<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 3(b)
CERTIFICATE OF AMENDMENT
TO AMENDED ARTICLES OF INCORPORATION OF
COLUMBUS SOUTHERN POWER COMPANY
BY THE BOARD OF DIRECTORS
The undersigned, Vice President and Assistant Secretary, of
Columbus Southern Power Company, an Ohio corporation, with its
principal office located in Columbus, Ohio, do hereby certify
that a meeting of the Board of Directors of said corporation was
duly called and held on the 19th day of May, 1994, at which
meeting a quorum of such Directors was present, and that at such
meeting the following Resolution of Amendment to Amended Articles
of Incorporation, as amended, was duly adopted under authority of
subdivision (B)(l) of Ohio Revised Code Section 1701.70:
RESOLVED, that the Amended Articles of Incorporation of
Columbus Southern Power Company, dated and filed in the
office of the Secretary of State of the State of Ohio on
November 14, 1990, subsequently as amended, be further
amended by adding at the end of Article IV thereof, the
following new Divisions 15 and 16:
15. Subject to and in accordance with the
provisions of this Article IV, there is hereby created
a series of Cumulative Preferred Shares of the par
value of $100 per share which shall be designated
"Cumulative Preferred Shares, 7% Series" and shall
consist of a maximum of 250,000 Cumulative Preferred
Shares of such series. Shares of such series redeemed
or otherwise acquired by the Corporation shall be
retired and shall thereafter be authorized and unissued
shares of Cumulative Preferred Shares, with a par value
of $100 per share, without designation as to series.
16. The preferences, rights, restrictions or
qualifications and the description and terms of the
Cumulative Preferred Shares, 7% Series, in the respects
in which the shares of such series vary from shares of
other series of the Cumulative Preferred Shares, $100
par value, shall be as follows:
(i) The annual dividend rate for such
series shall be 7% per share, per annum, which
dividend shall be calculated, per share, at such
percentage multiplied by $100, payable quarterly
on the first days of February, May, August and
November in each year with respect to the
quarterly period ending on the day preceding each<PAGE>
such respective payment date, and the date from
which dividends shall be cumulative on all shares
of such series issued prior to the record date for
the dividend payable August 1, 1994 shall be the
date of original issue of shares of such series.
(ii) Shares of such series are not
redeemable except as provided in clause (iv) of
this Division 16.
(iii) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any voluntary or involuntary liquidation,
dissolution or winding up of the Corporation shall
be $100 per share plus an amount equal to accrued
and unpaid dividends.
(iv)(1) A sinking fund shall be established
for the retirement of the shares of such series.
So long as there shall remain outstanding any
shares of such series, the Corporation shall, to
the extent permitted by law, redeem as and for a
sinking fund requirement, out of funds legally
available therefor, 50,000 shares of such series,
at a sinking fund redemption price of $100 per
share plus accrued and unpaid dividends to the
date of redemption on August 1 of each year
commencing with the year 2000. The sinking fund
requirements shall be cumulative so that if on any
such August 1 the sinking fund requirement shall
not have been met, then such sinking fund
requirement, to the extent not met, shall become
an additional sinking fund requirement for the
next succeeding August 1 on which such redemption
may be effected.
(2) The Corporation shall have the non-
cumulative option, on any sinking fund date as
provided in clause (iv)(1) of this Division 16, to
redeem at the sinking fund redemption price of
$100 per share plus accrued and unpaid dividends
to the date of redemption up to an additional
50,000 shares of such series. No redemption made
pursuant to this clause (iv)(2) shall be deemed to
fulfill any sinking fund redemption established
pursuant to clause (iv)(1).
(3) The Corporation shall be entitled,
at its election, to credit against the sinking
fund requirement due on August 1 of any year
pursuant to clause (iv)(1) of this Division 16,
shares of such series theretofore purchased or
2<PAGE>
otherwise acquired by the Corporation (other than
pursuant to the option provided by clause (iv)(2)
of this Division 16) and not previously credited
against any such sinking fund requirement.
(v) The shares of such series shall not
have any rights to convert the same into and/or
purchase shares of any other series or class or
other securities, or any special rights other than
those specified herein.
FURTHER RESOLVED, that a certificate signed by the
Chairman of the Board, the President, or a Vice President
and the Secretary or an Assistant Secretary of the
Corporation, containing a copy of this resolution and a
statement of the manner of its adoption, be filed in the
Office of the Secretary of State of the State of Ohio.
IN WITNESS WHEREOF, the undersigned Vice President and
Assistant Secretary of Columbus Southern Power Company, acting
for and on behalf of said corporation, have hereunto subscribed
their names this 19th day of May, 1994.
COLUMBUS SOUTHERN POWER COMPANY
By__/s/ G. P. Maloney_____________
Vice President
By__/s/ Jeffrey D. Cross__________
Assistant Secretary
</PAGE>
<PAGE>
Exhibit 3(c)
AMENDED ARTICLES OF INCORPORATION
OF
COLUMBUS SOUTHERN POWER COMPANY
ARTICLE I: Name and Principal Office
The name of the Corporation shall be Columbus Southern Power
Company, and its principal office shall be located in the City of
Columbus, Franklin County, Ohio.
ARTICLE II: Purpose
The purpose of the Corporation is to engage in any lawful
act or activity for which corporations may be formed under
Chapter 1701 of the Ohio Revised Code, as now in effect or
hereafter amended.
ARTICLE III: Authorized Shares
The maximum number of shares which the Corporation is
authorized to have outstanding shall be Thirty-Three Million Five
Hundred Thousand (33,500,000), classified as follows: (a) Two
Million Five Hundred Thousand (2,500,000) shares shall be
Cumulative Preferred Shares, of the par value of One Hundred
Dollars ($100.00) per share; (b) Seven Million (7,000,000) shares
shall be Cumulative Preferred Shares, of the par value of Twenty-
Five Dollars ($25.00) per share; and (c) Twenty-Four Million
(24,000,000) shares shall be Common Shares, without par value.
"Cumulative Preferred Shares ($100.00)", when used herein,
shall refer to all series of Cumulative Preferred Shares of the
par value of One Hundred Dollars ($100.00) per share; "Cumulative
Preferred Shares ($25.00)", when used herein shall refer to all
series of Cumulative Preferred Shares of the par value of Twenty-
Five Dollars ($25.00) per share, and "Cumulative Preferred
Shares", when used herein, shall refer collectively to all series
of Cumulative Preferred Shares ($100.00) and Cumulative Preferred
Shares ($25.00).
ARTICLE IV: Terms of Shares
1. Priority. The Cumulative Preferred Shares ($100.00) and the
Cumulative Preferred Shares ($25.00) shall be of equal rank
and, except as to matters relating to the par values and
voting rights thereof, and permitted variations between the
respective series thereof, shall confer equal rights upon
the holders thereof. The holders of the Common Shares are
subject to all of the rights and preferences of the holders
of the Cumulative Preferred Shares.<PAGE>
2. Voting Rights. Except as otherwise expressly provided in
this Article IV or required by the law of the State of Ohio,
the holders of the Cumulative Preferred Shares shall not be
entitled to vote. The holders of the Common Shares shall be
entitled to one vote per share upon all matters presented to
the shareholders. Whenever, pursuant to the provisions of
this Article IV or the law of the State of Ohio, the holders
of the Cumulative Preferred Shares shall be entitled to
vote, every holder of Cumulative Preferred Shares ($100.00)
shall be entitled to one (1) vote per share, and every
holder of Cumulative Preferred Shares ($25.00) shall be
entitled to one-fourth (1/4) of one (1) vote per share.
Except as otherwise specifically provided in this Article
IV, any action to be taken by the shareholders of the
Corporation under any provision of the Ohio Revised Code
which would require the affirmative vote of two-thirds of
the voting power of the Corporation unless otherwise
provided in the Articles of Incorporation may be taken by
the affirmative vote of the majority of the voting power of
the Corporation.
No holder of shares of any class of stock of the Corporation
shall have the right to vote cumulatively in the election of
directors.
