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)].
+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)].
+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)].
+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)].
+10(g)(1)(A) -- Excess Benefits Plan [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1993, File No. 1-
3525, Exhibit 10(g)(1)(A)].
+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)].
+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)].
+10(g)(3) -- Service Corporation Umbrella Trust for Executives
[Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1993, File No. 1-3525, Exhibit<PAGE>
10(g)(3)].
+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)].
*+10(i)(1) -- AEP Management Incentive Compensation Plan.
*+10(i)(2) -- American Electric Power System Performance Share
Incentive Plan, as Amended and Restated through January
1, 1995.
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 1994 Annual Report
(for the fiscal year ended December 31, 1994) 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++
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.
*3(c) -- Composite copy of the Restated Articles of Incorporation
of APCo, as amended.
3(d) -- Copy of By-Laws of APCo [Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1990, File
No. 1-3457 Exhibit 3(d)].
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);<PAGE>
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); Annual Report on Form 10-K of APCo for the fiscal
year ending December 31, 1993, File No. 1-3457, Exhibit
4(b)].
*4(b) -- Copy of Indentures Supplemental, dated August 15, 1994,
October 1, 1994 and March 1, 1995, to Mortgage and Deed
of Trust.
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,<PAGE>
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.
+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)].
+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)].
+10(f)(1) -- Management Incentive Compensation Plan [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31,
1994, File No. 1-3525, Exhibit 10(i)(1)].
+10(f)(2) -- American Electric Power System Performance Share
Incentive Plan [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1994, File No. 1-
3525, Exhibit 10(i)(2)].
+10(g)(1) -- Excess Benefits Plan [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1993, File No. 1-
3525, Exhibit 10(g)(1)(A)].
+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)].
+10(g)(3) -- Umbrella Trust 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)].
+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 1994 Annual Report
(for the fiscal year ended December 31, 1994) 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, 1994, File
No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
CSPCO++
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.
*3(c) -- Composite copy of Amended Articles of Incorporation of
CSPCo, as amended.
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,<PAGE>
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)].
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 1994 Annual Report
(for the fiscal year ended December 31, 1994) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of CSPCo [Annual Report on Form 10-
K of AEP for the fiscal year ended December 31, 1994,
File No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.<PAGE>
*27 -- Financial Data Schedules.
I&M++
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 [Annual Report on Form 10-K
of I&M for the fiscal year ended December 31, 1990, File
No 1-3570, Exhibit 3(d)].
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)].
*4(b) -- Copy of Indenture Supplemental dated May 1, 1994 to
Mortgage and Deed of Trust.
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<PAGE>
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); 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 1994 Annual Report
(for the fiscal year ended December 31, 1994) 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, 1994, 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.
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<PAGE>
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 1994 Annual Report (for
the fiscal year ended December 31, 1994) which are
incorporated by reference in this filing.
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
OPCO++
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.
*3(c) -- Composite copy of the Amended Articles of Incorporation
of OPCo, as amended.
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,<PAGE>
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 on Form 10-K of OPCo for the
fiscal year ended December 31, 1993, File No. 1-6543,
Exhibit 10(f)].
+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)].
+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)].
+10(i)(1) -- Management Incentive Compensation Plan [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31,
1994, File No. 1-3525, Exhibit 10(i)(1)].
+10(i)(2) -- American Electric Power System Performance Share
Incentive Plan, as Amended and Restated through January
1, 1995 [Annual Report on Form 10-K of AEP for the<PAGE>
fiscal year ended December 31, 1994, File No. 1-3525,
Exhibit 10(i)(2)].
+10(j)(1) -- Excess Benefits Plan [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1993, File No. 1-
3525, Exhibit 10(g)(1)(A)].
+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)].
+10(j)(3) -- Umbrella Trust 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)].
+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).
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the OPCo 1994 Annual Report
(for the fiscal year ended December 31, 1994) 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, 1994, File
No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
</TABLE>
---------------
++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.<PAGE>
<PAGE>
Exhibit 10(i)(1)
CONFIDENTIAL
AMERICAN ELECTRIC POWER SYSTEM
MANAGEMENT INCENTIVE COMPENSATION PLAN
TABLE OF CONTENTS
Page
INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . v
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 Annual Marketing Objectives . . . . . . . . . 8
4.2 Safety Performance . . . . . . . . . . . . . 9
4.3 O&M Expense vs. Budget . . . . . . . . . . . 10
4.4 Customer Service Reliability Index . . . . . 11
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 Affiliated Mine Costs . . . . . . . . . . . . 14
9.2 Safety Performance . . . . . . . . . . . . . 14
9.3 Vice President - Fuel Procurement and
Transportation Measures . . . . . . . . . . . 15
9.4 General Mine Manager/General Superintendent
Measures . . . . . . . . . . . . . . . . . . 15
9.5 Manager - River Transportation Measures . . . 16
9.6 Manager - Cook Coal Terminal Measures . . . . 17
9.7 Director - Coal Procurement Measures . . . . 17
10.0 DEPARTMENT OBJECTIVES . . . . . . . . . . . . . . . 18
11.0 THE MICP IN ACTION . . . . . . . . . . . . . . . . 19
12.0 PAYMENT RIGHTS AT TERMINATION OF ACTIVE EMPLOYMENT 22
12.1 Termination After Completion of Plan Year . . 22
12.2 Termination Due to Death, Retirement,
or Disability . . . . . . . . . . . . . . . . 22
12.3 Involuntary Termination During Plan Year . . 22
13.0 CHANGES IN SALARY / POSITION / PARTICIPATION . . . 24
14.0 PLAN ADMINISTRATION . . . . . . . . . . . . . . . . 25<PAGE>
ADDENDUM
15.0 MICP AWARD PAYMENTS/DEFERRED AWARDS . . . . . . . . A-1
16.0 POSSIBLE ADJUSTMENTS TO CORPORATE PERFORMANCE . . . A-2
17.0 FUEL SUPPLY PAYMENT SCHEDULES . . . . . . . . . . . A-3
17.1 Vice President-Fuel Procurement
& Transportation . . . . . . . . . . . . . . A-3
17.2 Price of Purchased Coal . . . . . . . . . . . A-3
17.3 River Transportation Safety . . . . . . . . . A-3
17.4 General Mine Managers . . . . . . . . . . . . A-4
17.5 Southern Ohio Coal Company - Meigs Division . A-4
17.6 Central Ohio Coal . . . . . . . . . . . . . . A-4
17.7 Windsor Coal . . . . . . . . . . . . . . . . A-5
17.8 Safety - All Mines . . . . . . . . . . . . . A-5
17.9 Manager - River Transportation . . . . . . . A-6
17.10 River Transportation Operating Cost
Per Ton Mile . . . . . . . . . . . . . . . . A-6
17.11 River Transportation Safety . . . . . . . . . A-6
17.12 Manager-Cook Coal Terminal . . . . . . . . . A-7
17.13 Cook Coal Terminal Adjusted Expenses . . . . A-7
17.14 Cook Coal Terminal Safety . . . . . . . . . . A-7
17.15 Director - Coal Procurement . . . . . . . . . A-8
17.16 Delivered Fuel Prices (Spot/Contract) . . . . A-8
17.17 Sum Total of Present Value Benefits/
Special Contract Negotiations . . . . . . . . A-8<PAGE>
INTRODUCTION
The American Electric Power System will continue the Management
Incentive Compensation Plan (MICP) during 1993, with revisions
from the 1992 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.<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. The
remaining 20% is deferred in the form of AEP common stock units
payable 3 years later (see Addendum page A-1).
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 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 EVP-
Operations.
B. AEPSC and Fuel Supply Department
Prior to becoming a participant in the Plan, specific
approval of the Chief Executive Officer is required for<PAGE>
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 Percent of Awards Allocated to
Participant Award as Organizational Units
Percent of
Base Salary
<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 50 Corporate Performance
50 Fuel Supply Performance
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<PAGE>
Operating Company G.O. 20 25 Corporate Performance
Department Heads and Executive 50 Operating Company
Assistants 25 Performance
Department Performance
25 or
75 Corporate Performance
Operating Company
Performance
Operating Company Division 20 25 Corporate Performance
Managers 25 Operating Company
50 Performance
Division 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
</TABLE>
2.0 TARGET AWARD ALLOCATIONS (Continued)
<TABLE>
<CAPTION>
Target Percent of Awards Allocated
Participant Award as to Organizational Units
Percent of
Base Salary
<S> <C> <C> <C>
Central Machine Shop Manager 20 25 Corporate Performance
75 Central Machine Shop
Performance
Fuel Supply Lancaster Senior 20 25 Corporate Performance
Staff 50 Fuel Supply Performance
25 Department Performance
or
25 Corporate Performance
75 Fuel Supply Performance
Vice President - Fuel 20 25 Corporate Performance
Procurement & Transportation 25 Fuel Supply Performance
50 Department Performance
Fuel Supply General Mine 20 25 Corporate Performance
Managers / General 25 Fuel Supply Performance
Superintendents 50 Division / Mine
Performance<PAGE>
Manager - Cook Coal Terminal 20 25 Corporate Performance
75 Cook Coal Terminal
Performance or
25 Corporate Performance
25 Fuel Supply Performance
50 Cook Coal Terminal
Performance
Manager - River Transportation 20 25 Corporate Performance
75 River Transportation
Performance or
25 Corporate Performance
25 Fuel Supply Performance
50 River Transportation
Performance
Director - Coal Procurement 20 25 Corporate Performance
25 Fuel Supply Performance
50 Department Performance
</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.<PAGE>
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 ROE Performance
ROE Factor* 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 interim 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) divided by 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<PAGE>
<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 aver-
age 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.<PAGE>
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:
<TABLE>
<CAPTION>
Operating Company and Division Target Award Payment Schedules
Annual Marketing Results vs. Goal
Results as Percent of Goal Performance Factor*
<S> <C>
Over 110% 1.50
105% 1.25
100% 1.00
95% .50
Below 95% 0
</TABLE>
*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:
The sum of (i) 1.25 and (ii) .25 times [(108% minus
105%) divided by (110% minus 105%)], which equals 1.40<PAGE>
4.2 Safety Performance of each Operating Company and Division is
measured by improvement in three indices, each weighted from
25% to 50% as indicated. The three are as follows:
Lost Workday Case Incidence Rate (weighted 25%) -
Number of lost workday cases per 200,000 work hours. A
three-year average incidence rate is calculated for all
of the Operating Companies combined. Target is set for
a 15% improvement over the three-year combined Company
average. The same calculations are made for each
Division and all of the Divisions in the System
combined. The Division target is a 15% improvement
over the three-year combined Division average.
Recordable Case Incidence Rate (weighted 50%) - Number
of recordable cases per 200,000 work hours. A three-
year average incidence rate is calculated for all of
the Operating Companies combined. Target is set for a
15% improvement over the three-year combined Company
average. The same calculations are made for each
Division and all of the Divisions in the System
combined. The Division target is set for a 15%
improvement over the three-year combined Division
average.
Lost Workday Rate (weighted 25%) - Number of days away
from work and restricted activity days per 200,000 work
hours. A three-year average lost workday rate is
calculated for all of the Operating Companies combined.
Target is set for a 15% improvement over the three-year
combined Company average. The same calculations are
made for each Division and all of the Divisions in the
System combined. The Division target is set for a 15%
improvement over the three-year combined Division
average.
The percent improvement over the three-year combined average is
calculated for each measure and the related performance factor
averaged to yield a single performance factor for safety
performance.
For the purposes of these measures, Wheeling Power and Kingsport
Power are considered Divisions.
<TABLE>
<CAPTION>
Operating Company and Division Target Award Payment Schedules
Improvement Over Three-Year Average
Operating Company or Division Safety Performance
Percent Improvement Over Performance
Three-Year Average Factor*<PAGE>
<S> <C>
30 or better 1.50
22.50 1.25
15.00 1.00
11.25 .75
7.50 .50
3.75 .25
0 or worse 0
</TABLE>
*Interpolate at intermediate performance.
Example: If a Division achieves a 15% improvement in lost workday
case incidence rate, a 30% improvement in recordable case
incidence rate, and a 7.5% improvement in lost workday rate, the
respective performance factors are 1.00, 1.50 and .50. Multiply
the performance factor by the assigned weight percentage and the
total yields a single performance factor of 1.125.
The performance factor shall be zero for any Division whose
recordable injuries include a fatality or a permanent total
disability case.
When a Division or Operating Company works less than 500,000
hours in a calendar year the maximum performance factor for both
the lost workday case incidence rate and the lost workday rate,
will each be 1.00. Such performance factor(s) may be increased
up to 1.50 on recommendation of the Operating Company President
and EVP-Operations, based on the attainment of specific
objectives in safety and health management, or the affected
manager's specific contributions to the safety records of the
operation.
4.3 O&M Expense Performance vs. Budget is measured by comparing
controllable operating and maintenance expenses against
budget for the current year. Perperformance 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.
<TABLE>
<CAPTION> Operating Company and Division
Target Award Payment Schedules<PAGE>
Controllable O & M Expenses vs. Budget
Expenses as Percent of Budget* Performance Factor
<S> <C>
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
</TABLE>
*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:
(i) 100 times the sum of [Cur. Interpt. Freq. Index
divided by (5 minus the Yr. Avg. Intm. Freq. Index)]
and [Cur. Interpt. Dur. Index divided by (5 minus Yr.
Avg. Intm. Dur. Index)] divided by (ii) 2
Resulting performance factors are determined as follows:
Operating Company and Division
Target Award Payment Schedules
<TABLE>
<CAPTION> Customer Service
Reliability Index vs. Prior Five-Year Average
Service Reliability Performance Factor*
Index
<S> <C>
85% or lower 1.50
92.5% 1.25
100% 1.00
105% .50
110% or higher 0
</TABLE/>
*Interpolate at intermediate performance.<PAGE>
Example: If an Operating Company's current reliability index is
97%, 3% better than its five-year average of 100%, the
performance factor is 1.10, which equals the sum of (i) 1 and
(ii) .25 times [(100% minus 97%) divided by (100% minus 92.5%)}
Special adjustments may be considered for catastrophic
situations. (See page 3 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<PAGE>
There are two overall Fuel Supply performance measures, which are
weighted to determine a single Fuel Supply performance factor.