3. Pre-emptive Rights. No holder of shares of any class of
stock of the Corporation shall have any pre-emptive right to
purchase any shares of stock of the Corporation, or
securities convertible into or carrying rights to purchase
shares, whether now or hereafter authorized, and whether
issued for cash, property, services or otherwise.
4. Cumulative Preferred Shares - Issuance in Series. The Board
of Directors is authorized to cause the Cumulative Preferred
Shares to be issued in one or more series, and with respect
to each such series to fix:
(i) the distinctive serial designation and
number of shares of the series;
(ii) the dividend rate or rates (which may be
fixed or variable) of the series, or the method by
which such rate or rates shall be determined;
(iii) the dates of payment of dividends, and the
date or dates from which dividends shall be cumulative;
(iv) the redemption rights (if any) and
redemption price or prices for shares of the series;
(v) the sinking fund requirements (if any) for
the purchase or redemption of shares of the series;
(vi) the amount or amounts which shall be
payable to the holders of shares of the series in the
event of any liquidation, dissolution or winding up of
the affairs of the Corporation, which amount or amounts
may differ in the event of voluntary or involuntary
liquidation, dissolution or winding up;<PAGE>
(vii) the rights (if any) of the holders of
shares of the series to convert such shares into shares
of any other series or class or other securities, and
the terms and conditions of any such conversion; and
(viii) any other preferences, rights, restrictions
or qualifications permitted by law and not inconsistent
with the provisions of this ARTICLE IV which apply to
all series of Cumulative Preferred Shares.
5. Dividends. The holders of each series of Cumulative
Preferred Shares shall be entitled to receive, when and as
declared by the Board of Directors out of funds legally
available, cash dividends at the rate or rates and payable
on the dates fixed for such series as herein provided;
dividends on all series shall be cumulative.
In no event, so long as any Cumulative Preferred Shares
shall be outstanding, shall any dividend, whether in cash or
in property, be paid or declared, nor shall any distribution
be made, on any Common Shares or any other shares of the
Corporation ranking junior to the Cumulative Preferred
Shares in respect of dividends or assets, nor shall any such
junior shares be purchased, redeemed or otherwise acquired
for value by the Corporation, unless all dividends on the
Cumulative Preferred Shares of all series for all past
dividend periods shall have been paid or declared and a sum
sufficient for the payment thereof set apart. The foregoing
provisions of this Division 5 shall not, however, apply to a
dividend payable in such junior shares, nor to the
acquisition of such junior shares in exchange for or through
application of the proceeds of the sale of junior shares,
nor to the acquisition of junior shares issued for cash or
property subsequent to the date of issuance of the
Cumulative Preferred Shares outstanding at the time of such
acquisition to the extent of the cash received or the cost
or fair value (whichever is less) of property received as
consideration for the issue of such junior shares, nor to
the transfer of any amount from surplus to stated capital.
Subject to the foregoing provisions of this Division 5 and
to any limitations established by the Board of Directors in
connection with the creation of any series of Cumulative
Preferred Shares, the Board of Directors may declare, out of
any funds legally available therefor, dividends (payable in
cash, shares or otherwise) upon the then outstanding Common
Shares and no holders of Cumulative Preferred Shares of any
series shall be entitled to share therein.
6. Liquidation Rights. Before any amount shall be paid to, or
any assets distributed among, the holders of the Common
Shares upon any liquidation, dissolution or winding up of
the affairs of the Corporation, and after paying or
providing for the payment of all creditors of the
Corporation, the holders of Cumulative Preferred Shares of
each series at the time outstanding shall be entitled to be
paid in cash the amount fixed for the particular series as
herein provided, together with a sum in the case of each
share of each series, computed at the annual dividend rate
for the series of which such share is a part, from the date
from which dividends on such share became cumulative to and
including the date fixed for such distribution or payment,
less the aggregate of the dividends theretofore and on such
date paid thereon; but no payments on account of such
distributive amounts shall be made to the holders of any
series of Cumulative Preferred Shares unless there shall
likewise be paid at the same time to the holders of each
other series of Cumulative Preferred Shares like
proportionate distributive amounts, ratably, in proportion
to the full distributive amounts to which they are
respectively entitled as herein provided. The holders of
the Cumulative Preferred Shares of any series shall not be
entitled to receive any amounts with respect thereto upon
any liquidation, dissolution or winding up of the affairs of
the Corporation other than the amounts referred to in this
Division 6. Neither the consolidation or merger of the
Corporation with any other corporation or corporations, nor
the sale or transfer by the Corporation of all or any part
of its assets, shall be deemed to be a liquidation,
dissolution or winding up of the affairs of the Corporation
within the meaning of the foregoing provisions of this
Division 6.
All assets and funds of the Corporation remaining after
paying or providing for the payment of all creditors of the
Corporation and after paying or providing for the payment to
the holders of all outstanding Cumulative Preferred Shares
of the full distributive amounts to which they are entitled
as herein provided shall be divided among and paid to the
holders of the Common Shares according to their rights and
interests.
7. Actions Requiring Vote of Two-Thirds of Voting Power of
Cumulative Preferred Shares. So long as any Cumulative
Preferred Shares of any series are outstanding, the
Corporation shall not, without the consent (given by vote in
person or by proxy at a meeting called for that purpose) of
the holders of at least two-thirds of the voting power of
the Cumulative Preferred Shares then outstanding:
(a) amend, alter, or repeal any of the rights, preferences
or powers of the holders of the Cumulative Preferred
Shares so as to affect adversely any such rights,
preferences or powers; provided, however, that if such
amendment, alteration or repeal affects adversely the
rights, preferences or powers of one or more, but not
all, series of Cumulative Preferred Shares at the time
outstanding, only the consent of the holders of at
least two-thirds of the voting power of each series so
affected shall be required; and provided, further, that
an amendment to increase or decrease the authorized
amount of Cumulative Preferred Shares or to create or
authorize, or increase or decrease the amount of, any
class of stock ranking on a parity with the Cumulative
Preferred Shares as to dividends or assets shall not be
deemed to affect adversely the rights, preferences or
powers of the holders of the Cumulative Preferred
Shares or any series thereof; or<PAGE>
(b) create or authorize any shares of any class of stock
ranking prior to the Cumulative Preferred Shares as to
dividends or assets.
8. Action Requiring Vote of Majority of Voting Power of
Cumulative Preferred Shares. So long as any Cumulative
Preferred Shares of any series are outstanding, the
Corporation shall not, without the consent (given by vote in
person or by proxy at a meeting called for that purpose) of
the holders of at least a majority of the voting power of
the Cumulative Preferred Shares then outstanding, increase
the total authorized amount of Cumulative Preferred Shares
or create or authorize any shares of any class of stock
ranking on a parity with the Cumulative Preferred Shares as
to dividends or assets.
9. Election of Directors by Holders of Cumulative Preferred
Shares. If at any time dividends on any series of
Cumulative Preferred Shares shall be in arrears in an amount
equal to payments for six full quarters or more (or, with
respect to Cumulative Preferred Shares which are not payable
for quarterly dividend periods, an amount equal to payments
for a number of dividend periods containing not less than
540 days), the holders of all series of Cumulative Preferred
Shares, voting together as a single class, shall be entitled
to elect two members of the Board of Directors of the
Corporation until such time as all arrearages in dividends
on the Cumulative Preferred Shares shall have been paid or
declared and set apart for payment. Whenever the right to
elect directors shall have accrued to the holders of the
Cumulative Preferred Shares, as herein provided, the
President of the Corporation shall call a meeting for the
election of directors, such meeting to be held not less than
forty-five (45) days and not more than ninety (90) days
after the accrual of such right. The term of office of all
directors of the Corporation shall terminate at the time of
any such meeting or adjournment thereof held for the purpose
of electing a new Board of Directors, at which a quorum of
the holders of the Cumulative Preferred Shares, or a quorum
of the holders of shares otherwise entitled to vote, shall
be present in person or by proxy, notwithstanding that the
term for which such directors were elected shall not then
have expired. In the event that at any such meeting a
quorum of the holders of the Cumulative Preferred Shares
shall not be present in person or by proxy, the holders of
the shares otherwise entitled to vote, if a quorum thereof
be present in person or by proxy, may temporarilY elect the
directors which the holders of the Cumulative Preferred
Shares were entitled but failed to elect, such directors to
be designated as having been so elected and their term of
office to expire at such time thereafter as their successors
shall be elected by the holders of the Cumulative Preferred
Shares. At any such meeting, the presence in person or by
proxy of the holders of a majority of the voting power of
the outstanding Cumulative Preferred Shares shall be
required to constitute a quorum of Cumulative Preferred
Shares for the election of directors; provided, however,
that the holders of a majority of the voting power of the
Cumulative Preferred Shares present in person or by proxy
shall have the power to adjourn such meeting for the
election of directors from time to time without notice other
than announcement at the meeting.