These are as follows:
Average cost of coal produced from affiliated mines,
measured by cents per million BTU (cents/MM BTU) for the
current year - weighted at 75%; 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 Affiliated Mine Costs
The cost of coal produced as measured by cents/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:
</TABLE>
<TABLE>
<CAPTION> Fuel Supply Target Award Payment Schedules
Affiliated Mine Costs
cents/MM BTU Performance Factor*
<S> <C>
153 or lower 1.50
158 1.25
163 1.00
Higher than 163 0
</TABLE>
*Interpolate at intermediate performance.
Example: If the average cost of coal produced were 160 cents/MM
BTU, the performance factor would be 1.15, which equals the sum
of (i) 1 and (ii) .25 times [(163 minus 160) divided by (163
minus 158)]
9.2 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:
<TABLE>
<CAPTION> Fuel Supply Target Award Payment Schedules
Safety - Incidence Rate vs. Coal Industry<PAGE>
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
</TABLE>
*Interpolate at intermediate performance.
Example: If Fuel Supply's incidence rate were 92% of the coal
industry rate, the performance factor is .40, which equals the
sum of (i) .25 and (ii) .25 times [(95% minus 92%) divided by
(95% minus 90%)].
9.3 Vice President - Fuel Procurement and Transportation
Measures
In addition to the Corporate performance measures weighted
25% and the overall Fuel Supply performance measures which
is weighted 25%, the Vice President - Fuel Procurement and
Transportation has two Department performance measures which
are weighted to determine a single Department performance
weighting of 50%. These are as follows:
Cost of coal purchased against the GDP Price Index (fixed
weight), a national index which measures inflation of price
for the current year - weighted 75%; and
Safety at River Transportation and Cook Coal Terminal
measured by percent improvement in incidence rate for the
current year over the prior three year average incidence
rate - weighted 25%.
Tables showing the performance factors and how they relate
to achievement are on page A-3 of the Addendum.
9.4 General Mine Managers/General Superintendents Measures
In addition to the Corporate performance measures weighted
25% and the overall Fuel Supply performance measure weighted
25%, the Fuel Supply General Mine Managers and General
Superintendents have two Division/Mine performance measures
which are weighted to determine a single Division/Mine
performance weighting of 50% for the mines for which they
are responsible. These are as follows:<PAGE>
General Mine Managers - Cost of coal produced measured in
the current year by cents per million BTU (cents/MM BTU) -
weighted at 75%;
General Superintendents - Production cost of coal produced
measured in the current year by cents per million BTU
(cents/MM BTU) - 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-4 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.
9.5 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 mils per ton mile (mils/ton
mile-$0.00x) for the current year, excluding cost for fuel -
weighted 75%; and
Safety performance measured by the percent improvement in
incidence rate for the current year over the prior three
year average incidence rate for River Transportation -
weighted 25%.
Tables showing the performance factors and how they relate
to achievement are on page A-7 of the Addendum.
9.6 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, +
adjustment volumes times 25 cents/ton - weighted 75%; and<PAGE>
Safety performance measured by the percent improvement in
incidence rate for the current year over the prior three-
year average incidence rate for Cook Coal Terminal -
weighted 25%.
Tables showing the performance factors and how they relate
to achievement are on page A-7.
9.7 Director - Coal Procurement Measures
The Director - Coal Procurement has, in addition to the
overall Corporate performance measures weighted 25% and the
overall Fuel Supply performance measure weighted 25%, two
Department performance measures which are weighted to
determine a single Department performance weighting of 50%
for Coal Procurement. These are:
Delivered fuel prices (spot/contract) composited change as a
percent of the GDP price index (fixed weight) - 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
25%.
Tables showing the performance factors and how they relate
to achievement are on page A-8.
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<PAGE>
the MICP work. For purposes of this example, assume that an
Operating Company Division Manager with annual base salary
earnings of $70,000 has a target award of 20%, or $14,000. This
individual's target award is allocated among the following
performance criteria:
AEP Corporate Performance: 25%, or $3,500
Operating Company Performance: 25%, or $3,500
Division Performance: 50%, or $7,000
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.
<TABLE>
<S> <C> <C> <C> <C> <C> <C> <C>
ROE 14% actual ROE = 1.00
S&P ranking = 1.40
(7th)
Average 1.20 x 25% = .30
TIR S&P ranking = .80 x 25% = .20
(12th)
Realization AEP ratio (.80) = 1.25 x 50% = .625
Ratio
Corporate Performance Factor = 1.125
The AEP Corporate award, then, is 1.125 x $3,500, or
$3,937.50.
</TABLE>
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>
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Achievement of Result = 105% = 1.25 x 25% = .3125
Annual Marketing
Objectives<PAGE>
Safety Performance Result = 22.5% = .75 x 25% = .1875
O&M Expense Result = 93% = 1.00 x 25% = .2500
Performance vs.
Budget
Customer Service Result = 97% = 1.10 x 25% = .2750
Reliability Index
Operating Company Performance Factor = 1.025
The Operating Company Award, then, is 1.025 x $3,500, or
$3,587.50
</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>
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Achievement of Result = 107% = 1.35 x 25% = .3375
Annual Marketing
Objectives
Safety Result = 22.5% = 1.25 x 25% = .3125
Performance
O&M Expense Result = 97% = 1.50 x 25% = .3750
Performance vs.
Budget
Customer Service Result = 100% = 1.00 x 25% = .2500
Reliability Index
Performance Factor = 1.275
The Division award, then, is 1.275 x $7,000, or $8,925.00
</TABLE>
11.4 Assuming the earnings per share for the year permitted a
100% payout, the Operating Company Division Manager in our
example earned a total award of $16,450.00, as follows:
AEP Corporate $ 3,937.50
Operating Company 3,587.50
Division 8,925.00
$16,450.00<PAGE>
Of that amount, 80%, or $13,160.00 is paid during the first
part of the following year. The balance, $3,290.00, 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.)
However, if earnings per share were $2.60 for the year, the
payout would be reduced to 75% of total award (see item 1.2
on page two for an explanation of how MICP awards are
affected by earnings per share). The Division Manager in
this situation would have a total award of $12,337.50
instead of $16,450.00, i.e., $16,450.00 x .75 = $12,337.50.
The total 75% award of $12,337.50 would be paid out as 80%
cash and 20% deferred as explained above.
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 12/31/93, and subsequently terminates is
entitled to the 80% cash award for Plan year 1993, and if
applicable, the value of his 1990 Plan year deferred amount.
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.
Deferred awards are payable 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<PAGE>
the AEP System Retirement Plan.
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.
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 and/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
deferred amounts that have not met the three calendar year
requirement, 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.<PAGE>
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 Compen-
sation 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 PAYMENTS/DEFERRED AWARDS
When all of the necessary data is available after the end of the
Plan year, performance results will be calculated and awards made
as soon as practicable. Eighty percent of the award earned will
be paid in cash.
Twenty percent of any awards made under the MICP will
automatically be deferred in AEP stock unit accounts. No company
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.<PAGE>
Amounts deferred in stock units are paid 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 paid.
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 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.
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 Vice President - Fuel Procurement and Transportation
17.2 Fuel Supply Target Award Payment Schedules
<TABLE>
<CAPTION>
Change in Price of Purchased Coal as Percent
of GDP Price Index (Fixed Weight)
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
/TABLE
<PAGE>
*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.
17.3 Fuel Supply Target Award Payment Schedules
<TABLE>
<CAPTION>
River Transportation and Cook Coal Terminal Safety
Percent Improvement Over Performance Factor*
Three-Year Average
Incidence Rate
<S> <C>
30 or better 1.50
22.50 1.25
15.00 1.00
11.25 .75
7.50 .50
3.75 .25
0 or worse 0
</TABLE>
*Interpolate at intermediate performance.
17.4 General Mine Managers
17.5 Southern Ohio Coal Company - Meigs Division
<TABLE>
<CAPTION>
Cost of Coal Produced
cents/MM BTU Performance Factor*
<S> <C>
157 or lower 1.50
162 1.25
167 1.00<PAGE>
Higher than 167 0
</TABLE>
*Interpolate at intermediate performance.
17.6 Central Ohio Coal Company
<TABLE>
<CAPTION>
Cost of Coal Produced
cents/MM BTU Performance Factor*
<S> <C>
156 or lower 1.50
161 1.25
165 1.00
Higher than 165 0
</TABLE>
*Interpolate at intermediate performance.
17.7 Windsor Coal Company
<TABLE>
<CAPTION>
Cost of Coal Produced
cents/MM BTU Performance Factor*
<S> <C>
133 or lower 1.50
138 1.25
143 1.00
Higher than 143 0
</TABLE>
*Interpolate at intermediate performance.
17.8 All Coal Mines<PAGE>
<TABLE>
<CAPTION>
Safety - Incidence Rate vs. Coal Industry
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
</TABLE>
*Interpolate at intermediate performance.
17.9 Manager - River Transportation
17.10 River Transportation
<TABLE>
<CAPTION>
Operating Cost Per Ton Mile
Mils/Ton Mile
($.00x) Performance Factor*
<S> <C>
5.00 or better 1.50
5.20 1.25
5.40 1.00
5.60 .75
5.80 .50
6.00 .25
Higher than 6.20 0
</TABLE>
*Interpolate at intermediate performance.<PAGE>
17.11 River Transportation Safety
<TABLE>
<CAPTION>
Percent Improvement Over Three-Year Base Average
Percent Improvement Over
Three-Year Average Performance Factor*
Incidence Rate
<S> <C>
30 or better 1.50
22.50 1.25
15.00 1.00
11.25 .75
7.50 .50
3.75 .25
0 or worse 0
</TABLE>
*Interpolate at intermediate performance.
17.12 Manager - Cook Coal Terminal
17.13 Cook Coal Terminal
<TABLE>
<CAPTION>
Adjusted Expenses
Adjusted Expenses Performance Factor*
<S> <C>
$6.90 million or better 1.50
$7.10 1.25
$7.30 1.00
$7.50 .75
$7.70 .50
$7.90 .25
$8.10 million or higher 0<PAGE>
</TABLE>
*Interpolate at intermediate performance.
17.14 Cook Coal Terminal Safety
<TABLE>
<CAPTION>
Percent Improvement Over Three - Year Average
Percent Improvement Over
Three-Year Average Performance Factor*
Incidence Rate
<S> <C>
30 or better 1.50
22.50 1.25
15.00 1.00
11.25 .75
7.50 .50
3.75 .25
0 or worse 0
</TABLE>
*Interpolate at intermediate performance.
17.15 Director - Coal Procurement
17.16 Delivered Fuel Prices (Spot/Contract)
<TABLE>
<CAPTION>
Fuel Supply Target Award Payment Schedule Composited
Change in Price of Purchased Coal as Percent
of GDP Price Index (Fixed Weight)
Percent of GDP Price Index Performance Factor*
<S> <C>
60 or lower 1.50
70 1.25
80 1.00
100 .50<PAGE>
110 .25
Higher than 110 0
</TABLE>
*Interpolate at intermediate performance.
17.17 Sum Total of Present Value Benefits/
Special Contract Negotiations
<TABLE>
<CAPTION>
Fuel Supply Target Award Payment Schedule Sum Total
of PV Benefits Special Contract Renegotiations
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
</TABLE>
*Interpolate at intermediate performance.
/PAGE
<PAGE>
<PAGE>
Exhibit 10(i)(2)
American Electric Power System
Performance Share Incentive Plan
as Amended and Restated through January 1, 1995
Article 1. Establishment and Purpose
1.1 Establishment of the Plan.
The Company hereby establishes an incentive compensation plan to
be known as the "American Electric Power System Performance Share
Incentive Plan" (the "Plan"), as set forth in this document.
1.2 Purposes.
The Purposes of the Plan are to provide competitive, longer-term,
performance driven, incentive compensation opportunities to
Participants, which are directly related to and dependent upon
the competitiveness of the longer-term returns realized by the
Company's shareholders; and to facilitate ownership of Restricted
Stock Units by Participants so as to equate further their long-
term financial interests with those of the shareholders.
Article 2. Effective Date and Term of Plan
The Plan was approved by the Company's shareholders and the
Securities and Exchange Commission effective January 1, 1994.
While the Board may suspend or terminate the Plan at any time, no
such suspension or termination shall adversely affect any
outstanding Performance Share Units without the Participant's
written consent as specified in Section 12.2. No Performance
Share Units shall be granted for Performance Periods commencing
after December 31, 2003.
Article 3. Definitions
Whenever used in the Plan, the following terms shall have the
meanings set forth below and, when the meaning is intended, the
initial letter of the word is capitalized:
(a) "Award Certificate" means a certificate setting forth
the terms and provisions applicable to each grant of
Performance Share Units, which shall include, but
shall not be limited to, the number of Performance
Share Units granted to the Participant, the
Performance Measure, the levels of Performance Share
Unit payment opportunities based on the Performance
Measure, the method of determining earned Performance
Share Units pursuant to Section 8.1 and the length of<PAGE>
the Performance Period.
(b) "Board" means the Board of Directors of the Company.
(c) "Committee" shall mean the Human Resources Committee
of the Board.
(d) "Common Stock" shall mean the common stock of the
Company.
(e) "Company" means American Electric Power Company,
Inc., a New York corporation, and any successor
thereto.
(f) "Director" means an individual who is a member of the
Board.
(g) "Disability" shall have the definition set forth in
the American Electric Power System Retirement Plan.
(h) "Equivalent Stock Ownership Target" means a stock
ownership target for each Participant established by
the Board which is a combination of Common Stock and
Common Stock equivalents held by a Participant.
(i) "Fair Market Value" means the closing sale price of
the Common Stock, as published in The Wall Street
Journal report of New York Stock Exchange Composite
Transactions on the date in question or, if the
Common Stock shall not have been traded on such date
or if the New York Stock Exchange is closed on such
date, then the first day prior thereto on which the
Common Stock was so traded.
(j) "Participant" means any full-time, nonunion employee
of any Subsidiary, who has been selected to
participate in the Plan for a stipulated Performance
Period by the Committee.
(k) "Performance Measure" means, for a period of at least
three years, the financial objective to be applied to
the Performance Period in which Performance Share
Units held by a Participant for a Performance Period
are earned, based on the relative ranking of the Com-
pany's TSR compared to the TSR's of the companies
comprising the S&P Electric Utility Index.
(l) "Performance Period" means the period established by
the Committee, during which the number of Performance
Share Units earned by Participants shall be
determined.
(m) "Performance Share Unit" means a measure of
participation, expressed as a share of Common Stock,
received as a grant under Section 7.1 or as a
dividend under Section 7.2.
(n) "Restricted Stock Unit" means a measure of value,
expressed as a share of Common Stock, allocated to a
Participant under Section 8.1. No certificates shall
be issued with respect to such Restricted Stock
Units, but the Company shall maintain a bookkeeping
account in the name of the Participant to which the
Restricted Stock Units shall relate.
(o) "Retirement" means termination of employment with any
Subsidiary other than for cause after attaining age
55 and at least five (5) years of service.
(p) "Rule 16b-3" means Rule 16b-3 promulgated under the
Securities Exchange Act of 1934, as amended (or any
successor provision at the time in effect).
(q) "Section 162(m)" means Section 162(m) of the Internal
Revenue Code of 1986, as amended and applicable
interpretive authority thereunder.
(r) "Subsidiary" shall mean any corporation in which the
Company owns directly or indirectly through its
Subsidiaries, at least fifty percent (50%) of the
total combined voting power of all classes of stock,
or any other entity (including, but not limited to,
partnerships and joint ventures) in which the Company
owns at least fifty percent (50%) of the combined
equity thereof.
(s) "Transition Performance Period" means the one (1) and
two (2) year Performance Periods that may be made
available on a one-time basis to Participants
receiving Performance Share Units at the commencement
of the Plan and Participants receiving their first
grant of Performance Share Units for a Performance
Period at any time during the term of the Plan.
(t) "TSR" means total shareholder return and is the
compound product of the annual TSR amounts obtained
by dividing: (1) the sum of: (i) the annual amount of
dividends for each year of the Performance Period,
assuming dividend reinvestment, and (ii) the
difference between the share price at the end and the
beginning of each year of the Performance Period; by
(2) the share price at the beginning of each year of
the Performance Period.
Article 4. Administration
4.1 The Committee.
The Plan shall be administered by the Committee consisting of not
less than three (3) Directors. Each member of the Committee
shall at all times while serving be a "disinterested person"
within the meaning of Rule 16b-3 and an "outside director" within
the meaning of Section 162(m).
4.2 Authority of the Committee.
Subject to the provisions herein and to the approval of the
Board, the Committee shall have full power for the following:
(a) Selecting Participants to whom Performance Share
Units are granted.
(b) Determining the size and frequency of grants (which
need not be the same for each Participant), except as
limited by Article 5.
(c) Construing and interpreting the Plan and any
agreement or instrument entered into under the Plan.
(d) Establishing, amending, rescinding or waiving rules
and regulations for the Plan's administration.
(e) Amending, modifying, and/or terminating the Plan,
subject to the provisions of Article 12 herein.
Further, the Committee shall have the full power to make all
other determinations which may be necessary or advisable for the
administration of the Plan, to the extent consistent with the
provisions of the Plan, and subject to the approval of the Board.
As permitted by law, the Committee may delegate its authority as
identified hereunder; provided, however, that the Committee may
not delegate certain of its responsibilities hereunder if such
delegation may jeopardize compliance with the "disinterested
administration" requirement of Rule 16b-3 and the "outside
directors" provision of Section 162(m).
4.3 Decisions Binding.
All determinations and decisions made by the Committee pursuant
to the provisions of the Plan, and all related orders or
resolutions of the Board shall be final, conclusive, and binding
on all persons, including the Company, its shareholders,
Participants and their estates, and beneficiaries.
Article 5. Maximum Awards and Adjustments
5.1 Maximum Amount Available for Awards.
The maximum number of Performance Share Units which may be earned
during the term of the Plan on an aggregate basis is 1,000,000
and, for one Performance Period, the maximum number of
Performance Share Units which may be earned by a Participant is
25,000.
Not more than 1,000,000 shares of Common Stock will be available
for delivery upon payment for Performance Share Units earned
under the Plan. The shares to be delivered under the Plan will
be made available from shares reacquired by the Company.
The limitations in this Section 5.1 on the maximum amount of
Performance Share Units and shares of Common Stock available
under the Plan are subject to adjustment as provided in Section
5.2.
5.2 Adjustments.
If the 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
maximum number of Performance Share Units which may be earned on
an aggregate basis or by a Participant, the maximum number of
shares of Common Stock which may be delivered, as specified in
Section 5.1, and the number of Restricted Stock Units held by a
Participant.
Article 6. Eligibility and Participation
6.1 Eligibility.
Eligibility for participation in the Plan shall be limited to
senior officers of the Company and/or its Subsidiaries who, in
the opinion of the Committee, have the capacity for contributing
in a substantial measure to the successful performance of the
Company.
6.2 Actual Participation.
Participation in the Plan shall begin on the first day of each
Performance Period. At the beginning of each Performance Period,
the Committee will identify which, if any, Participants shall
receive a grant of Performance Share Units for that Performance
Period. As soon as practicable following selection, a
Participant shall receive an Award Certificate.
Article 7. Grants of Performance Share Units
7.1 Grant Timing, Frequency and Number.
Performance Share Units may be granted to Participants as of the
first day of each Performance Period on an annual basis. It is
intended that Performance Periods will overlap. However, grants
do not necessarily have to be on an annual basis. The number of
Performance Share Units to be granted to each Participant shall
be determined by the Committee in its sole discretion.
7.2 Dividends.
During the Performance Period, Participants will be credited with
dividends, equivalent in value to those declared and paid on
shares of the Common Stock, on all Performance Share Units
granted to them. These dividends will be regarded as having been
reinvested in Performance Share Units on the date of the Common
Stock dividend payments based on the then Fair Market Value of
the Common Stock, thereby increasing the number of Performance
Share Units held by a Participant.
Participants will be credited with dividend equivalents, equal in
value to those declared and paid on shares of Common Stock, on
all Restricted Stock Units allocated to the Participants.
Dividend equivalents on Restricted Stock Units required to be
held pursuant to Section 8.2 or deferred pursuant to Section 8.4
will be regarded as having been reinvested in Restricted Stock
Units on the date of the Common Stock dividend payments based on
the then Fair Market Value of the Common Stock, thereby
increasing the number of Restricted Stock Units held by a
Participant. However, once a Participant attains the desired
Equivalent Stock Ownership Target, dividend equivalents on
Restricted Stock Units held pursuant to Section 8.2 shall be paid
to the Participant in cash on the same date Common Stock
dividends are paid.
7.3 Performance Periods.
Subject to the next sentence, the Committee shall establish
Performance Periods in its discretion. Performance Periods
shall, in all cases, be at least three (3) years in length,
except for the Transition Performance Periods.
The first Performance Periods shall be the one (1) and two (2)
year Transition Performance Periods ending December 31, 1994 and
December 31, 1995, respectively, and the three-year period
beginning January 1, 1994 and ending December 31, 1996.
Performance Share Units granted as part of the initial grant of
Performance Share Units for such Performance Periods shall be
deemed to be granted as of the first day of such Performance
Periods.
Article 8. Determination and Payment
8.1 Determination.
The number of Performance Share Units earned by a Participant for
a Performance Period shall be determined by multiplying the
number of Performance Share Units held by the Participant at the
end of the Performance Period by a factor based upon the
Performance Measure. No Performance Share Units shall be earned
by any Participant if, at the end of the Performance Period,
shareholders do not realize a positive TSR under the Performance
Measure. In any event, the Committee may, at its discretion,
reduce the number of Performance Share Units earned by any
Participant for a Performance Period.
Earned Performance Share Units shall be converted to Restricted
Stock Units if the Participant has not met the Equivalent Stock
Ownership Target. A Participant shall receive one Restricted
Stock Unit for each earned Performance Share Unit. Once a
Participant has attained the Equivalent Stock Ownership Target,
earned Performance Share Units shall be paid to the Participant
at the end of the Performance Period as provided in Section 8.3
or may be deferred by the Participant as provided in Section 8.4.
8.2 Holding of Restricted Stock Units.
Restricted Stock Units required to meet the Equivalent Stock
Ownership Target will be held until the Participant terminates
employment at which time the Participant shall receive payment
for the Restricted Stock Units.
8.3 Payment of Restricted Stock Units and Earned Performance
Share Units.
The payment of Restricted Stock Units that were required to be
held pursuant to Section 8.2 shall be made in cash or shares of
Common Stock, or a combination of both, as then elected by the
Participant and as approved by the Committee. Any cash payments
of Restricted Stock Units shall be calculated on the basis of the
average of the Fair Market Value of the Common Stock for the last
20 trading days prior to the date the Participant terminates
employment. Payment in Common Stock shall be at the rate of one
share of Common Stock for each Restricted Stock Unit.
The payment of earned Performance Share Units not required to be
converted to Restricted Stock Units pursuant to Section 8.1 shall
be made in cash or shares of Common Stock, or a combination of
both, as then elected by the Participant and as approved by the
Committee. Any cash payment of earned Performance Share Units
shall be calculated on the basis of the average of the Fair
Market Value of the Common Stock for the last 20 trading days of
the Performance Period for which the Performance Share Units were
earned. Payment in Common Stock shall be at the rate of one
share of Common Stock for each earned Performance Share Unit.
8.4 Deferrals.
Once the Participant attains the Equivalent Stock Ownership
Target, the Participant may make annual elections to defer the
payment of subsequent earned Performance Share Units for at least
one year but in no event any later than the Participant's
termination of employment. The deferral election must be made at
least one year prior to the end of the Performance Period for
which the Participant has received an allocation with regard to a
Performance Period and each earned Performance Share Unit shall
be converted into a Restricted Stock Unit. Payment of the
elective deferrals will be made at the end of the deferral period
in cash or shares of Common Stock, or a combination of both as
then elected by the Participant and as approved by the Committee.
Cash payments of Restricted Stock Units shall be calculated on
the basis of the average of the Fair Market Value of the Common
Stock for the last 20 trading days of the deferral period.
Payment in Common Stock shall be at the rate of one share of
Common Stock for each Restricted Stock Unit.
8.5 Performance Share Units Granted in 1994.
Performance Share Units granted in 1994 for the two Transition
Performance Periods ending December 31, 1994 and December 31,
1995 and for the Performance Period ending December 31, 1996
shall be paid 50% in cash and 50% in Common Stock unless the
Participant consents to have the Performance Share Units earned
for the Transition Performance Period ending December 31, 1995
and the Performance Share Units earned for the Performance Period
ending December 31, 1996 paid in accordance with the provisions
of Sections 8.1 through 8.4. The payment in cash and Common
Stock shall be as provided in the second paragraph of Section
8.3.
8.6 Limitations on Sales of Common Stock.
A Participant shall not be permitted to sell the shares of Common
Stock distributed to such Participant pursuant to Section 8.5
which are required to meet the Equivalent Stock Ownership Target
until the Participant terminates employment with the
Subsidiaries.
In order to enforce the limitations imposed upon the shares of
Common Stock distributed pursuant to Section 8.5, the Committee
may (i) direct the delivery of stock certificates to Participants
to be withheld until the shares of Common Stock covered by such
certificates may be sold by the Participant, (ii) cause a legend
or legends to be placed on any such certificates, and/or (iii)
issue "stop transfer" instructions as it deems necessary or
appropriate.
Holders of shares of Common Stock limited as to sale under this
Section 8.6 shall have rights as a shareholder with respect to
such shares to receive dividends in cash or other property or
other distribution or rights in respect of such shares and to
vote such shares as the record owner thereof.
Article 9. Termination of Employment
9.1 Termination of Employment Due to Death, Disability,
Retirement or Involuntary Termination Other Than for Cause.
In the event of a Participant's termination of employment with
the Subsidiaries, prior to the end of a Performance Period but
after the first six months of such Performance Period, by reason
of the Participant's death, Disability, Retirement or involuntary
termination other than for cause, the Participant will be
eligible to earn prorated Performance Share Units for each such
Performance Period which has not yet ended, determined pursuant
to Section 8.1 for such period and the number of days of
participation during such Performance Period. In the case of the
Transition Performance Periods, the Performance Share Units
earned would not be subject to proration if the employment period
and termination conditions specified in this Section 9.1 were
met.
9.2 Termination for Reasons Other Than Death, Disability,
Retirement or Involuntary Termination Other Than for Cause.
In the event a Participant's employment is terminated for reasons
other than death, Disability, Retirement or involuntary
termination other than for cause, all rights to any unearned
Performance Share Units under the Plan shall be forfeited.
Article 10. Beneficiary Designation
10.1 Designation of Beneficiary.
Each Participant shall be entitled to designate a beneficiary or
beneficiaries who, following the Participant's death, will be
entitled to receive any amounts that otherwise would have been
paid to the Participant under the Plan. All designations shall
be signed by the Participant, and shall be in such form as
prescribed by the Committee. Each designation shall be effective
as of the date delivered to the Company by the Participant. The
Participant may change his or her designation of beneficiary on
such form as prescribed by the Committee. The payment of any
amounts owing to a Participant pursuant to such Participant's
outstanding Performance Share Units or Restricted Stock Units
held under the Plan shall be in accordance with the last
unrevoked written designation of beneficiary that has been signed
by the Participant and delivered by the Participant to the
Company prior to the Participant's death.
10.2 Death of Beneficiary.
In the event that all of the beneficiaries named by a Participant
pursuant to Section 10.1 herein predecease the Participant, any
amounts that would have been paid to the Participant or the
Participant's beneficiaries under the Plan shall be paid to the
Participant's estate.
Article 11. Rights of Participants
11.1 Employment.
Nothing in the Plan shall interfere with or limit in any way the
right of the Company or any Subsidiary to terminate any
Participant's employment at any time, nor confer upon any
Participant any right to continue in the employ of the Company or
Subsidiary.
11.2 Participation.
No Participant shall at any time have a right to be selected for
participation in the Plan for any Performance Period, despite
having been selected for participation in a previous Performance
Period.
11.3 Nontransferability.
No Performance Share Units held by a Participant or Restricted
Stock Units held pursuant to Sections 8.2 or 8.4 may be sold,
transferred, pledged, assigned, or otherwise alienated or
hypothecated, other than by will or by the laws of descent and
distribution.
11.4 Rights to Common Stock.
Performance Share Units or Restricted Stock Units do not give a
Participant any rights whatsoever with respect to shares of
Common Stock until such time and to such extent that payment of
earned Performance Share Units or Restricted Stock Units is made
in shares of Common Stock as requested by the Participant.
Article 12. Amendment, Modification and Termination
12.1 Amendment, Modification and Termination.
The Committee may amend or modify the Plan at any time, with the
approval of the Board. However, without the approval of the
shareholders of the Company, no such amendment or modification
may:
(a) Materially modify the eligibility requirements of the
Plan.