Whenever the Cumulative Preferred Shares shall be entitled
to elect directors, any holder of record of Cumulative
Preferred Shares shall have the right, during regular
business hours, in person or by a duly authorized
representative, to examine the Corporation's stock records
of Cumulative Preferred Shares for the purpose of
communicating with other holders of such shares with respect
to the exercise of such right of election and to make a list
of such holders.
Whenever the Cumulative Preferred Shares shall be divested
of such voting right, and a request to such effect signed by
any holder of record of any other class of shares then
entitled to vote for the election of directors shall be
delivered to the Corporation at its principal office not
less than one hundred twenty (120) days prior to the date
for the annual meeting next following the date of such
divesting, the President of the Corporation shall call a
special meeting of the holders of the shares then entitled
to vote for directors to be held within sixty (60) days
after the receipt of such request for the purpose of
electing a new Board of Directors to serve until the next
annual meeting or until their respective successors shall be
elected and shall qualify. The term of office of all
directors of the Corporation shall terminate at the time of
any such special meeting or adjournment thereof at which a
quorum of the holders of shares then entitled to vote for
directors shall be present in person or by proxy,
notwithstanding that the term for which such directors had
been elected shall not have expired.
If, during any interval between annual meetings of
shareholders for the election of directors and while the
Cumulative Preferred Shares shall be entitled to elect
directors, the number of directors in office who have been
elected by the holders of the Cumulative Preferred Shares or
by the Common Shares, as the case may be, shall by reason of
resignation, death or removal, be less than the total number
of directors subject to election by the holders of shares of
such class, (a) the vacancy or vacancies shall be filled by
a majority vote of the remaining directors then in office
who were elected by such class or who succeeded directors so
elected, although such majority be less than a quorum (or by
the remaining such director, if only one), and (b) if any
vacancy which occurred more than six months prior to the
date for the next ensuing annual meeting is not so filled
within forty (40) days after the occurrence thereof, the
President of the Corporation shall call a special meeting of
the holders of the shares of such class and such vacancy
shall be filled at such special meeting.
10. Redemption of Cumulative Preferred Shares. Subject to the
express terms of each series, redemption of Cumulative
Preferred Shares may be effected as provided in this
Division 10 at any time or from time to time by paying in
cash the redemption price of the shares of the particular
series, fixed therefor as herein provided, together with a
sum in the case of each share of each series so to be
redeemed, computed at the annual dividend rate for the
series of which that share is a part, from the date from
which dividends on such share become cumulative to the date
fixed for such redemption, less the aggregate of the
dividends theretofore and on such redemption date paid
thereon. Notice of such redemption shall be given, not less
than thirty (30) nor more than sixty (60) days prior to the
date fixed for such redemption, by mail to each holder of
record of such shares at such holder's address on the books
of the Corporation on the record date fixed for the purpose
by the Board of Directors.
In case of the redemption of a part only of the shares of
such series, the shares to be redeemed shall be selected by
lot or by such other manner of random selection as the Board
of Directors shall approve.
If notice of redemption shall have been duly given, and if
on the redemption date specified in such notice all funds
necessary for such redemption shall have been set aside by
the Corporation, separate and apart from its other funds, in
trust for the holders of the shares to be redeemed, so as to
be and continue to be available therefor, then,
notwithstanding that any certificate for such shares shall
not have been surrendered for cancellation, from and after
the date fixed for redemption the shares so to be redeemed
shall no longer be deemed to be outstanding, and all rights
with respect to such shares shall forthwith terminate,
except only the right of the holders thereof to receive on
and after the date fixed for redemption, out of the funds so
set aside in trust, the amount payable upon redemption,
without interest. The Corporation may, after giving notice
as provided above, or after giving to the bank or trust
company hereinafter referred to irrevocable authorization to
mail such notice, and at any time prior to the redemption
date specified in such notice, deposit in trust for the
account of the holders of the shares to be redeemed, so as
to be and continue to be available therefor, with directions
to pay to the holders of the shares to be redeemed the
amounts payable upon such redemption upon surrender of the
certificate or certificates for shares held by such holders,
funds necessary for such redemption with a bank or trust
company having capital, surplus and undivided profits
aggregating at least $5,000,000, designated in such notice,
and, upon such deposit in trust, all shares with respect to
which such deposit shall have been made shall no longer be
deemed to be outstanding, and all rights with respect to
such shares shall forthwith cease and terminate, except only
the right of the holders thereof to receive at any time from
and after the date of such deposit, the amount payable upon
redemption thereof, without interest.
Any monies deposited in trust by the Corporation pursuant to
this Division 10 which remain unclaimed at the end of seven
years from the date fixed for redemption shall be repaid
upon its request, expressed in a resolution of its Board of
Directors, to the Corporation, and thereafter, the holders
of shares so called for redemption shall be deemed unsecured
creditors of the Corporation, entitled to look only to the
Corporation for payment of an amount equal to the sum
payable on redemption, without interest.
11. Subject to and in accordance with the provisions of this
Article IV, there is hereby created a series of Cumulative
Preferred Shares of the par value of $100 per share which
shall be designated "Cumulative Preferred Shares, 9.50%
Series" and shall consist of a maximum of 750,000 Cumulative
Preferred Shares of such series. Shares of such series
redeemed or otherwise acquired by the Corporation shall be
retired and shall thereafter be authorized and unissued
shares of Cumulative Preferred Shares, with a par value of
$100 per share, without designation as to series.
12. The preferences, rights, restrictions or qualifications and
the description and terms of the Cumulative Preferred
Shares, 9.50% Series, in respects in which the shares of
such series vary from shares of other series of the
Cumulative Preferred Shares, $100 par value, shall be as
follows:
(i) The annual dividend rate for such series
shall be 9.50% per share per annum, which dividend
shall be calculated, per share, at such percentage
multiplied by $100, payable quarterly on the first days
of February, May, August and November in each year with
respect to the quarterly period ending on the day
preceding each such respective payment date, and the
date from which dividends shall be cumulative on all
shares of such series issued prior to the record date
for the dividend payable February 1, 1991 shall be the
date of initial issuance of shares of such series.
(ii) Shares of such series may be redeemed by
the Corporation, at its option, by action of the Board
of Directors, at an optional redemption price of
$109.50 per share if redeemed on or prior to October
31, 1995 and thereafter at the following optional
redemption prices:
If Redeemed Optional
During 12 Months Redemption
Period Ending Price
October 31 Per Share
1996 . . . . . . . . . . . . . . . . $106.33
1997 . . . . . . . . . . . . . . . . 105.70
1998 . . . . . . . . . . . . . . . . 105.07
1999 . . . . . . . . . . . . . . . . 104.43
2000 . . . . . . . . . . . . . . . . 103.80
2001 . . . . . . . . . . . . . . . . 103.17
2002 . . . . . . . . . . . . . . . . 102.53
2003 . . . . . . . . . . . . . . . . 101.90
2004 . . . . . . . . . . . . . . . . 101.27
2005 . . . . . . . . . . . . . . . . 100.63
and $100 per share, if redeemed on November 1, 2005 or
thereafter; provided, however, that no share of such
series shall be redeemed prior to November 1, 1995, if
such redemption is for the purpose or in anticipation
of refunding such share, directly or indirectly,
through the incurring of debt, or through the issuance
of shares of capital stock ranking equally with or
prior to the Cumulative Preferred Shares as to
dividends or assets, if such debt has an effective
interest cost to the Corporation (computed in
accordance with generally accepted financial practice),
or such shares of capital stock have an effective
dividend cost to the Corporation (so computed), of less
than 9.58% per annum.