(b) Materially increase the benefits accruing to
Participants under the Plan.
(c) Materially increase the number of Performance Share
Units which may be earned on an aggregate basis or by
a Participant (except as provided in Section 5.2).
(d) Materially increase the maximum number of shares of
Common Stock available for payment under the Plan
(except as provided in Section 5.2).
(e) Modify the Performance Measure and the method of
determining Performance Share Units earned pursuant
to Section 8.1, except as may be permitted by Section
162(m).
12.2 Performance Share Units Previously Granted.
No termination, amendment or modification of the Plan shall in
any manner adversely affect any outstanding Performance Share
Units or Restricted Stock Units under the Plan, without the
written consent of the Participant holding such Performance Share
Units or Restricted Stock Units.
Article 13. Miscellaneous Provisions
13.1 Costs of the Plan.
The costs of the Plan awards shall be paid directly by the
Subsidiary that pays each Participant's base salary during the
Performance Period. Although not prohibited from doing so, the
Subsidiary is not required in any way to segregate assets in any
manner or to specifically fund the benefits provided under the
Plan.
13.2 Relationship to Other Benefits.
No payment under the Plan shall be taken into account in
determining any benefits under any pension, retirement, group
insurance, or other benefit plan of the Company and/or its
Subsidiaries.
13.3 Governing Law.
To the extent not preempted by Federal law, the Plan, and all
agreements hereunder, shall be construed in accordance with and
governed by the laws of the State of New York.
Article 14. Rule 16b-3 Compliance
The Company intends that the Plan meet the requirements of Rule
16b-3. In all cases, the terms, provisions, conditions and
limitations of the Plan shall be construed and interpreted
consistent with the Company's intent as stated in this Article
14.
In the event the Plan does not include a provision required by
Rule 16b-3 to be stated therein, such provision shall be deemed
to be incorporated by reference into the Plan as it relates to
eligible Participants subject to Section 16 of the Securities
Exchange Act of 1934, with such incorporation to be deemed
effective as of the effective date of such Rule 16b-3 provision.
</PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
<CAPTION>
Year Ended December 31, 1994 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C>
INCOME STATEMENTS DATA
(in millions):
Operating Revenues $5,505 $5,269 $5,045 $5,047 $5,178
Operating Income 932 928 883 918 861
Net Income 500 354 468 498 496
<CAPTION>
December 31, 1994 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C>
BALANCE SHEETS DATA (in millions):
Electric Utility Plant $18,175 $17,712 $17,509 $17,148 $16,652
Accumulated Depreciation
and Amortization 6,827 6,612 6,281 5,952 5,588
Net Electric Utility Plant $11,348 $11,100 $11,228 $11,196 $11,064
Total Assets $15,713 $15,341 $14,277 $13,886 $13,596
Common Shareholders' Equity 4,230 4,152 4,246 4,222 4,167
Cumulative Preferred Stocks
of Subsidiaries:
Not Subject to Mandatory
Redemption 233 268 535 535 535
Subject to Mandatory Redemption* 590 501 234 141 145
Long-term Debt* 4,980 4,995 5,311 5,029 4,927
Obligations Under Capital Leases* 400 284 300 273 290
*Including portion due within one year
<CAPTION>
Year Ended December 31, 1994 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C>
COMMON STOCK DATA:
Earnings per Share $2.71 $1.92 $2.54 $2.70 $2.65
Average Number of Shares
Outstanding (in thousands) 184,666 184,535 184,535 184,535 187,064
Market Price Range: High $37-3/8 $40-3/8 $35-1/4 $34-1/4 $33-1/8
Low 27-1/4 32 30-3/8 26-5/8 26
Year-end Market Price 32-7/8 37-1/8 33-1/8 34-1/4 28
Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio 88.6% 125.2% 94.6% 88.9% 90.3%
Book Value per Share $22.83 $22.50 $23.01 $22.88 $22.58
</TABLE>
<PAGE>
Management's Discussion and Analysis
of Results of Operations and Financial Condition
Earnings Increase
Earnings for 1994 were $500 million or $2.71 per share, up 41.3% 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 resulting from a disallowance by
the Public Utilities Commission of Ohio (PUCO) of a portion of the Company's
Zimmer Plant investment. Exclusive of the disallowance, 1993 earnings and
earnings per share would have been $498 million and $2.70, respectively, and
1994 earnings would have increased slightly as the effect of rate increases
in several jurisdictions was offset by the related amortization of Zimmer
Plant deferrals and increased operating expenses due mainly to significant
storm damage and increased fuel expenses.
In 1993 earnings declined 24.4% from $468 million or $2.54 per share in
1992 reflecting the adverse impact in 1993 of the Zimmer disallowance.
Without the Zimmer disallowance, earnings in 1993 would have increased 6.4%
due predominantly to improved sales reflecting a return to normal weather,
continued improvement in industrial sales, rate increases in several
jurisdictions and decreased interest expense and preferred stock dividends
due to refinancings.
_________________________________________________________________________
[The following data was presented in graphical form in the printed report.]
1990 1991 1992 1993 1994
Earnings per share $2.65 $2.70 $2.54 $1.92* $2.71
* Without the Zimmer disallowance 1993 would be $2.70
_________________________________________________________________________
<PAGE>
Revenues Increase
Operating revenues increased more than 4% in 1994 and 1993 reflecting the
effects of rate increases, growth in the number of customers and the weather.
The change in revenues can be analyzed as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1994 1993
Amount % Amount %
Retail:
Price Variance $ 90.7 $ 53.1
Volume Variance 53.8 173.4
Fuel Cost Recoveries 40.5 (49.7)
185.0 4.1 176.8 4.1
Wholesale:
Price Variance 68.6 (3.4)
Volume Variance (49.7) 59.1
Fuel Cost Recoveries 8.1 (15.9)
27.0 3.9 39.8 6.1
Other Operating Revenues 23.8 7.5
Total $235.8 4.5 $224.1 4.4
The increase in 1994 operating revenues was 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. The increase in retail energy sales of 2% 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 as mild weather during most
of the year offset the effect of the severe weather in January and the
unseasonably hot weather in June.
Although wholesale energy sales declined by 7% in 1994, wholesale
revenues increased 4% 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 an
increase in 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 due to mild weather
throughout most of 1994. While severe winter weather in January 1994 and
extremely hot June weather increased short-term wholesale sales, the mild
weather throughout the remainder of 1994, combined with increased competition
in the wholesale market, reduced short-term sales for the year.
Fuel cost recoveries increased in both the retail and wholesale
jurisdictions in 1994 with the retail jurisdiction increase reflecting the
effect of the operation of the fuel clause mechanism in Indiana and the
wholesale jurisdiction increase resulting from increased fuel costs.
<PAGE>
The increase in 1993 operating revenues was also primarily due to
increased revenues from retail customers reflecting a significant increase in
retail energy sales and retail rate increases offset in part by a reduction
in fuel cost recoveries. In 1993 energy sales rose 5% with retail energy
sales increasing 4% and wholesale sales rising 9%. The increase in retail
energy sales in 1993 was due to a return to normal weather, improved
industrial sales and growth in the number of retail customers. The 9% upturn
in wholesale sales in 1993 was mainly the result of an increase in short-term
sales due to decreased availability of unaffiliated generating units combined
with increased demand resulting from hot summer weather in 1993. The decline
in fuel cost recoveries in 1993 reflects the effects of decreases in fuel
costs.
Efforts to improve short-term wholesale sales are affected by the highly
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 the extent applicable.
Also, since the Company's residential and commercial sales are weather-
sensitive, future results of operations will depend on the weather.
_________________________________________________________________________
[The following data was presented in graphical form in the printed report.]
1990 1991 1992 1993 1994
(in billions of kilowatthours)
Sales of Energy:
Residential 25 27 27 29 29
Commercial 19 20 20 21 21
Industrial 39 40 41 42 44
Wholesale & All Other 37 26 23 25 23
Total Energy Use 120 113 111 117 117
_________________________________________________________________________
Operating Expenses Increase
Operating expenses increased 5% in 1994 and 4% in 1993. Changes in the
components of operating expenses are shown in the table.
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1994 1993
Amount % Amount %
Fuel and Purchased Power $ 97.7 5.9 $ 0.4 0.0
Other Operation 31.9 3.3 57.2 6.3
Maintenance 21.2 4.1 32.6 6.7
Depreciation and Amortization 41.5 7.8 24.4 4.8
Taxes Other Than Federal
Income Taxes 25.9 5.5 26.4 5.9
Federal Income Taxes 13.8 6.8 37.2 22.4
Total $232.0 5.3 $178.2 4.3
The increased fuel and purchased power expense in 1994 was mainly the
result of increased utilization of coal-fired generation as low-cost nuclear
generation was reduced due to scheduled refueling and maintenance outages at
both of the Company's nuclear generating units. Also contributing to the
increase was increased purchases of energy from unaffiliated utilities for
pass-through sales to other unaffiliated utilities.
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. The increase in other operation
expense in 1993 was due to severance costs in connection with a
reorganization of the Company's Ohio operations and a change in accounting
method for postretirement benefits other than pensions due to the adoption of
a new accounting standard.
Significant storm damage caused by snow and ice storms during the first
three months of 1994 increased maintenance expense. Storm damage
expenditures totaled $46 million of which $23.9 million was deferred as a
regulatory asset. The increase in maintenance expense in 1993 was due to an
increase in scheduled power plant maintenance, unusual storm damage and the
amortization of previously deferred incremental cost of nuclear maintenance
expenditures incurred during refueling outages in 1992. With regulator
approval the incremental cost of certain nuclear maintenance procedures,
which are performed only when the nuclear unit is out of service for
refueling, are levelized (deferred and amortized) over the period starting
with the beginning of the outage and ending with the beginning of the next
outage so that the cost of an average number of refuelings are reflected in
each year's expenses. This procedure is necessary to levelize rates because
the refueling outages occur approximately every 18 months.
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 amortization
of such costs as they were recovered in rates. Depreciation and amortization
expense increased in 1993 predominantly as a result of property additions
including the Zimmer Plant. Although Zimmer went into service in 1991,
regulator-approved deferrals of depreciation expense were recorded through
May of 1992, when rate recovery commenced.
Taxes other than federal income tax expense rose in 1994 mainly due to
an increase in the generation-based West Virginia business and occupation tax
reflecting an increase in generation at West Virginia power plants and an
increase in the revenue-based gross receipts tax of several states reflecting
the increase in revenues in 1994. In 1993 taxes other than federal income
taxes rose reflecting increased taxable income and property tax assessments
and the effect of regulator-approved deferral of Zimmer Plant property taxes
in 1992.
The increase in federal income tax expense attributable to operations in
1994 and 1993 was primarily due to an increase in pre-tax operating income.
Deferred Carrying Charges and Nonoperating Income
The decrease in deferred Zimmer Plant carrying charges in 1994 resulted from
the cessation of deferrals commensurate with inclusion of the full plant
investment in rate base effective February 1, 1994. The amortization of the
deferrals is included in depreciation and amortization expense.
Zimmer Plant carrying charges decreased in 1993 as the plant investment
was phased into rate base commensurate with recovery from ratepayers under a
PUCO-ordered rate phase-in plan. From the in-service date of March 1991
until phase-in rate relief was granted in May 1992, deferred carrying charges
of $56 million were recorded on the full Zimmer Plant investment. Under the
phase-in plan and subsequent to May 1992, a deferred return was recorded only
on the portion of the allowed plant investment not yet reflected in rates.
Recovery of the pre-rate relief deferral will be sought in the next PUCO base
rate proceeding.
The decrease in other nonoperating income in 1994 was mainly due to
recording 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 received from the Internal Revenue
Service (IRS) in connection with the settlement of audits of prior years' tax
returns. From 1992 to 1993 other nonoperating income declined significantly
mainly because of the effect of interest income recorded in 1992 on tax
refunds received from the IRS in connection with the settlement of audits of
prior years' tax returns and on receivables from customers for the collection
of prior years' fuel costs resulting from the favorable resolution of
litigation.
_________________________________________________________________________
[The following data was presented in graphical form in the printed report.]
1990 1991 1992 1993 1994
(In Millions)
Net Interest Charges $401 $431 $448 $418 $389
Preferred Dividend Requirements $53 $54 $59 $59 $55
_________________________________________________________________________
_________________________________________________________________________
[The following data was presented in graphical form in the printed report.]
1990 1991 1992 1993 1994
(In Percent)
Dividend Payout Ratio 90.3% 88.9% 94.6% 125.2%* 88.6%
Common Equity Ratio 42.6% 42.5% 41.1% 41.9% 42.2%
* Without Zimmer disallowance 1993 would be 88.9%
_________________________________________________________________________
Interest and Preferred Stock Dividends Decrease
Refinancing programs of several subsidiaries during 1993 and the early part
of 1994 reduced the average interest rate on outstanding long-term debt as
well as the levels of long-term debt causing the decline in interest expense
in 1994 and 1993. Over the past two years management refinanced and retired
$2 billion of relatively high interest rate long-term debt to take advantage
of low interest rates. Also management took advantage of the low market
rates to refinance preferred stock at reduced dividend rates.
Common Dividend and Payout Ratio Remain Constant
The Company paid a quarterly dividend in 1994 of 60 cents a share maintaining
the annual dividend rate at $2.40 per share. The payout ratio was 89% in
both 1994 and 1993 before the Zimmer disallowance, down from 95% in 1992.
The payout ratio is considered an indicator of a company's ability to
increase or maintain its dividend in the future. It has become an important
consideration for the electric utility industry as it faces the possibility
of competition. Some electric utility companies have reduced the payout
ratio by cutting their dividend in order to retain more earnings and be
better equipped to meet competitive challenges. Management's objective is to
reduce the payout ratio to a level between 75% and 80% by improving earnings.
Construction Spending
Construction expenditures have been declining in recent years. Management
estimates cumulative construction expenditures for the next three years to be
$2 billion including expenditures necessary to meet the requirements of the
Clean Air Act Amendments of 1990. Approximately 86% of the construction
expenditures for the next three years will be financed internally. These
estimated construction expenditures do not include any major new plant
construction.
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 1994 short-term borrowings increased
by $38 million. At December 31, 1994, American Electric Power and its
subsidiaries had outstanding unused short-term lines of credit of $558
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 700,000 shares of common stock in 1994 through a Dividend
Reinvestment Program raising $22 million. As a result of the common stock
issuance in 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, 1994 the ratio increased to 42.2% from 41.9% at year end 1993
and has improved from 41.1% in 1992. Management expects that small amounts
of common stock will similarly be issued to meet a portion of the
construction budget and to maintain or enhance common equity ratios over the
next three years.