(iii) The preferential amounts to which the
holders of shares of such series shall be entitled upon
any voluntary liquidation, dissolution or winding up of
the affairs of the Corporation shall be the then
applicable optional redemption price per share, as set
forth in clause (ii) of this Division 12, and in the
event of any involuntary liquidation, dissolution or
winding up of the affairs of the Corporation, shall be
$100 per share.
(iv)(1) A sinking fund shall be established for
the retirement of the shares of such series. So long
as there shall remain outstanding any shares of such
series, the Corporation shall, to the extent permitted
by law, on February 1 in each year commencing with the
year 1996, redeem as and for a sinking fund
requirement, out of funds legally available therefor, a
number of shares equal to 5% of the total number of
shares initially classified in Division 11 hereof, at a
redemption price of $100 per share. The sinking fund
requirements shall be cumulative so that if on any such
February 1 the sinking fund requirement shall not have
been met, then such sinking fund requirement, to the
extent not met, shall become an additional sinking fund
requirement for the next succeeding February 1 on which
such redemption may be effected.
(2) The Corporation shall have the non-
cumulative option, on any sinking fund date as provided
in clause (iv)(1) of this Division 12, to redeem at the
sinking fund redemption price of $100 per share an
additional number of shares equal to not more than 5%
of the total number of shares initially classified in
Division 11 hereof. No redemption made pursuant to
this clause (iv)(2) shall be deemed to fulfill any
sinking fund requirement established pursuant to clause
(iv)(1).
(3) The Corporation shall be entitled, at
its election, to credit against any sinking fund
requirement due on February 1 of any year pursuant to
clause (iv)(1) of this Division 12 shares of such
series theretofore purchased or otherwise acquired by
the Corporation and not previously credited against any
such sinking fund requirement.<PAGE>
(v) The shares of such series shall not have
any rights to convert the same into and/or purchase
shares of any other series or class or other
securities, or any special rights other than those
specified herein.
13. Subject to and in accordance with the provisions of this
Article IV, there is hereby created a series of Cumulative
Preferred Shares of the par value of $100 per share which
shall be designated "Cumulative Preferred Shares, 7-7/8%
Series" and shall consist of a maximum of 500,000 Cumulative
Preferred Shares of such series. Shares of such series
redeemed or otherwise acquired by the Corporation shall be
retired and shall thereafter be authorized and unissued
shares of Cumulative Preferred Shares, with a par value of
$100 per share, without designation as to series.
14. The preferences, rights, restrictions or qualifications and
the description and terms of the Cumulative Preferred
Shares, 7-7/8% Series, in the respects in which the shares
of such series vary from shares of other series of the
Cumulative Preferred Shares, $100 par value, shall be as
follows:
(i) The annual dividend rate for such series
shall be 7-7/8% per share, per annum, which dividend
shall be calculated, per share, at such percentage
multiplied by $100, payable quarterly on the first days
of February, May, August and November in each year with
respect to the quarterly period ending on the day
preceding each such respective payment date, and the
date from which dividends shall be cumulative on all
shares of such series issued prior to the record date
for the dividend payable May 1, 1992 shall be the date
of initial issuance of shares of such series.
(ii) Shares of such series may be redeemed in
whole or in part at any time by the Corporation, at its
option, by action of the Board of Directors, at an
optional redemption price of $107.88 per share if
redeemed on or prior to February 28, 1997 and
thereafter at the following optional redemption prices:
Optional
Redemption
Price
Redemption Date (Dates Inclusive) Per Share
March 1, 1997 to February 28, 1998 . . . . .$105.25
March 1, 1998 to February 28, 1999 . . . . . 104.73
March 1, 1999 to February 29, 2000 . . . . . 104.20
March 1, 2000 to February 28, 2001 . . . . . 103.68
March 1, 2001 to February 28, 2002 . . . . . 103.15
March 1, 2002 to February 28, 2003 . . . . . 102.63
March 1, 2003 to February 29, 2004 . . . . . 102.10
March 1, 2004 to February 28, 2005 . . . . . 101.58
March 1, 2005 to February 28, 2006 . . . . . 101.05
March 1, 2006 to February 28, 2007 . . . . . 100.53<PAGE>
and $100 per share, if redeemed on March 1, 2007 or
thereafter; provided, however, that no share of such
series shall be redeemed prior to March 1, 1997, if
such redemption is for the purpose or in anticipation
of refunding such share, directly or indirectly,
through the incurring of debt, or through the issuance
of shares of capital stock ranking equally with or
prior to the Cumulative Preferred Shares as to
dividends or assets, if such debt has an effective
interest cost to the Corporation (computed in
accordance with generally accepted financial practice),
or such shares of capital stock have an effective
dividend cost to the Corporation (so computed), of less
than 7.95% per annum.
(iii) The preferential amounts to which the
holders of shares of such series shall be entitled upon
any voluntary liquidation, dissolution or winding up of
the affairs of the Corporation shall be the then
applicable optional redemption price per share, as set
forth in clause (ii) of this Division 14, and in the
event of any involuntary liquidation, dissolution or
winding up of the affairs of the Corporation, $100 per
share.
(iv)(1) A sinking fund shall be established for
the retirement of the shares of such series. So long
as there shall remain outstanding any shares of such
series, the Corporation shall, to the extent permitted
by law on May 1 in each year commencing with the year
1998, redeem as and for a sinking fund requirement, out
of funds legally available therefor, a number of shares
equal to 5% of the total number of shares initially
classified in Division 13 hereof, at a redemption price
of $100 per share plus accrued unpaid dividends to the
date of redemption. The sinking fund requirements
shall be cumulative so that if on any such May 1 the
sinking fund requirement shall not have been met, then
such sinking fund requirement, to the extent not met,
shall become an additional sinking fund requirement for
the next succeeding May 1 on which such redemption may
be effected.
(2) The Corporation shall have the non-
cumulative option, on any sinking fund date as provided
in clause (iv)(1) of this Division 14, to redeem at the
sinking fund redemption price of $100 per share an
additional number of shares equal to not more than 5%
of the total number of shares initially classified in
Division 13 hereof. No redemption made pursuant to
this clause (iv)(2) shall be deemed to fulfill any
sinking fund requirement established pursuant to clause
(iv)(1).
(3) The Corporation shall be entitled, at
its election, to credit against any sinking fund
requirement due on May 1 of any year pursuant to clause
(iv)(1) of this Division 14 shares of such series
theretofore purchased or otherwise acquired by the<PAGE>
Corporation and not previously credited against any
such sinking fund requirement.
(v) The shares of such series shall not have
any rights to convert the same into and/or purchase
shares of any other series or class or other
securities, or any special rights other than those
specified herein.
15. Subject to and in accordance with the provisions of this
Article IV, there is hereby created a series of Cumulative
Preferred Shares of the par value of $100 per share which
shall be designated "Cumulative Preferred Shares, 7% Series"
and shall consist of a maximum of 250,000 Cumulative
Preferred Shares of such series. Shares of such series
redeemed or otherwise acquired by the Corporation shall be
retired and shall thereafter be authorized and unissued
shares of Cumulative Preferred Shares, with a par value of
$100 per share, without designation as to series.
16. The preferences, rights, restrictions or qualifications and
the description and terms of the Cumulative Preferred
Shares, 7% Series, in the respects in which the shares of
such series vary from shares of other series of the
Cumulative Preferred Shares, $100 par value, shall be as
follows:
(i) The annual dividend rate for such series
shall be 7% per share, per annum, which dividend shall
be calculated, per share, at such percentage multiplied
by $100, payable quarterly on the first days of
February, May, August and November in each year with
respect to the quarterly period ending on the day
preceding each such respective payment date, and the
date from which dividends shall be cumulative on all
shares of such series issued prior to the record date
for the dividend payable August 1, 1994 shall be the
date of original issue of shares of such series.
(ii) Shares of such series are not redeemable
except as provided in clause (iv) of this Division 16.
(iii) The preferential amounts to which the
holders of shares of such series shall be entitled upon
any voluntary or involuntary liquidation, dissolution
or winding up of the Corporation shall be $100 per
share plus an amount equal to accrued and unpaid
dividends.
(iv)(1) A sinking fund shall be established for
the retirement of the shares of such series. So long
as there shall remain outstanding any shares of such
series, the Corporation shall, to the extent permitted
by law, redeem as and for a sinking fund requirement,
out of funds legally available therefor, 50,000 shares
of such series, at a sinking fund redemption price of
$100 per share plus accrued and unpaid dividends to the
date of redemption on August 1 of each year commencing
with the year 2000. The sinking fund requirements
shall be cumulative so that if on any such August 1 the<PAGE>
sinking fund requirement shall not have been met, then
such sinking fund requirement, to the extent not met,
shall become an additional sinking fund requirement for
the next succeeding August 1 on which such redemption
may be effected.
(2) The Corporation shall have the non-
cumulative option, on any sinking fund date as provided
in clause (iv)(1) of this Division 16, to redeem at the
sinking fund redemption price of $100 per share plus
accrued and unpaid dividends to the date of redemption
up to an additional 50,000 shares of such series. No
redemption made pursuant to this clause (iv)(2) shall
be deemed to fulfill any sinking fund redemption
established pursuant to clause (iv)(1).
(3) The Corporation shall be entitled, at
its election, to credit against the sinking fund
requirement due on August 1 of any year pursuant to
clause (iv)(1) of this Division 16, shares of such
series theretofore purchased or otherwise acquired by
the Corporation (other than pursuant to the option
provided by clause (iv)(2) of this Division 16) and not
previously credited against any such sinking fund
requirement.
(v) The shares of such series shall not have any
rights to convert the same into and/or purchase shares
of any other series or class or other securities, or
any special rights other than those specified herein.
ARTICLE V: Effect of Amended Articles
These Amended Articles of Incorporation supersede and take
the place of all prior articles of incorporation of the
Corporation and any and all amendments thereto.
/PAGE
<PAGE>
<PAGE>
<TABLE>
EXHIBIT 12
COLUMBUS SOUTHERN POWER COMPANY
Computation of Consolidated Ratios of Earnings to Fixed Charges
(in thousands except ratio data)
<CAPTION>
Year Ended December 31,
1990 1991 1992 1993 1994
<S> <C> <C> <C> <C> <C>
Fixed Charges:
Interest on First Mortgage Bonds. . . . . . . . . . $ 76,181 $ 80,245 $75,866 $74,119 $68,471
Interest on Other Long-term Debt. . . . . . . . . . 12,276 11,489 11,430 10,436 10,221
Interest on Short-term Debt . . . . . . . . . . . . 7,539 3,665 3,282 1,305 817
Miscellaneous Interest Charges. . . . . . . . . . . 2,361 2,663 3,158 4,036 4,566
Estimated Interest Element in Lease Rentals . . . . 4,900 5,600 4,100 3,700 3,700
Total Fixed Charges. . . . . . . . . . . . . . $103,257 $103,662 $97,836 $93,596 $87,775
Earnings:
Net Income. . . . . . . . . . . . . . . . . . . . . $ 96,000 $ 66,979 $ 76,244 $(55,898) $109,845
Plus Federal Income Taxes . . . . . . . . . . . . . 6,178 1,074 27,389 34,154 49,838
Plus State Income Taxes . . . . . . . . . . . . . . 2 1 - - 1
Plus Fixed Charges (as above) . . . . . . . . . . . 103,257 103,662 97,836 93,596 87,775
Total Earnings . . . . . . . . . . . . . . . . $205,437 $171,716 $201,469 $ 71,852 $247,459
Ratio of Earnings to Fixed Charges. . . . . . . . . . 1.98 1.65 2.05 0.76(a) 2.81
(a) Ratio includes the effect of the Loss from Zimmer Plant Disallowance of $144,533,000 (net of applicable
income taxes of $14,534,000). As a result, earnings for the twelve months ended December 31, 1993 were
inadequate to cover fixed charges by $21,744,000. If the effect of the Loss from Zimmer Plant Disallowance
were excluded, the ratio would be 2.46 for the twelve months ended December 31, 1993.
</TABLE>
<PAGE>
MANAGEMENT'S NARRATIVE ANALYSIS OF
RESULTS OF OPERATIONS
Net Income Increases
Net income increased by $166 million in 1994 due to the effect of a $144.5
million after tax loss recorded in 1993 as a result of a disallowance of a
portion of the Company's investment in its Zimmer Plant. Excluding the 1993
disallowance, net income would have increased by $21 million in 1994 due to
the favorable impact of increased retail energy sales reflecting unseasonable
weather in January and June 1994 and the refinancing of debt at lower
interest rates.
Operating Revenues Increase
Operating revenues for 1994 increased $77.5 million or 8.1%. The
components of the change in revenues were as follows:
Increase (Decrease)
(dollars in millions) From Previous Year
Amount %
Retail:
Price variance . . . . . . . . $66.6
Volume variance. . . . . . . . 6.0
Fuel Cost Recoveries . . . . . (2.0)
70.6 8.2
Wholesale:
Price variance . . . . . . . . 7.6
Volume variance. . . . . . . . (3.7)
3.9 5.2
Other Operating Revenues. . . . . 3.0
Total . . . . . . . . . . . . . $77.5 8.1
Retail revenues increased primarily due to a rate increase granted in
February 1994. The Public Utilities Commission of Ohio (PUCO) granted a
7.11% increase in rates effective February 1, 1994 as a result of a November
1993 Ohio Supreme Court ruling that the PUCO did not have authority under
state law to order a rate phase-in for the Zimmer Plant. The increase
includes a 3.72% base rate increase, which represents the acceleration of the
final step of the court rejected rate phase-in plan, and a 3.39% surcharge,
which provides for recovery of $96.9 million of previous deferrals under the
phase-in plan and a return thereon, to be collected until the deferrals are
recovered which is expected to be in 1998. The rate increase has no effect
on net income since it is offset by the amortization of prior year phase-in
plan deferrals and the cessation of current year deferrals which
would have occurred had the phase-in plan continued in effect.
Wholesale revenues increased 5.2% reflecting higher sales to the AEP
System Power Pool (Power Pool) due to increased availability of several
Conesville Plant generating units in 1994 compared with 1993 and an increase
in take-or-pay capacity charges to unaffiliated utilities. Capacity charges
are to reserve a specified quantity of generating capacity and are collected
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 the
short-term contract sale of capacity to unaffiliated utilities in the summer
of 1994 due to the forced outage of an unaffiliated generating unit.
However, the increase in capacity reservation did not have a corresponding
increase in energy sales 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 in those months, the mild weather
throughout the remainder of 1994 combined with increased competition in the
wholesale market reduced short-term sales for the year.
Operating Expenses Increase
Operating expenses increased $41.8 million or 5.2% in 1994. Changes in the
components of operating expenses were as follows:
Increase (Decrease)
(dollars in millions) From Previous Year
Amount %
Fuel. . . . . . . . . . . . . . . $ 17.4 9.3
Purchased Power . . . . . . . . . (25.4) (15.9)
Other Operation . . . . . . . . . 4.7 2.8
Maintenance . . . . . . . . . . . 0.1 0.1
Depreciation. . . . . . . . . . . (1.7) (2.0)
Amortization of Zimmer Plant
Phase-in Costs. . . . . . . . . 36.0 N.M.
Taxes Other Than Federal
Income Taxes. . . . . . . . . . 3.3 3.3
Federal Income Taxes. . . . . . . 7.4 18.7
Total Operating Expenses. . . . $41.8 5.2
The increase in fuel expense was due to an increase in net generation
reflecting the full availability in 1994 of three units that had been out of
service for scheduled maintenance in the second quarter of 1993.
Purchased power expense decreased due to the reduction in wholesale
energy demand caused by the cooler late summer weather and mild fall weather
as well as the increase in net generation.
The amortization of Zimmer Plant phase-in costs increased sharply due to
the court ordered discontinuance of Zimmer phase-in plan deferrals in
February 1994 and the subsequent amortization of the deferred costs,
commensurate with their recovery.