At December 31, 1994 the subsidiaries have outstanding $4.98 billion of
long-term debt and $823 million of preferred stock. The subsidiaries have
regulatory approval to issue up to $714 million of long-term debt and $85
million of preferred stock. Management expects to use the proceeds of future
long-term financings to retire short-term debt, refinance higher cost and
maturing long-term debt, refund cumulative preferred stock and fund
construction expenditures.
Unless the subsidiaries meet certain earnings or coverage tests, they
cannot issue additional long-term debt or preferred stock. In order to issue
certain long-term debt (without refunding existing debt), each subsidiary
must have pre-tax earnings equal to at least two times the annual interest
charges on long-term debt 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.
_________________________________________________________________
PRINCIPAL OPERATING SUBSIDIARIES
DEBT & PREFERRED STOCK COVERAGE Long-term Preferred
December 31, 1994 Debt Stock
Appalachian Power Co. 3.10 1.65
Columbus Southern Power Co. 3.64 N/A
Indiana Michigan Power Co. 5.08 2.74
Kentucky Power Co. 2.60 N/A
Ohio Power Co. 4.55 2.58
N/A = Not applicable; no preferred stock restrictions
_________________________________________________________________
Business Conditions
Competition in Our Core Business
All public electric utilities are confined with regard to retail service to
providing electric generation, transmission and distribution services in a
designated service territory. In exchange for this exclusive right to
provide such services at a cost-based regulated price which provides the
opportunity to earn a regulator-determined reasonable rate of return on
shareholders' equity, electric utilities are obligated to serve all customers
in their service territories. Although public electric utilities including
AEP are regulated monopolies, we have historically competed with self-
generation and with distributors of alternative sources of energy, such as
natural gas, fuel oil and coal, within our service areas. In recent years
regulated electric utilities have also competed with independent power
producers for the right to build and operate new generating plant. The
primary competitive factors have been price, reliability of service and the
ability of customers to utilize sources of energy other than electric power.
AEP has maintained a favorable competitive position on the basis of all of
these factors. This is evidenced by the lack of independent power producers
and significant self generation in our service territories. With respect to
alternative energy sources, AEP believes that the convenience and versatility
of electricity and reliability of our service coupled with the limited
ability of customers to substitute other energy sources for electric power
have placed us in a favorable competitive position. However, we continue to
work to improve the competitiveness, effectiveness and reliability of our
core product, electricity. AEP, for example, markets high-efficiency heat
pumps and off-peak storage water heaters which make electricity competitive
with natural gas for space and water heating.
Competition in the wholesale market, that is, the sale of bulk power to
other public and municipal utilities, is not new and has been increasing for
a number of years. This is particularly true in the short-term wholesale
market. The National Energy Policy Act of 1992 (the Energy Act) facilitated
competition in the short and long-term wholesale market since, among other
things, it authorized the Federal Energy Regulatory Commission (FERC) to
order transmission access for wholesale transactions. The principal factors
in competing for wholesale sales are price, including fuel costs,
availability of capacity, transmission capability and cost, and reliability
of service. Management believes that over the years AEP has generally
maintained a favorable competitive position in these factors. However, due
to the recent availability of additional capacity of other utilities and
reduced fuel prices, price competition, especially in the short-term
wholesale market, has been, and is expected to be, important in the future.
AEP intends to continue competing for wholesale sales when it will enhance
shareholder value.
With the passage of the Energy Act, the potential for retail wheeling,
i.e., competition for retail sales, is getting considerable attention. While
the Energy Act gave the FERC broad authority to mandate transmission access
in the wholesale market, it prohibits the FERC from ordering retail wheeling.
A number of state legislatures and state regulatory agencies have begun to
study retail wheeling with encouragement from major industrial customers.
If it occurs, increased competition may require the resolution of some
complex issues, such as stranded investment and the obligation to serve.
When a customer leaves a utility system, there is an issue of who pays for
plant investment, regulatory assets and commitments that are no longer
needed. If a customer leaves its native electric supplier and later decides
to return, the issue of whether the original local utility has an obligation
to serve the returning customer must also be addressed. If not recovered
directly from customers that choose another supplier and/or from the
remaining regulated customers, the AEP System, like all electric utilities,
will be required to address stranded investment losses that could result from
any future loss of customers or reduced pricing from head-to-head
competition. Management intends to seek recovery of any stranded investment,
including regulatory assets, as an appropriate recovery of previously
approved cost of service.
Although management believes that it has a favorable competitive
position due to AEP's relatively low cost of generation, it will be essential
for management to better understand the nature of AEP's costs in order to
develop new, innovative and competitive pricing structures and to manage
profit margins especially if competition were to expand. It will be
important to develop improved costing tools in order to maintain our position
as a low-cost supplier. AEP is turning to activity-based budgeting and cost
management techniques to enable management to cost logical work activities
and services. By examining our operations by logical work units, the cost of
all major activities can be better controlled, identified and evaluated to
properly price our products and to eliminate unnecessary activities and their
cost.
The development of tools and training to enable management to better
manage the costs of operations is only one of the options AEP is currently
pursuing. In 1994 AEP's management team has been:
- Reviewing and streamlining operations and staffing,
- Reducing layers of supervision,
- Expanding customer relations and service activities,
- Expanding its ability to help customers adopt new
electro-technologies to reduce their usage of electricity,
- Expanding strategic planning and management training activities,
and
- Exploring participation in new and existing international power
projects and other non-core but related business opportunities.
Management is committed to maintaining and enhancing our core business.
Although the AEP System with our relatively low cost of generation is
competitive, management is moving in "new directions" to maintain and improve
our competitive position. Whether competition expands or not, these efforts
will serve to maintain our relatively low rates and improve sales through
economic development in our service territory.
Non-Core Business Prospects
Although AEP has not yet developed any major non-core business, we continue
to consider new business opportunities, particularly those which permit the
use of our expertise and core competencies. These endeavors are conducted
through AEP Energy Services, Inc. (AEPES) and AEP Resources, Inc. which are
non-rate-regulated subsidiaries.
AEPES offers consulting services both domestically and internationally
and contracts with other public utilities, commercial entities and government
agencies for the licensing of intellectual property and the delivery of
services. Recently AEPES entered into agreements with several major
engineering consulting firms to jointly market certain consulting services.
AEPES is also engaged in efforts to research, develop and commercialize
products that can be made out of the ash by-products of electricity
generation from coal in an attempt to reduce disposal costs and improve
shareholder value.
AEP Resources is pursuing several possible investment projects. Its
primary business focus will be international and domestic cogeneration, the
independent power market and the privatization of generation and transmission
facilities in the international market. Recently an agreement of intent was
signed that may result in a joint venture to construct two 1,300 mw coal-
fired generating units in China at an estimated cost of $2 billion. These
two units, if constructed, would be the largest coal-fired generating units
in Asia and would burn low-sulfur coal. It is currently proposed that AEPES
will provide the engineering, design, construction management and training
for operation of the two 1,300 mw units. It is anticipated that AEP may
acquire an interest in the 49% share of equity expected to be available to
foreign investors.
Non-core investments offer the potential for earning returns which
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 investments in these and other new non-core businesses after
management carefully assesses the risks involved vs. potential for enhanced
shareholder value. Appropriate non-core business investments are part of
AEP's strategic plan for enhancing shareholder value.
Affiliated Coal
For a number of years Ohio Power Company (OPCo) has been limited in its
recovery of the cost of coal produced by its affiliated mines. Under a 1992
stipulation agreement a predetermined price of $1.64 per million Btu's was
established for the cost of coal burned at four of OPCo's generating plants
(the Gavin, Mitchell, Muskingum River and Cardinal plants), three of which
burn affiliated coal from the Meigs, Muskingum and Windsor mines. The
stipulation covered the three-year period ending November 30, 1994.
Beginning December 1, 1994 an inflation adjusted 15-year predetermined price
of $1.575 per million Btu's for coal burned at the Gavin Plant was
established by the 1992 stipulation agreement. As discussed below under
"Clean Air Act" a Settlement Agreement sets an overall predetermined electric
fuel component rate 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 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, management believes that OPCo should be
able to recover, under the terms of the 1992 stipulation agreement in
conjunction with the Settlement Agreement, the Ohio jurisdictional portion of
the cost of the affiliated mining operations including mine closure costs.
As discussed below, compliance with the January 1, 2000 Phase II
deadline of the Clean Air Act Amendments of 1990 may cause the affiliated
Muskingum and Windsor mines to close. Shutdown costs for the Muskingum and
Windsor mines include investments in the mines, leased asset buy-outs,
reclamation costs and employee benefits and are estimated to be $150 million
after tax (the non-Ohio jurisdiction portion is estimated to be $85 million
after tax) at December 31, 1994. Management intends to seek from ratepayers
adequate and timely recovery of the non-Ohio jurisdictional portion of the
investment in and the liabilities and closing costs of the Muskingum and
Windsor mining operations as well as for the Meigs mining operations. In the
event those costs and/or the cost of such affiliated coal production in the
interim cannot be recovered, results of operations would be adversely
affected.
Nuclear Cost
The cost to operate and maintain the two-unit Cook Nuclear Plant is impacted
by Nuclear Regulatory Commission (NRC) requirements and the normal aging of
the plant (Unit 1 began commercial operation in 1975 and Unit 2 in 1978). In
addition, the cost to decommission the plant is affected by NRC regulations
and the Department of Energy's Spent Nuclear Fuel (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. By law I&M participates in the Department of
Energy's SNF disposal program which is described in Note 4 of the Notes to
Consolidated Financial Statements. Decommissioning costs and spent nuclear
fuel disposal costs are being recovered from ratepayers. In 1993 the Indiana
and the Michigan commissions approved higher levels of recovery so that the
amount currently being recovered is at least at the lower end of the range in
the prior decommissioning study. To date AEP has recovered and accrued $212
million in decommissioning cost. Management intends to seek recovery through
the rate-making process of the last increase and any future increases in
decommissioning costs over the remaining plant life.
Nuclear operations are continually reviewed for ways to lessen the
growth in operation, maintenance and decommissioning costs. In 1994 Cook
Nuclear Plant achieved a superior rating from the Institute of Nuclear Power
Operations, a nuclear industry oversight group, and received improved NRC
performance ratings. Additionally, costs related to nuclear refueling
outages at the Cook Nuclear Plant have been reduced by approximately $20
million in the last two years.
In 1994 the Financial Accounting Standards Board (FASB) added Accounting
for Nuclear Decommissioning Liabilities to its agenda. Among the topics to
be studied by the FASB is the question of when future decommissioning
liabilities should be recognized. The Company and the electric utility
industry accrue such costs over the service life of their nuclear facilities
as recovered in rates. A new requirement from the FASB could cause the
annual provisions for decommissioning to increase should the estimate of the
remaining unaccrued decommissioning costs be greater than the regulators'
allowed recovery level. Management believes that the industry's life of the
plant accrual accounting method is appropriate and should be accepted by the
FASB. Until the FASB completes its study and reaches a conclusion, the
impact, if any, on results of operations and financial condition cannot be
determined.
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 Systemwide least-cost
compliance plan was developed reflecting various methods of compliance. The
cornerstone of the compliance strategy is the installation of flue gas
desulfurization systems (scrubbers) on OPCo's 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 continued
use of Ohio high-sulfur coal at the Gavin Plant. The scrubbers for Gavin
Unit 1 were completed in December 1994 and the Unit 2 scrubbers are expected
to be completed in March 1995. The cost of the leased scrubbers is estimated
to be $675 million. Capital expenditures for all other AEP System CAAA-
related environmental based protection facilities for the next three years
are estimated to be $45 million.
The PUCO approved the compliance plan for OPCo as a least-cost
compliance strategy in November 1992, and under Ohio law the plan is deemed
prudent for subsequent PUCO rate proceedings.
Under the approved plan, fuel switching would be the compliance method
at OPCo's Muskingum River Plant in 1995 and 2000 and at OPCo's Cardinal Plant
Unit 1 in 2001 although the PUCO in a subsequent fuel cost recovery
proceeding recommended that OPCo consider employing fuel switching as early
as 1995 at the Cardinal Plant. The plants are currently supplied by OPCo's
wholly-owned, high-sulfur coal-mining subsidiaries which operate the
Muskingum and Windsor mines. Consequently, these affiliated mining
operations could shut down resulting in substantial costs.
Recovery of CAAA capital and operating compliance costs is being sought
through the rate-making process. In 1994 OPCo filed with the PUCO for an
annual revenue increase of $152.5 million with half of the requested rate
increase to recover costs associated with the Gavin Plant's 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. Under the
terms of the Settlement Agreement base rates would increase by $66 million
annually in March 1995 which includes recovery of the annual cost of the
scrubbers; the EFC rate would be fixed at 1.465 cents per kwh from June 1995
through November 1998; OPCo would be provided an opportunity under a 1992
predetermined price agreement for coal burned at the Gavin Plant (which is
described above) to recover its Ohio jurisdictional portion of the investment
in and the future shutdown costs of all affiliated mines; and OPCo may
proceed with its CAAA compliance plan as filed with the PUCO. The Settlement
Agreement allows the Company to continue to operate the Muskingum and Windsor
mines through the end of Phase I, January 1, 2000. The Settlement Agreement
is subject to PUCO approval.
Efforts are continuing to obtain timely recovery of the compliance costs
in jurisdictions other than OPCo's Ohio jurisdiction, although there can be
no assurance that regulators will provide for recovery of all CAAA compliance
costs on a timely basis. Compliance with the CAAA, including potential mine
closure costs, will have an adverse effect on results of operations and
possibly financial condition if not recovered from ratepayers or through
asset dispositions.
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 substance
disposal sites and authorizes the United States Environmental Protection
Agency (Federal EPA) to administer the clean-up programs. AEP companies have
been named by the Federal EPA as a "potentially responsible party" (PRP) for
12 sites as of December 31, 1994. Liability has been settled for five of
these sites with no significant effect on results of operations. In
addition, there are 11 sites for which AEP companies have received
information requests or demand letters which could lead to PRP designation.
In all 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. As a result, AEP has instituted a number of Systemwide
policies that have raised the standard of care by going beyond regulatory
requirements where appropriate.
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 unknown reasons significant costs are
incurred for cleanup, results of operations and possibly financial condition
would be adversely affected unless the costs can be recovered from insurance
proceeds and/or, with regulatory approval, from ratepayers.
Notice of Violation - Kammer Plant - In August 1994 the Federal EPA issued a
Notice of Violation (NOV) to OPCo alleging that the Kammer Plant has been
operating in violation of applicable federally enforceable air pollution
control requirements since January 1, 1989. By law the Federal EPA may seek
penalties of up to $25,000 per day for each day of violation. A Consent
Decree was negotiated and filed on November 15, 1994, which resolves that
portion of the NOV relating to compliance. The portion of the NOV relating
to penalties will be addressed independently. At this time management is
unable to estimate the amount of any civil penalties that the Federal EPA may
impose. It is not anticipated that the ultimate resolution of this matter
will have a material adverse impact on results of operations.
Global Climate Change - Concern about global climate change, or "the
greenhouse effect," has been the focus of intensive debate within the United
States and around the world. Much of the uncertainty about what effects
greenhouse gas concentrations will have on the global climate results from a
myriad of factors that affect climate. Based on the terms of a 1992 United
Nations treaty that pledged the United States to reduce greenhouse gas
emissions, the Clinton Administration developed a voluntary plan to reduce
greenhouse gas emissions to 1990 levels by the year 2000. As part of this
plan, AEP is participating with the U.S. Department of Energy and other
electric utility companies in the climate change program to limit future
greenhouse gas emissions.
AEP's climate challenge program applies a policy of proactive
environmental stewardship, whereby actions are taken that make economic and
environmental sense on their own merits, irrespective of the uncertain threat
of global climate change. The plan includes energy conservation programs,
improvements in fossil generation efficiency, increased use of nuclear
capacity and forest management activities. However, should it be determined
necessary to enact significant new measures to control the burning of coal,
their cost, if not recovered from ratepayers could adversely impact results
of operations and financial condition.
EMF - The potential for electric and magnetic fields (EMF) from transmission
and distribution facilities to adversely affect the public health is being
extensively researched. AEP continues to support EMF research to help
determine the extent, if any, to which EMF may adversely impact public
health. Our concern is that new laws imposing EMF limits may be passed or new
regulations promulgated without sufficient scientific study and evidence to
support them. As long as there is uncertainty about EMF, AEP and other
electric utilities will have difficulty finding acceptable sites for their
facilities, which could hamper economic growth within AEP's seven-state
operating territory. If the present energy delivery system must be changed
because of EMF concerns, or if the courts conclude that EMF exposure harms
individuals and that utilities are liable for damages, then AEP's results of
operations and financial condition could be adversely affected, unless the
costs can be recovered from ratepayers.
Litigation
The Company is involved in a number of legal proceedings and claims. While
we are unable to predict the outcome of such litigation, it is not expected
that the resolution of these matters will have a material adverse effect on
financial condition. Information about these matters can be found in the
footnotes to the financial statements.
Proposed Revision of the Public Utility Holding Company Act
The Public Utility Holding Company Act of 1935 (1935 Act) currently requires
that service, sales and construction contracts (other than power sales)
between companies in a registered holding company system, such as the AEP
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 their full
costs under these provisions.
The Securities and Exchange Commission is studying the 1935 Act to
determine whether the rules to administer it should be updated or the 1935
Act should be amended or repealed. Proposals being considered to modernize
the 1935 Act could eliminate the assurance that affiliated companies will
recover their full cost of providing intra-system services. These proposals
may price such transactions at a market-based price if it is lower than cost
or generally eliminate the application of the 1935 Act to such transactions.
The effect of the adoption of these proposals on AEP 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.
The 1935 Act was premised upon the fact that utilities were vertically
integrated and operated as monopolies in an assigned territory. With passage
of the Energy Act and the possibility of increased competition in the
electric utility industry, it is essential that the Company's ability to
compete not be restricted by its status as a registered holding company under
the 1935 Act. To be prepared for these possible changes in the nature of the
industry, management has concluded that it supports the repeal of the 1935
Act.
Effects of Inflation
Inflation affects the AEP System's cost of replacing utility plant and the
cost of operating and maintaining its plant. The rate-making process limits
the Company to recovery of the historical cost of assets resulting in
economic losses when the effects of inflation are not recovered from
customers on a timely basis. However, economic gains that result from the
repayment of long-term debt with inflated dollars partly offset such losses.
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands - except per share amounts)
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
OPERATING REVENUES $5,504,670 $5,268,842 $5,044,792
OPERATING EXPENSES:
Fuel and Purchased Power 1,745,245 1,647,573 1,647,167
Other Operation 997,235 965,329 908,172
Maintenance 544,312 523,062 490,425
Depreciation and Amortization 572,189 530,731 506,304
Taxes Other Than Federal Income Taxes 496,260 470,346 443,963
Federal Income Taxes 217,209 203,431 166,219
TOTAL OPERATING EXPENSES 4,572,450 4,340,472 4,162,250
OPERATING INCOME 932,220 928,370 882,542
NONOPERATING INCOME:
Deferred Zimmer Plant Carrying Charges
(net of tax) 5,604 25,343 41,901
Other Nonoperating Income 5,881 21,229 51,163
TOTAL NONOPERATING INCOME 11,485 46,572 93,064
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 943,705 830,409 975,606
INTEREST CHARGES (net) 388,998 417,822 447,955
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES 54,695 58,818 59,348
NET INCOME $ 500,012 $ 353,769 $ 468,303
AVERAGE NUMBER OF SHARES OUTSTANDING 184,666 184,535 184,535
EARNINGS PER SHARE $2.71 $1.92 $2.54
CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
</TABLE>
____________________________________________
<TABLE>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<CAPTION>
Year Ended December 31,
(in thousands) 1994 1993 1992
<S> <C> <C> <C>
RETAINED EARNINGS JANUARY 1 $1,269,283 $1,358,800 $1,333,855
NET INCOME 500,012 353,769 468,303
DEDUCTIONS:
Cash Dividends Declared 443,101 442,891 442,891
Other 613 395 467
RETAINED EARNINGS DECEMBER 31 $1,325,581 $1,269,283 $1,358,800
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
<CAPTION>
December 31,
(in thousands) 1994 1993
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production $ 9,172,766 $ 9,079,130
Transmission 3,247,280 3,169,347
Distribution 3,966,442 3,743,047
General (including mining assets and nuclear fuel) 1,529,436 1,406,159
Construction Work in Progress 258,700 314,489
Total Electric Utility Plant 18,174,624 17,712,172
Accumulated Depreciation and Amortization 6,826,514 6,612,131
NET ELECTRIC UTILITY PLANT 11,348,110 11,100,041
OTHER PROPERTY AND INVESTMENTS 735,042 724,373
CURRENT ASSETS:
Cash and Cash Equivalents 62,866 42,561
Accounts Receivable:
Customers (Less Allowance for Uncollectible Accounts of
$4,056 in 1994 and $4,048 in 1993) 346,462 373,251
Miscellaneous 86,397 90,514
Fuel - at average cost 306,700 314,441
Materials and Supplies - at average cost 216,741 207,373
Accrued Utility Revenues 167,486 169,905
Prepayments and Other 94,786 98,958
TOTAL CURRENT ASSETS 1,281,438 1,297,003
REGULATORY ASSETS 1,949,852 1,849,055
DEFERRED CHARGES 398,257 370,929
TOTAL $15,712,699 $15,341,401
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
<CAPTION>
December 31,
(in thousands - except share data) 1994 1993
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock-Par Value $6.50:
1994 1993
Shares Authorized. .300,000,000 300,000,000
Shares Issued. . . .194,234,992 193,534,992
(8,999,992 shares were held in treasury) $ 1,262,527 $ 1,257,977
Paid-in Capital 1,641,522 1,625,068
Retained Earnings 1,325,581 1,269,283
Total Common Shareholders' Equity 4,229,630 4,152,328
Cumulative Preferred Stocks of Subsidiaries:*
Not Subject to Mandatory Redemption 233,240 268,240
Subject to Mandatory Redemption 590,300 500,450
Long-term Debt* 4,686,648 4,964,060
TOTAL CAPITALIZATION 9,739,818 9,885,078
OTHER NONCURRENT LIABILITIES 667,722 509,317
CURRENT LIABILITIES:
Long-term Debt Due Within One Year* 293,671 31,141
Short-term Debt 316,985 278,976
Accounts Payable 251,186 259,145
Taxes Accrued 382,677 409,198
Interest Accrued 88,916 91,161
Obligations Under Capital Leases 93,252 62,215
Other 407,965 338,988
TOTAL CURRENT LIABILITIES 1,834,652 1,470,824
DEFERRED FEDERAL INCOME TAXES 2,473,539 2,468,015
DEFERRED INVESTMENT TAX CREDITS 456,043 487,501
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 415,226 430,091
DEFERRED CREDITS 125,699 90,575
CONTINGENCIES (Note 4)
TOTAL $15,712,699 $15,341,401
See Notes to Consolidated Financial Statements.
*See accompanying schedules.
</TABLE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
Year Ended December 31,
(in thousands) 1994 1993 1992
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net Income $ 500,012 $ 353,769 $ 468,303
Adjustments for Noncash Items:
Depreciation and Amortization 561,188 555,436 541,726
Deferred Federal Income Taxes (12,223) (58,376) 103,180
Deferred Investment Tax Credits (31,275) (28,222) (27,796)
Deferred Operating Expenses and
Carrying Charges (net of amortization) 16,022 2,997 (108,429)
Loss from Zimmer Plant Disallowance - 159,067 -
Changes in Certain Current Assets and
Liabilities:
Accounts Receivable (net) 30,906 (16,980) (72,055)
Fuel, Materials and Supplies (1,627) 156,464 84,473
Accrued Utility Revenues 2,419 18,994 (48,935)
Accounts Payable (7,959) 47,018 (12,550)
Taxes Accrued (26,521) 56,502 26,304
Other (net) (53,217) 19,998 (119,234)
Net Cash Flows From Operating Activities 977,725 1,266,667 834,987
INVESTING ACTIVITIES:
Construction Expenditures (643,457) (592,199) (625,636)
Proceeds from Sale of Property and Other 49,802 26,669 97,977
Net Cash Flows Used For
Investing Activities (593,655) (565,530) (527,659)
FINANCING ACTIVITIES:
Issuance of Common Stock 22,256 - -
Issuance of Cumulative Preferred Stock 88,787 321,168 98,851
Issuance of Long-term Debt 411,869 1,339,227 1,329,973
Retirement of Cumulative Preferred Stock (35,949) (333,992) (7,153)
Retirement of Long-term Debt (445,636) (1,696,806) (1,086,875)
Change in Short-term Debt (net) 38,009 25,822 (159,229)
Dividends Paid on Common Stock (443,101) (442,891) (442,891)
Net Cash Flows Used For
Financing Activities (363,765) (787,472) (267,324)
Net Increase (Decrease) in Cash and
Cash Equivalents 20,305 (86,335) 40,004
Cash and Cash Equivalents January 1 42,561 128,896 88,892
Cash and Cash Equivalents December 31 $ 62,866 $ 42,561 $ 128,896
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
1. Significant Accounting Policies:
Organization - The American Electric Power System (AEP, AEP System or the
Company) is comprised 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; 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. American Electric Power Service Corporation
(AEPSC) provides management and professional services to the AEP System. The
active coal-mining companies are wholly-owned by OPCo and sell 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 1,300 megawatt (mw) generating units.
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 appropriate. 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 do 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 and represent regulator-
approved deferred expenses and revenues, respectively, resulting from the
rate-making process.
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 6.59%, 5.84% and 6.13% in 1994, 1993 and 1992,
respectively, and the amounts of AFUDC accrued were $11 million in 1994 and
$9 million in 1993 and 1992.
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 4.3%
Hydroelectric-Conventional
and Pumped Storage 1.7% to 3.0%
Transmission 1.7% to 2.7%
Distribution 3.4% to 4.2%
General 1.7% 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 57 cents 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 1995, 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, 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. 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 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. The amounts deferred were $49.6
million in 1994, $1.4 million in 1993 and $71.8 million in 1992.
Amortization of such deferrals was $30.8 million in 1994, $35.2 million in
1993 and $24.6 million in 1992.
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.
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 and
amortized 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 - Investments held in trust funds for
decommissioning nuclear facilities and for the disposal of spent nuclear fuel
are recorded at market value. Adjustments for unrealized gains and losses to
the carrying value of trust fund investments are not reflected in equity due
to the rate-making process.
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:
Rate Activity - On June 27, 1994 the Virginia State Corporation Commission
(VA SCC) issued a final order granting APCo an increase in annual revenues of
$17.9 million out of the requested amount of $31.4 million which required a
revenue refund to customers in August 1994 of $15.8 million. Effective
November 15, 1994 APCo implemented a net decrease in rates charged to its
Virginia retail customers of $13.2 million, subject to final approval by the
VA SCC. The net decrease reflects reduced fuel costs offset, in part, by
amortization over three years of $23.9 million of the deferred cost of
extensive repairs to facilities damaged by severe winter storms in 1994.
An application was filed by OPCo on July 6, 1994 with the Public
Utilities Commission of Ohio (PUCO) seeking a $152.5 million 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. Under the
terms of the Settlement Agreement, base rates would increase by $66 million
annually in March 1995 which includes recovery of the cost of the scrubbers;
the EFC rate would be 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 the investment in and the liabilities and the future
shut-down 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 (CAAA) compliance plan as filed with the PUCO. The Settlement
Agreement allows the Company to continue to operate the Muskingum and Windsor
mines. The Settlement Agreement is subject to PUCO approval.
Recovery of Fuel Costs - 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 Btu's with quarterly escalation adjustments. As discussed above the
Settlement Agreement fixes the EFC factor to 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 predetermined Gavin Plant 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.
As discussed in Note 4 under "Clean Air Act" 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. Management
believes that costs of compliance with the CAAA should be recovered from
ratepayers and intends to seek adequate and timely recovery of the non-Ohio
jurisdictional portion of the investment in and the liabilities and closing
costs of the Muskingum and Windsor mining operations as well as for the Meigs
mining operation. Unless those costs and/or the cost of affiliated coal
production can be recovered from customers through regulated rates, results
of operations would be adversely affected.