Federal income tax expense attributable to operations increased
primarily due to the increase in pre-tax operating income offset in part by
changes in certain book/tax differences accounted for on a flow-through basis
and adjustments associated with the audit of prior years' tax returns.
Deferred Zimmer Plant Carrying Charges
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.
Interest Expense Decreases
Interest expense declined due to the refinancing program throughout 1993
and in the first quarter of 1994 that refinanced $200 million of long-term
debt at lower interest rates and retired $19.7 million of long-term debt in
1994.
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Shareowners and Board of
Directors of Columbus Southern
Power Company:
We have audited the accompanying consolidated balance sheets of Columbus
Southern Power Company 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 Columbus Southern Power Company
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>
<CAPTION>
Consolidated Statements of Income
Year Ended December 31,
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
OPERATING REVENUES $1,031,151 $953,652 $843,996
OPERATING EXPENSES:
Fuel 204,210 186,761 188,077
Purchased Power 134,540 159,979 137,718
Other Operation 175,102 170,397 160,008
Maintenance 71,629 71,537 54,533
Depreciation 83,180 84,883 76,710
Amortization (Deferral) of Zimmer Plant
Phase-in Costs 27,144 (8,913) (9,346)
Taxes Other Than Federal Income Taxes 102,672 99,348 94,714
Federal Income Taxes 46,806 39,444 19,267
TOTAL OPERATING EXPENSES 845,283 803,436 721,681
OPERATING INCOME 185,868 150,216 122,315
NONOPERATING INCOME:
Deferred Zimmer Plant Carrying
Charges (net of tax) 5,604 25,343 41,901
Other 1,426 2,000 5,269
TOTAL NONOPERATING INCOME 7,030 27,343 47,170
Loss From Zimmer Plant Disallowance:
Disallowed Cost - 159,067 -
Related Income Taxes - (14,534) -
NET ZIMMER LOSS - 144,533 -
INCOME BEFORE INTEREST CHARGES 192,898 33,026 169,485
INTEREST CHARGES 83,053 88,924 93,241
NET INCOME (LOSS) 109,845 (55,898) 76,244
PREFERRED STOCK DIVIDEND REQUIREMENTS 12,084 11,062 10,220
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 97,761 $(66,960) $ 66,024
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Consolidated Balance Sheets
December 31,
1994 1993
(in thousands)
<S> <C> <C>
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,461,484 $1,443,506
Transmission 306,744 295,539
Distribution 797,570 755,342
General 111,623 97,874
Construction Work in Progress 52,156 52,794
Total Electric Utility Plant 2,729,577 2,645,055
Accumulated Depreciation 884,237 811,817
NET ELECTRIC UTILITY PLANT 1,845,340 1,833,238
OTHER PROPERTY AND INVESTMENTS 26,744 34,558
CURRENT ASSETS:
Cash and Cash Equivalents 14,065 6,633
Accounts Receivable:
Customers 41,056 42,906
Affiliated Companies 4,624 1,084
Miscellaneous 10,025 8,098
Allowance for Uncollectible Accounts (1,768) (991)
Fuel - at average cost 28,060 32,257
Materials and Supplies - at average cost 24,923 25,772
Accrued Utility Revenues 31,595 28,889
Prepayments 31,241 30,235
TOTAL CURRENT ASSETS 183,821 174,883
REGULATORY ASSETS 475,019 479,672
DEFERRED CHARGES 63,418 60,320
TOTAL $2,594,342 $2,582,671
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
December 31,
1994 1993
(in thousands)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares $ 41,026 $ 41,026
Paid-in Capital 565,642 566,046
Retained Earnings 46,976 18,288
Total Common Shareowner's Equity 653,644 625,360
Cumulative Preferred Stock -
Subject to Mandatory Redemption 150,000 125,000
Long-term Debt 917,608 997,013
TOTAL CAPITALIZATION 1,721,252 1,747,373
OTHER NONCURRENT LIABILITIES 25,861 17,189
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 80,000 20,700
Short-term Debt - 25,225
Accounts Payable - General 34,934 37,258
Accounts Payable - Affiliated Companies 14,057 13,289
Taxes Accrued 113,362 114,233
Interest Accrued 18,923 23,245
Other 37,521 22,189
TOTAL CURRENT LIABILITIES 298,797 256,139
DEFERRED FEDERAL INCOME TAXES 467,593 474,290
DEFERRED INVESTMENT TAX CREDITS 64,597 68,533
DEFERRED CREDITS 16,242 19,147
COMMITMENTS AND CONTINGENCIES (Note 3)
TOTAL $2,594,342 $2,582,671
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Consolidated Statements of Cash Flows
Year Ended December 31,
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net Income (Loss) $ 109,845 $ (55,898) $ 76,244
Adjustments for Noncash Items:
Depreciation 82,795 84,462 84,755
Deferred Federal Income Taxes (2,132) 10,167 36,908
Deferred Investment Tax Credits (3,929) (5,471) (4,787)
Deferred Fuel Costs (net) 2,247 3,659 (4,236)
Deferred Zimmer Plant Operating Expenses
and Carrying Charges 19,156 (46,475) (77,532)
Loss from Zimmer Plant Disallowance - 159,067 -
Changes in Certain Current Assets and
Liabilities:
Special Deposits - Restricted Funds - 1,293 17,612
Accounts Receivable (net) (2,840) (8,030) 3,540
Fuel, Materials and Supplies 5,046 1,428 6,091
Accrued Utility Revenues (2,706) (12,599) (4,586)
Accounts Payable (1,556) 3,336 (8,068)
Other (net) (11,382) (407) (2,056)
Net Cash Flows From Operating Activities 194,544 134,532 123,885
INVESTING ACTIVITIES:
Construction Expenditures (80,973) (88,605) (76,262)
Proceeds from Sale and Leaseback
Transactions and Other 2,606 2,659 -
Net Cash Flows Used For Investing Activities (78,367) (85,946) (76,262)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company - - 20,000
Issuance of Cumulative Preferred Stock 24,596 - 49,448
Issuance of Long-term Debt 198,298 197,722 251,046
Retirement of Long-term Debt (225,834) (166,166) (278,918)
Change in Short-term Debt (net) (25,225) (28,594) (12,381)
Dividends Paid on Common Stock (68,788) (42,175) (68,760)
Dividends Paid on Cumulative Preferred Stock (11,792) (11,062) (9,564)
Net Cash Flows Used For Financing Activities (108,745) (50,275) (49,129)
Net Increase (Decrease) in
Cash and Cash Equivalents 7,432 (1,689) (1,506)
Cash and Cash Equivalents January 1 6,633 8,322 9,828
Cash and Cash Equivalents December 31 $ 14,065 $ 6,633 $ 8,322
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Consolidated Statements of Retained Earnings
Year Ended December 31,
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Retained Earnings January 1 $ 18,288 $127,562 $130,765
Net Income (Loss) 109,845 (55,898) 76,244
128,133 71,664 207,009
Deductions:
Cash Dividends Declared:
Common Stock 68,788 42,175 68,760
Cumulative Preferred Stock:
7% Series 1,167 - -
7-7/8% Series 3,938 3,937 3,423
9.50% Series 7,125 7,125 7,125
Total Cash Dividends Declared 81,018 53,237 79,308
Other 139 139 139
Total Deductions 81,157 53,376 79,447
Retained Earnings December 31 $ 46,976 $ 18,288 $127,562
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Organization
Columbus Southern Power Company (the Company or CSPCo) is a wholly-owned
subsidiary of American Electric Power Company, Inc. (AEP Co., Inc.), a public
utility holding company. The Company is engaged in the generation, purchase,
transmission and distribution of electric power in central and southern Ohio.
As a member of the American Electric Power (AEP) System Power Pool (Power
Pool) and a signatory company to the AEP Transmission Equalization Agreement,
CSPCo's facilities are operated in conjunction with the facilities of certain
other AEP affiliated utilities as an integrated utility system.
The Company's three wholly-owned subsidiaries are: Conesville Coal Prepa-
ration Company (CCPC) which provides coal washing services for one of the
Company's generating stations; Simco Inc. which is engaged in leasing a coal
conveyor system to CCPC; and Colomet, Inc. which is engaged in real estate
activities for its parent.