Unaffiliated Coal and Affiliated Transportation Cost - In October 1993, the
FERC denied a request by an I&M wholesale customer seeking rehearing of a
February 1993 order. The order concerned the reasonableness of coal costs
from an unaffiliated supplier who leases a Utah mining operation from I&M and
affiliated coal transportation charges. The February order reversed an
administrative law judge's decision and dismissed the complaint. The
wholesale customer appealed the October order to the U.S. Court of Appeals.
It is not anticipated that the ultimate resolution of this matter will have a
material adverse impact on results of operations.
<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. These regulatory assets and liabilities are
comprised of the following:
December 31,
(In Thousands) 1994 1993
Regulatory Assets:
Amounts Due From Customers For
Future Federal Income Taxes $1,381,549 $1,363,802
Rate Phase-in Plan Deferrals 118,553 152,711
Unamortized Loss on
Reacquired Debt 101,672 99,910
Other 348,078 232,632
Total Regulatory Assets $1,949,852 $1,849,055
Regulatory Liabilities:
Deferred Investment Tax Credits $456,043 $487,501
Other Regulatory Liabilities* 76,468 45,259
Total Regulatory Liabilities $532,511 $532,760
* Included in Deferred Credits on Consolidated Balance Sheets
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 1994 $18.5 million 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. 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.
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 $43.2 million and $58.8 million at December 31, 1994 and
1993, respectively. Amortization was $16 million in 1994, 1993 and 1992.
4. Commitments and Contingencies:
Construction and Other Commitments - The AEP System has made substantial
construction commitments. Such commitments do not presently include any
expenditures for new generating capacity. The aggregate construction program
expenditures for 1995-1997 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 1,275 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 1996 to 2010.
Clean Air Act - The Clean Air Act Amendments of 1990 (CAAA) requires
significant reductions in sulfur dioxide and nitrogen oxide emissions from
various AEP System generating plants. The first phase of reductions in
sulfur dioxide emissions (Phase I) began in 1995 and the second, more
restrictive phase (Phase II) begins in the year 2000. The law also
established a permanent nationwide cap on sulfur dioxide emissions after
1999.
In 1992 the PUCO approved a systemwide Phase I CAAA compliance plan.
The AEP System's compliance plan centers around the compliance method
selected for OPCo's two-unit 2,600 mw Gavin Plant which has emitted 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: installing leased flue
gas desulfurization equipment (scrubbers) to burn Ohio high-sulfur coal at
Gavin; 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;
and switching from high-sulfur coal to an alternate fuel at other System
units.
Fuel switching may result in the shutdown of OPCo's affiliated Muskingum
and Windsor coal-mining operations. To meet Phase I compliance, fuel
switching is necessary at one of the Muskingum River generating units
beginning in 1995. In order to comply with Phase II requirements on a least-
cost basis, fuel switching is currently planned at all of the Muskingum River
generating units in January 2000 and at the Cardinal generating unit in 2001.
As a result of the aforementioned PUCO approval of the Company's least-
cost compliance plan, OPCo entered into an agreement in 1992 for construction
and lease of the Gavin Plant scrubbers with JMG Funding Partnership, an
unaffiliated company. The lease will be accounted for as an operating lease.
Management currently expects that the cost of the leased scrubbers will be
approximately $675 million. The scrubbers on Gavin Plant Unit 1 commenced
operation in December 1994 and the Unit 2 scrubbers are expected to commence
operation in March 1995. Capital expenditures for AEP System CAAA-related
environmental-based protection facilities for the next three years are
estimated to be $45 million which excludes the Gavin scrubbers.
Recovery of compliance costs is being sought and will be sought through
the rate-making process. As detailed in Note 2 under Rate Activity, OPCo has
filed an application with the PUCO seeking recovery of its cost of CAAA
compliance and entered into a Settlement Agreement regarding this rate
request. This Ohio 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 Muskingum and Windsor mining operations to the extent
the actual cost of coal burned at the Gavin Plant is below a predetermined
price. The Settlement Agreement requires PUCO approval. AEP intends to also
seek timely recovery of all compliance costs, including mine shutdown costs,
from its non-Ohio jurisdictional customers. There can be no assurance that
regulators will provide for recovery of all CAAA compliance costs on a timely
basis. Compliance with the CAAA, including potential mine closure costs,
will have an adverse effect on results of operations and possibly financial
condition unless the cost can be recovered from ratepayers and/or from asset
dispositions.
Other Environmental Matters - The AEP System is regulated by federal, state
and local authorities with respect to air and water quality and other
environmental matters. Local authorities also regulate zoning. The
generation of electricity produces non-hazardous and hazardous by-products.
Asbestos, polychlorinated biphenyls (PCBs) and other hazardous materials have
been used in the generating plants and transmission/distribution facilities.
Substantial costs to store and dispose of hazardous materials have been
incurred. Significant additional costs could be incurred in the future to
meet the requirements of new laws and regulations and to clean up disposal
sites under existing legislation. Management has no knowledge of any
material clean up costs related to AEP's past disposal of hazardous and non-
hazardous materials.
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. Should nuclear losses or liabilities be
underinsured or exceed accumulated funds, or should recovery through
regulated rates be denied, results of operations and financial condition
would be negatively affected. Specific information about nuclear risk
management and potential liabilities is discussed below.
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
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 $41.9 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
$154 million for fuel consumed prior to April 7, 1983 have been recorded as
long-term debt with an offsetting regulatory asset. The regulatory asset at
December 31, 1994 of $8.4 million is being amortized as rate recovery occurs.
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, 1994, funds collected from customers and
related earnings including accrued interest totaled $145.6 million.
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. Estimated decommissioning and low level radioactive waste
accumulation disposal costs range from $634 million to $988 million in 1993
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 which depends on future developments in the
federal government's spent nuclear fuel disposal program. 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 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 which was $26 million in 1994, $13
million in 1993 and $12 million in 1992. Decommissioning amounts recovered
from customers are deposited in external trusts. Trust fund earnings
increase the fund assets and the recorded liability. Trust fund earnings
decrease the amount to be recovered from ratepayers. At December 31, 1994
I&M has recognized a decommissioning liability of $212 million.
Kammer Plant - In August 1994 the United States Environmental Protection
Agency (Federal EPA) issued a Notice of Violation (NOV) to OPCo alleging that
the Kammer Plant has been operating in violation of applicable federally
enforceable air pollution control requirements since January 1, 1989. By
law, civil penalties of up to $25,000 per day may be imposed for each day of
violation. A Consent Decree was negotiated and filed on November 15, 1994
which resolves that portion of the NOV relating to compliance. The portion
of the NOV relating to penalties will be addressed independently. At this
time management is unable to estimate the amount of any civil penalties that
may be imposed by the Federal EPA. It is not anticipated that the ultimate
resolution of this matter will have a material adverse impact on results of
operations.
Litigation - The Company is involved in a number of legal proceedings and
claims. While management is unable to predict the outcome of litigation, it
is not expected that the resolution of these matters will have a material
adverse effect on 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, 1994, $234 million of retained earnings were restricted. To
pay dividends out of paid-in capital the subsidiaries need regulatory
approval.
6.Lines of Credit and Commitment Fees:
At December 31, 1994 and 1993 short-term bank lines of credit were available
in the amounts of $558 million and $537 million, respectively. Commitment
fees of approximately 3/16 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) 1994 1993
Balance Outstanding:
Notes Payable $ 42,535 $ 65,526
Commercial Paper 274,450 213,450
Total $316,985 $278,976
Weighted Average Interest Rate:
Notes Payable 6.2% 3.5%
Commercial Paper 6.3% 3.7%
Total 6.3% 3.6%
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:
Year Ended December 31,
(In Thousands) 1994 1993 1992
Service Cost-Benefits Earned
During the Year $ 40,000 $ 37,100 $ 36,600
Interest Cost on Projected
Benefit Obligations 114,500 112,600 110,100
Actual Return on Assets (6,700) (150,000) (97,600)
Net Amortization and Deferral (123,300) 24,700 (17,800)
Net AEP Pension Plan Costs $ 24,500 $ 24,400 $ 31,300
<PAGE>
AEP pension plan assets and actuarially computed benefit obligations are:
December 31,
(In Thousands) 1994 1993
AEP Pension Plan Assets at
Fair Value (a) $1,480,600 $1,560,900
Actuarial Present Value of
Benefit Obligations:
Vested 1,130,000 1,315,200
Nonvested 120,700 144,700
Accumulated Benefit Obligation 1,250,700 1,459,900
Effects of Salary Progression 132,600 176,600
Projected Benefit Obligation 1,383,300 1,636,500
Funded Status - AEP Pension Plan
Assets in Excess of or (Less Than)
Projected Benefit Obligation 97,300 (75,600)
Unrecognized Prior Service Cost 160,800 174,500
Unrecognized Net Gain (229,000) (35,500)
Unrecognized Net Transition Assets
(Being Amortized Over 17 Years) (88,600) (98,400)
Accrued Net AEP Pension
Plan Liability $ (59,500) $ (35,000)
(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:
December 31,
1994 1993 1992
Discount Rate 8.5% 7.0% 8.22%
Average Rate of Increase in
Compensation Levels 3.2% 3.2% 5.6 %
Expected Long-term Rate of Return 8.5% 9.0% 9.25%
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 three 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 $18.6 million
in 1994, $17.6 million in 1993 and $17.1 million in 1992.
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,
1994, the UMWA actuary estimates the OPCo coal-mining subsidiaries' share of
the UMWA pension plans unfunded vested liabilities was approximately $46
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 $1.6 million in
both 1994 and 1993 and $2.1 million in 1992.
Postretirement Benefits Other Than Pensions - 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. Prior to 1993, net
costs of these benefits were recognized as an expense when paid and totaled
$12.3 million in 1992.
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. The cost of health care benefits for this group was
expensed when paid in 1992 and totaled $16.5 million.
SFAS 106, Employers' Accounting for Postretirement Benefits Other Than
Pensions, was adopted in January 1993 for the Company's aggregate liability
for postretirement benefits other than pensions (OPEB). SFAS 106 requires
the accrual of the present value liability for OPEB costs during the
employee's service years. Costs for the accumulated postretirement benefits
earned and not recognized at adoption are being recognized, in accordance
with SFAS 106, as a transition obligation over 20 years.
Management has taken several measures to reduce the impact of its
postretirement benefits cost. 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, as other property and investments. 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 implementation of SFAS 106 which is comprised of
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 $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 regulator 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, 1994 and 1993, $28.5 million and
$19.1 million, respectively, of incremental OPEB costs were deferred.
<PAGE>
Aggregate OPEB costs were computed as follows:
December 31,
(In Thousands) 1994 1993
Service Cost $16,500 $15,700
Interest Cost on Projected
Benefit Obligation 47,300 45,300
Net Amortization of Transition Obligation 31,100 28,200
Return on Plan Assets 900 (1,000)
Net Amortization and Deferral (6,800) -
Net OPEB Costs $89,000 $88,200
OPEB assets and actuarially computed benefit obligations are:
December 31,
(In Thousands) 1994 1993
Fair Market Value of Plan Assets (a) $ 87,200 $ 58,600
Accumulated Postretirement Benefit
Obligation:
Active Employees Fully Eligible
for Benefits 41,200 26,800
Current Retirees 361,500 357,000
Other Active Employees 245,800 278,200
Total Benefit Obligations 648,500 662,000
Unfunded Benefit Obligation (561,300) (603,400)
Unrecognized Net Loss 8,900 48,000
Unrecognized Transition Obligation
Being Amortized Over 20 Years 517,700 550,100
Accrued OPEB Liability $ (34,700) $ (5,300)
(a) Plan assets represent cash surrender value of life insurance contracts on
certain employees owned by the trust.
Assumptions used to determined OPEB's funded status were:
December 31,
1994 1993 1992
Discount Rate 8.5% 7.0% 8.22%
Expected Long-Term Rate of Return
on Plan Assets 8.25% 8.75% 9.0%
Initial Medical Cost Trend Rate 8.0% 8.0% 9.0%
Ultimate Medical Cost Trend Rate 5.25% 4.25% 5.25%
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 1994 OPEB
cost for all employees, both non-UMWA and UMWA would increase by $8 million
and the accumulated benefit obligations would increase by $71 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 $3.1 million in 1994, $3.8 million in 1993 and
$10 million in 1992.
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 $6.9
million in 1994 and $10 million in 1993. The Black Lung Trust had excess
funds at December 31, 1994 and 1993 of $16 million and $18 million,
respectively.
8. Fair Value of Financial Instruments:
Nuclear Trust Funds Recorded at Market Value - Effective January 1, 1994, the
Company adopted SFAS 115, Accounting for Certain Investments in Debt and
Equity Securities, which requires fair value accounting for investments in
equity securities with readily determinable market values and investments in
debt securities except those that the reporting enterprise has the positive
intent and ability to hold to maturity. Debt securities not classified as
held-to-maturity and qualifying equity securities, shall be classified as
trading or available-for-sale. The Company's investments held in trust funds
for decommissioning nuclear facilities and for the disposal of spent nuclear
fuel have been classified as available-for-sale. SFAS 115 requires that
unrealized gains and losses on investments classified as available-for-sale
be reported as a separate component of shareholders' equity. However, due to
the rate-making process, adjustments under SFAS 115 for unrealized gains and
losses to the carrying value of investments held in the trusts result in
corresponding adjustments to regulatory assets and liabilities.
The cumulative effect of adopting SFAS 115 resulted in an increase
in the decommissioning and spent nuclear fuel trust fund assets of $20.4
million comprised of an unrealized holding gain of $21.4 million and an
unrealized holding loss of $1 million, with no effect on net income and/or
shareholders' equity. The trust investments, reported in other property and
investments, had a fair value of $321 million at January 1, 1994 and consist
primarily of long-term tax-exempt municipal bonds. In accordance with SFAS
115, prior year amounts were not restated.
At December 31, 1994 the fair value of the trust investments was $353
million. Accumulated gross unrealized holding gains and losses were $5.5
million and $12.2 million, respectively, at December 31, 1994. The change in
market value during 1994 was a $27.1 million net holding loss.
The trust investments' cost basis by security type at December 31, 1994,
was:
(In Thousands)
Treasury Bonds $ 997
Tax-Exempt Bonds 332,098
Equity Securities 1,665
Cash and Cash Equivalents 25,304
Total $360,064
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, 1994, the year of maturity of trust fund investments
other than equity securities, was:
(In Thousands)
1995 $ 39,173
1996 - 1999 85,199
2000 - 2004 142,868
After 2004 91,159
Total $358,399
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 $537 million and $512 million and for long-term
debt were $4.7 billion and $5.3 billion at December 31, 1994 and 1993,
respectively. The carrying amounts for preferred stock subject to mandatory
redemption were $590 million and $501 million and for long-term debt were
$5.0 billion and $5.0 billion at December 31, 1994 and 1993, 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.
9. Federal Income Taxes:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
(In Thousands) 1994 1993 1992
Charged (Credited) to Operating
Expenses (net):
Current $240,655 $270,318 $ 93,266
Deferred (6,367) (49,652) 91,188
Deferred Investment Tax Credits (17,079) (17,235) (18,235)
Total 217,209 203,431 166,219
Charged (Credited) to Nonoperating
Income (net):
Current (2,907) 8,727 17,600
Deferred (5,856) 4,603 11,992
Deferred Investment Tax Credits (14,196) (9,780) (9,561)
Total (22,959) 3,550 20,031
Credited to Loss from
Zimmer Plant Disallowance (net):
Deferred - (13,327) -
Deferred Investment Tax Credits - (1,207) -
Total - (14,534) -
Total Federal Income Taxes
as Reported $194,250 $192,447 $186,250
<PAGE>
The following is a reconciliation of the difference between the amount
of federal income taxes computed by multiplying book income before federal
income taxes by the statutory tax rate, and the amount of federal income
taxes reported.
Year Ended December 31,
(In Thousands) 1994 1993 1992
Income Before Preferred Stock
Dividend Requirements
of Subsidiaries $554,707 $412,587 $527,651
Federal Income Taxes 194,250 192,447 186,250
Pre-Tax Book Income $748,957 $605,034 $713,901
Federal Income Tax on Pre-Tax
Book Income at Statutory Rate
(1994 and 1993-35%, 1992-34%) $262,135 $211,762 $242,726
Increase (Decrease) in Federal
Income Tax Resulting from
the Following Items:
Depreciation 31,212 27,554 24,337
Removal Costs (13,818) (17,730) (15,124)
Corporate Owned Life Insurance (22,970) (27,310) (25,490)
Investment Tax Credits (net) (31,273) (28,218) (26,528)
Zimmer Plant Disallowance - 42,346 -
Federal Income Tax
Accrual Adjustments (16,100) (6,500) -
Other (14,936) (9,457) (13,671)
Total Federal Income Taxes
as Reported $194,250 $192,447 $186,250
Effective Federal Income
Tax Rate 25.9% 31.8% 26.1%
The following tables show the elements of the net deferred tax liability and
the significant temporary differences:
December 31,
(In Thousands) 1994 1993
Deferred Tax Assets $ 712,048 $ 709,895
Deferred Tax Liabilities (3,185,587) (3,177,910)
Net Deferred Tax Liabilities $(2,473,539) $(2,468,015)
Property Related Temporary Differences $(2,098,304) $(2,074,684)
Amounts Due From Customers For
Future Federal Income Taxes (483,512) (477,331)
Deferred Net Gain - Rockport Plant Unit 2 125,278 129,794
All Other (net) (17,001) (45,794)
Total Net Deferred Tax Liabilities $(2,473,539) $(2,468,015)
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 1988. Returns for the years 1988 through 1990 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>
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:
Year Ended December 31,
(In Thousands) 1994 1993 1992
Operating Leases $233,805 $243,190 $268,810
Amortization of Capital Leases 79,116 84,226 59,971
Interest on Capital Leases 23,280 23,839 22,562
Total Rental Payments $336,201 $351,255 $351,343
Properties under capital leases and related obligations on the
Consolidated Balance Sheets are as follows:
December 31,
(In Thousands) 1994 1993
ELECTRIC UTILITY PLANT:
Production $ 44,683 $ 26,831
Transmission 38 364
Distribution 14,717 14,717
General:
Nuclear Fuel (net of amortization) 89,478 45,660
Mining Plant and Other 403,038 332,099
Total Electric Utility Plant 551,954 419,671
Accumulated Amortization 173,641 164,820
Net Electric Utility Plant 378,313 254,851
OTHER PROPERTY 24,724 30,986
Accumulated Amortization 2,838 1,985
Net Other Property 21,886 29,001
Net Property under Capital Leases $400,199 $283,852
Obligations under Capital Leases $400,199 $283,852
Less Portion Due Within One Year 93,252 62,215
Noncurrent Capital Lease Liability $306,947 $221,637
<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,
1994:
Noncancelable
Capital Operating
(In Thousands) Leases Leases
1995 $ 80,308 $ 252,206
1996 66,203 250,427
1997 52,654 245,813
1998 39,650 237,146
1999 33,008 234,891
Later Years 141,781 4,378,882
Total Future Minimum Lease Rentals 413,604(a) $5,599,365
Less Estimated Interest Element 102,883
Estimated Present Value of Future
Minimum Lease Rentals 310,721
Unamortized Nuclear Fuel 89,478
Total $400,199
(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:
Year Ended December 31,
(In Thousands) 1994 1993 1992
Purchased Power - Ohio Valley Electric Corp.
(44.2% owned by AEP) $5,755 $19,253 $15,599
Cash was paid for:
Interest (net of capitalized amounts) $379,361 $421,060 $447,549
Income Taxes $312,233 $245,350 $128,200
Noncash Acquisitions under
Capital Leases were $227,055 $80,220 $108,726
In connection with a 1992 sale of coal-mining properties, a coal-mining
subsidiary is receiving cash payments of $77 million over a 13-1/2 year
period which had a net present value of $44.6 million at the time of the
sale.
<PAGE>
<TABLE>
12. CAPITAL STOCKS AND PAID-IN CAPITAL:
Changes in capital stocks and paid-in capital during the period January 1, 1992 through December 31, 1994 were:
<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)
<S> <C> <C> <C> <C> <C> <C>
January 1, 1992 193,534,992 9,953,201 $1,257,977 $1,630,466 $ 534,978 $140,662
Issues - 1,000,000 - - - 100,000
Retirements and Other - (191,526) - (1,149) - (7,153)
December 31, 1992 193,534,992 10,761,675 1,257,977 1,629,317 534,978 233,509
Issues - 3,250,000 - - - 325,000
Retirements and Other - (6,323,907) - (4,249) (266,738) (57,972)
December 31, 1993 193,534,992 7,687,768 1,257,977 1,625,068 268,240 500,537
Issues 700,000 900,000 4,550 17,706 - 90,000
Retirements and Other - (351,517) - (1,252) (35,000) (152)
December 31, 1994 194,234,992 8,236,251 $1,262,527 $1,641,522 $ 233,240 $590,385
(a) Includes 8,999,992 shares of treasury stock.
(b) Including portion due within one year.
</TABLE>
13. Unaudited Quarterly Financial Information:
Quarterly Periods Ended
(In Thousands - Except 1994
Per Share Amounts) March 31 June 30 Sept. 30 Dec. 31
Operating Revenues $1,488,185 $1,348,563 $1,385,278 $1,282,644
Operating Income 257,448 219,427 246,946 208,399
Net Income 152,954 103,793 139,826 103,439
Earnings per Share 0.83 0.56 0.76 0.56
Quarterly Periods Ended
(In Thousands - Except 1993
Per Share Amounts) March 31 June 30 Sept. 30 Dec. 31
Operating Revenues $1,321,450 $1,210,398 $1,406,311 $1,330,683
Operating Income 240,965 195,196 242,156 250,053
Net Income (Loss) 133,058 86,219 (10,139) 144,631
Earnings (Loss)
per Share 0.72 0.47 (0.06) 0.79
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. The third quarter 1993 loss results from the Zimmer
disallowance discussed in Note 3.
<PAGE>
<TABLE>
American Electric Power Company, Inc. and Subsidiary Companies
SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
<CAPTION>
December 31, 1994
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% - 7.76% $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% $109.50(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
___________________________________________________________________________________________________________
<CAPTION>
December 31, 1993
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 1,600,000 1,600,000 160,000
8.04% $102.58 150,000 150,000 15,000
Total Not Subject to Mandatory
Redemption $268,240
Subject to Mandatory Redemption (c):
4.50% $102 19,625 5,365 $ 537
5.90% - 5.92% (d) 1,950,000 1,950,000 195,000
6.02% - 6-7/8% (e) 1,300,000 1,300,000 130,000
7% - 7-7/8% $107.80-$107.88(f) 1,000,000 1,000,000 100,000
9.50% $109.50(g) 750,000 750,000 75,000
Total Subject to Mandatory
Redemption (h) 500,537
Less Portion Due Within One Year 87
Long-term Portion $500,450
</TABLE>
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, 1994 price is shown) plus accrued dividends. The
involuntary liquidation preference is $100 per share for all outstanding shares.
(b) As of December 31, 1994 the subsidiaries had 2,730,000, 22,200,000 and
5,546,152 shares of $100, $25 and no par valve 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) Redemption is restricted prior to November 1995.
(h) The sinking fund provisions of the series subject to mandatory redemption
aggregate $85,000, $3,900,000, $3,835,000, $8,750,000 and $8,750,000 in 1995,
1996, 1997, 1998 and 1999, respectively.
<PAGE>
<TABLE>
American Electric Power Company, Inc. and Subsidiary Companies
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
<CAPTION>
Weighted Average
Maturity Interest Rate Interest Rates at December 31, December 31,
December 31, 1994 1994 1993 1994 1993
(in thousands)
<S> <C> <C> <C> <C> <C>
FIRST MORTGAGE BONDS
1995-1999 7.16% 5%-9.15% 5%-9.15% $ 526,866 $ 596,566
2001-2004 7.26% 6%-9.31% 6%-9.31% 1,450,020 1,264,020
2017-2024 8.37% 7.10%-9-7/8% 7.10%-9-7/8% 1,540,661 1,677,186
INSTALLMENT PURCHASE CONTRACTS (a)
1995-1998 6.55% 6%-7-1/4% 3.65%-7-1/4% 174,500 174,500
2007-2022 6.82% 5.45%-9-3/8% 5.45%-9-3/8% 811,745 811,745
NOTES PAYABLE (b)
1994 - 2008 8.29% 5.29%-10.78% 3.725%-10.78% 313,000 318,000
SINKING FUND DEBENTURES (c)
1996 - 1999 6.40% 5-1/8%-7-7/8% 5-1/8%-7-7/8% 30,759 31,153
OTHER LONG-TERM DEBT (d) 163,896 154,386
Unamortized Discount (net) (31,128) (32,355)
Total Long-term Debt
Outstanding (e) 4,980,319 4,995,201
Less Portion Due Within One Year 293,671 31,141
Long-term Portion $4,686,648 $4,964,060
</TABLE>
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 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) Prior to December 31, 1994 sufficient principal amounts of debentures
had been reacquired in anticipation of all future sinking fund requirements.
(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, 1994 is payable as follows:
Principal Amount (in thousands)
1995 $ 293,671
1996 117,062
1997 90,513
1998 274,645
1999 139,905
Later Years 4,095,651
Total $5,011,447
<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, 1994 and
1993, and the related consolidated statements of income, retained earnings,
and cash flows for each of the three years in the period ended December 31,
1994. 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, 1994 and 1993, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1994 in conformity with generally accepted
accounting principles.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 21, 1995
<PAGE>
<TABLE>
EXHIBIT 21
Subsidiaries of
American Electric Power Company, Inc.
As of January 1, 1995
<CAPTION>
Percentage
of Voting
Securities
State 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)
Kanawha Valley Power Company West Virginia 100.0
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 94.2 (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
553,848 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
1,712,403 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>
<PAGE>
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Post-Effective
Amendment No. 3 to Registration Statement No. 33-1052 of American
Electric Power Company, Inc. on Form S-8 and Post-Effective
Amendment No. 2 to Registration Statement No. 33-1734 of American
Electric Power Company, Inc. on Form S-3 of our reports dated
February 21, 1995, 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, 1994.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
March 28, 1995
/PAGE
<PAGE>
<PAGE>
Exhibit 24
POWER OF ATTORNEY
AMERICAN ELECTRIC POWER COMPANY, INC.
Annual Report on Form lO-K for the Fiscal Year Ended
December 31, 1994
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, 1994, 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 22nd day of February, 1995.
/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/ Arthur G. Hansen /s/ Linda Gillespie Stuntz
Arthur G. Hansen Linda Gillespie Stuntz
/s/ Lester A. Hudson, Jr. /s/ Morris Tanenbaum
Lester A. Hudson, Jr. Morris Tanenbaum
/s/ G. P. Maloney /s/ Ann Haymond Zwinger
G. P. Maloney Ann Haymond Zwinger
/PAGE
<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-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 11,348,110
<OTHER-PROPERTY-AND-INVEST> 735,042
<TOTAL-CURRENT-ASSETS> 1,281,438
<TOTAL-DEFERRED-CHARGES> 398,257
<OTHER-ASSETS> 1,949,852
<TOTAL-ASSETS> 15,712,699
<COMMON> 1,262,527
<CAPITAL-SURPLUS-PAID-IN> 1,641,522
<RETAINED-EARNINGS> 1,325,581
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4,229,630
590,300
233,240
<LONG-TERM-DEBT-NET> 4,686,648
<SHORT-TERM-NOTES> 42,535
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 274,450
<LONG-TERM-DEBT-CURRENT-PORT> 293,671
85
<CAPITAL-LEASE-OBLIGATIONS> 306,947
<LEASES-CURRENT> 93,252
<OTHER-ITEMS-CAPITAL-AND-LIAB> 4,961,941
<TOT-CAPITALIZATION-AND-LIAB> 15,712,699
<GROSS-OPERATING-REVENUE> 5,504,670
<INCOME-TAX-EXPENSE> 235,043
<OTHER-OPERATING-EXPENSES> 4,337,407
<TOTAL-OPERATING-EXPENSES> 4,572,450
<OPERATING-INCOME-LOSS> 932,220
<OTHER-INCOME-NET> 11,485
<INCOME-BEFORE-INTEREST-EXPEN> 943,705
<TOTAL-INTEREST-EXPENSE> 388,998
<NET-INCOME> 500,012
54,695<F1>
<EARNINGS-AVAILABLE-FOR-COMM> 500,012
<COMMON-STOCK-DIVIDENDS> 443,101
<TOTAL-INTEREST-ON-BONDS> 270,745
<CASH-FLOW-OPERATIONS> 977,725
<EPS-PRIMARY> $2.71
<EPS-DILUTED> $2.71
<FN>
<F1>Represents preferred stock dividend requirements of
subsidiaries; deducted before computation of net income.
</FN>
</TABLE>