Regulation
As a member of the AEP System, CSPCo is subject to the regulation of the
Securities and Exchange Commission (SEC) under the Public Utility Holding
Company Act of 1935 (1935 Act). Retail rates are regulated by the Public
Utilities Commission of Ohio (PUCO). The Federal Energy Regulatory
Commission (FERC) regulates wholesale rates.
Principles of Consolidation
The consolidated financial statements include CSPCo and its wholly-owned
subsidiaries. Significant intercompany items are eliminated in consol-
idation.
Basis of Accounting
As a cost-based rate-regulated entity, CSPCo's 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. Such deferrals are amortized commensurate with their
inclusion in rates (revenues).
Utility Plant
Electric utility plant is stated at original cost and is generally subject
to first mortgage liens. Additions, major replacements and betterments are
added to the plant accounts. Retirements from the plant accounts and
associated removal costs, net of salvage, are deducted from accumulated
depreciation.
The costs of labor, materials and overheads incurred to operate and
maintain utility plant are included in operating expenses.
Allowance for Funds Used During Construction (AFUDC)
AFUDC is a noncash nonoperating income item that is recovered with
regulator approval over the service life of utility plant through
depreciation and represents the estimated cost of borrowed and equity funds
used to finance construction projects. The average rates used to accrue
AFUDC were 7.25%, 4.75% and 3.75% in 1994, 1993 and 1992, respectively, and
the amounts of AFUDC accrued were $1.2 million in 1994 and 1993 and $0.5
million in 1992.
Depreciation
Depreciation is provided on a straight line basis over the estimated
useful lives of utility plant and is calculated largely through the use of
composite rates by functional class as follows:
Functional Class Composite
of Property Annual Rates
Production 3.2%
Transmission 2.3%
Distribution 3.7%
General 3.5%
Amounts to be used for removal of plant are recovered through depreciation
charges included in rates.
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
Changes in retail jurisdictional fuel cost are deferred until reflected in
revenues in later months through a PUCO fuel cost recovery mechanism.
Wholesale jurisdictional fuel cost changes are expensed and billed as
incurred.
Income Taxes
The Company follows the liability method of accounting for income taxes as
prescribed by SFAS 109, Accounting for Income Taxes. Under the liability
method, deferred income taxes are provided for all temporary differences
between book cost and tax basis of assets and liabilities which will result
in a future tax consequence. Where the flow-through method of accounting for
temporary differences is reflected in rates, regulatory assets and
liabilities are recorded in accordance with SFAS 71.
Investment Tax Credits
The Company's policy was to account for investment tax credits under the
flow-through method except where regulatory commissions reflected investment
tax credits in the rate-making process on a deferral basis. Commensurate
with rate treatment deferred investment tax credits are being amortized over
the life of the related plant investment.
Debt and Preferred Stock
Gains and losses on reacquired debt are deferred and amortized over the
remaining term of the reacquired debt in accordance with rate-making
treatment. If the debt is refinanced the reacquisition costs are deferred
and amortized over the term of the replacement debt commensurate with their
recovery in rates.
Debt discount or premium and debt issuance expenses are amortized over the
term of the related debt, with the amortization included in interest charges.
Redemption premiums paid to reacquire preferred stock are deferred and
amortized in accordance with rate-making treatment.
Other Property and Investments
Other property and investments are stated at cost.
Reclassifications
Certain prior-period amounts were reclassified to conform with current-
period presentation.
2. EFFECTS OF REGULATION AND THE ZIMMER PHASE-IN PLAN:
The consolidated financial statements include assets and liabilities
recorded in accordance with regulatory actions to match expenses and revenues
in cost-based rates. Regulatory assets are expected to be recovered in
future periods through the rate-making process and regulatory liabilities are
expected to reduce future rate recoveries. The Company's regulatory assets
and liabilities are comprised of the following:
December 31,
1994 1993
(in thousands)
Regulatory Assets:
Amounts Due From Customers For
Future Federal Income Taxes $286,079 $290,644
Zimmer Plant Phase-in Plan
Deferrals 75,394 93,907
Deferred Zimmer Plant
Carrying Charges 43,003 43,003
Unamortized Loss On
Reacquired Debt 34,839 31,632
Other 35,704 20,486
Total Regulatory Assets $475,019 $479,672
Regulatory Liabilities:
Deferred Investment Tax Credits $64,597 $68,533
Other Regulatory Liabilities* 13,123 16,357
Total Regulatory Liabilities $77,720 $84,890
* Included in Deferred Credits on the 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 for the new Zimmer Plant 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 revenues
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 deferred
revenues are recovered, estimated to be 1998. In 1994 $18.5 million of net
phase-in deferrals were collected through the surcharge. 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.
3. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Substantial construction commitments have been made. Such commitments do
not include any expenditures for new generating capacity. The aggregate con-
struction program expenditures for 1995-1997 are estimated to be $289
million.
Long-term fuel supply contracts contain clauses that provide for periodic
price adjustments. The PUCO has a fuel clause mechanism that provides for
deferral and subsequent recovery or refund of changes in the cost of fuel
with PUCO review and approval. The contracts are for various terms, the
longest of which extends to 2011, and contain various clauses that would
release the Company from its obligation under certain force majeure
conditions.
Clean Air
The Clean Air Act Amendments of 1990 (CAAA) require 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 on January 1, 1995 and the second, more restrictive phase
(Phase II) begins on January 1, 2000. The law also established a permanent
nationwide cap on sulfur dioxide emissions after 1999.
Under an AEP Systemwide Phase I compliance plan the Company will modify
Conesville Units 1 through 3 to allow use of either low sulfur coal or
natural gas at an estimated capital cost of $30 million. Also the compliance
plan calls for switching to moderate-sulfur coal at Beckjord Unit 6 (a unit
jointly owned with two unaffiliated utilities) with no additional capital
cost. Although Conesville Unit 4 is an affected Phase I unit, it does not
require operating or fuel changes under the compliance plan since the plan
provides for under-compliance at Conesville 4 to be offset by over-compliance
at other AEP System units. The Company's other generating units are not
affected in Phase I.
The Company will incur a portion of the Phase I compliance costs of other
AEP affiliates through the Power Pool (which is described in Note 5). The
compliance plan for the AEP System's generating units affected by Phase I
includes installation of flue gas desulfurization systems (scrubbers) at the
two-unit 2,600 mw Gavin Plant owned by an affiliate, Ohio Power Company and
fuel switching at other affected affiliated plants. The Company will incur
additional costs to comply with Phase II requirements at its generating
plants and those of affiliated Power Pool members. If the Company is unable
to recover its compliance cost from customers, results of operations would be
adversely impacted.
Other Environmental Matters
The Company and its subsidiaries are 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 the Company's past disposal of hazardous
and non-hazardous materials.
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.
4. RELATED PARTY TRANSACTIONS:
Benefits and costs of the System's generating plants are shared by members
of the Power Pool. Under the terms of the System Interconnection Agreement,
capacity charges and credits are designed to allocate the cost of the
System's capacity among the Power Pool members based on their relative peak
demands and generating reserves. Power Pool members are also compensated for
the out-of-pocket costs of energy delivered to the Power Pool and charged for
energy received from the Power Pool.
Operating revenues include $15.8 million in 1994, $12.5 million in 1993
and $13 million in 1992 for energy suppled to the Power Pool.
Charges for Power Pool capacity reservation and energy received were
included in purchased power expense as follows:
Year Ended December 31,
1994 1993 1992
(in thousands)
Capacity Charges $ 74,936 $ 85,450 $ 81,727
Energy Charges 46,164 68,277 48,966
Total $121,100 $153,727 $130,693
Power Pool members share in wholesale sales to unaffiliated utilities made
by the Power Pool. The Company's share of the Power Pool's wholesale sales
included in operating revenues were $48.7 million in 1994, $49.3 million in
1993 and $40 million in 1992.
In addition, the Power Pool purchases power from unaffiliated companies
for immediate resale to other unaffiliated utilities. The Company's share of
these purchases was included in purchased power expense and totaled $13.4
million in 1994, $6.2 million in 1993 and $7 million in 1992. Revenues from
these transactions are included in the above Power Pool wholesale operating
revenues.
AEP System companies participate in a transmission equalization agreement.
This agreement combines certain AEP System companies' investments in
transmission facilities and shares the costs of ownership in proportion to
the System companies' respective peak demands. Pursuant to the terms of the
agreement, other operation expense includes equalization charges of $30.1
million, $31.2 million and $29.9 million in 1994, 1993 and 1992, respective-
ly.
American Electric Power Service Corporation (AEPSC) provides certain
managerial and professional services to AEP System companies. The costs of
the services are billed by AEPSC on a direct-charge basis to the extent
practicable and on reasonable bases of proration for indirect costs. The
charges for services are made at cost and include no compensation for the use
of equity capital, which is furnished to AEPSC by AEP Co., Inc. Billings
from AEPSC are capitalized or expensed depending on the nature of the
services rendered. AEPSC and its billings are subject to the regulation of
the SEC under the 1935 Act.
5. BENEFIT PLANS:
The Company and its subsidiaries participate in the AEP System pension
plan, a trusteed, noncontributory defined benefit plan covering all employees
meeting eligibility requirements. Benefits are based on service years and
compensation levels. Pension costs are allocated by first charging each
System company with its service cost and then allocating the remaining
pension cost in proportion to its share of the projected benefit obligation.
The funding policy is to make annual trust fund contributions equal to the
net periodic pension cost up to the maximum amount deductible for federal
income taxes, but not less than the minimum contribution required by with the
Employee Retirement Income Security Act of 1974.
Net pension costs for the years ended December 31, 1994, 1993 and 1992
were $2.2 million, $2.5 million and $3.9 million, respectively.
An employee savings plan is offered which allows participants to
contribute up to 17% of their salaries into three investment alternatives,
including AEP Co., Inc. common stock. An employer matching contribution,
equaling one-half of the employees' contribution to the plan up to a maximum
of 3% of the employees' base salary, is invested in AEP common stock. The
employer's annual contributions totaled $2.1 million in 1994 and $1.9 million
in both 1993 and 1992.
Certain other benefits are provided for retired employees under an AEP
System other postretirement benefit plan. Substantially all employees are
eligible for 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 $1.9 million in
1992.
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 during the employee's service years of the present value
liability for OPEB costs. 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. OPEB costs are deter-
mined by the application of AEP System actuarial assumptions to each operat-
ing company's employee complement. The annual accrued costs for employees
and retirees OPEBs required by SFAS 106, which includes the recognition of
one-twentieth of the prior service transition obligation, were $10.4 million
in 1994 and $9.7 million in 1993.
The Company received approval from the PUCO and FERC to defer under
certain conditions the increased OPEB costs not being currently recovered in
rates. In the FERC jurisdiction future recovery of the deferrals and the
annual ongoing OPEB costs will be sought in the next base rate filing. In
the retail jurisdiction the Company had sufficient earnings in 1994 to absorb
the increased OPEB cost over the pay-as-you-go cost. At December 31, 1994
and 1993, the total OPEB deferred costs were $2.7 million and $3.6 million,
respectively.
A Voluntary Employees Beneficiary Association (VEBA) trust fund for OPEB
benefits was established and a corporate owned life insurance (COLI) program
was implemented. The insurance policies have a substantial cash surrender
value which is recorded, net of equally substantial policy loans, as other
property and investments. In 1995 the Company will contribute an amount to
the VEBA trust fund equal to the difference between the pay-as-you-go OPEB
cost and SFAS 106 total OPEB cost for 1994 and 1995. This contribution will
be funded by amounts collected from ratepayers plus net earnings from the
COLI program.
<PAGE>
6. COMMON OWNERSHIP OF GENERATING AND TRANSMISSION FACILITIES:
The Company jointly owns, as tenants in common, four generating units and
transmission facilities with two unaffiliated companies. Each of the
participating companies is obligated to pay its share of the costs of any
such jointly owned facilities in the same proportion as its ownership
interest. The Company's proportionate share of the operating costs
associated with such facilities is included in the Consolidated Statements of
Income and the amounts reflected in the accompanying Consolidated Balance
Sheets under utility plant include such costs as follows:
<TABLE>
<CAPTION>
Company's Share
December 31,
1994 1993
Percent Utility Construction Utility Construction
of Plant Work Plant Work
Ownership in Service in Progress in Service in Progress
(in thousands)
<S> <C> <C> <C> <C> <C>
Production:
W.C. Beckjord Generating Station (Unit No. 6) 12.5 $ 12,625 $1,137 $ 12,518 $ 141
Conesville Generating Station (Unit No. 4) 43.5 78,831 420 77,527 371
J.M. Stuart Generating Station 26.0 175,195 3,209 168,419 6,979
Wm. H. Zimmer Generating Station 25.4 695,990 1,797 695,121 1,210
$962,641 $6,563 $953,585 $8,701
Transmission (a) $ 58,813 $ 161 $ 58,730 $ 6
(a) Varying percentage of ownership.
</TABLE>
At December 31, 1994 and 1993, the accumulated depreciation with respect
to the Company's share of jointly owned facilities amounted to $218.2 million
and $189.4 million, respectively.
<PAGE>
7. CUMULATIVE PREFERRED STOCK:
At December 31, 1994, authorized shares of cumulative preferred stock were
as follows:
Par Value Shares Authorized
$100 2,500,000
25 7,000,000
The cumulative preferred stock outstanding shown below is subject to
mandatory redemption and has an involuntary liquidation preference of par
value.
<TABLE>
<CAPTION>
Call Price Shares Amount
December 31, Par Outstanding December 31,
Series (a) 1994 Value December 31, 1994 1994 1993
(in thousands)
<S> <C> <C> <C> <C> <C>
7% (b) (b) $100 250,000 $ 25,000 $ -
7-7/8% (c) $107.88 100 500,000 50,000 50,000
9.50% (d) $109.50 100 750,000 75,000 75,000
$150,000 $125,000
</TABLE>
(a) The sinking fund provisions of series subject to mandatory redemption
aggregate $3,750,000 in both 1996 and 1997 and $6,250,000 in both 1998 and
1999. There are no sinking fund provisions for 1995.
(b) Shares issued June 1994. Commencing in 2000, a sinking fund will require
the redemption of 50,000 shares at $100 a share on or before August 1 of each
year. The Company has the right, on each sinking fund date, to redeem an
additional 50,000 shares. Redemption of this series is prohibited prior to
August 1, 2000.
(c) Shares issued March 1992. Commencing in 1998, a sinking fund will
require the redemption of 25,000 shares at $100 a share on or before May 1 of
each year. The Company has the right, on each sinking fund date, to redeem
an additional 25,000 shares. Redemption of this series is restricted prior
to March 1, 1997.
(d) Commencing in 1996, a sinking fund will require the redemption of 37,500
shares at $100 a share on or before February 1 of each year. The Company has
the right, on each sinking fund date, to redeem an additional 37,500 shares.
Redemption of this series is restricted prior to November 1, 1995.
<PAGE>
8. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Charged (Credited) to Operating Expenses (net):
Current $56,424 $ 34,235 $ (619)
Deferred (5,916) 8,935 24,386
Deferred Investment Tax Credits (3,702) (3,726) (4,500)
Total 46,806 39,444 19,267
Charged (Credited) to Nonoperating Income (net):
Current (525) (4,777) (4,113)
Deferred 3,784 14,559 12,522
Deferred Investment Tax Credits (227) (538) (287)
Total 3,032 9,244 8,122
Credited to Loss from Zimmer Disallowance (net):
Deferred - (13,327) -
Deferred Investment Tax Credits - (1,207) -
Total - (14,534) -
Total Federal Income Taxes as Reported $49,838 $ 34,154 $27,389
</TABLE>
The following is a reconciliation of the difference between the amount of
federal income taxes computed by multiplying book income before federal
income taxes by the statutory tax rate, and the amount of federal income
taxes reported.
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Net Income (Loss) $109,845 $(55,898) $ 76,244
Federal Income Taxes 49,838 34,154 27,389
Pre-tax Book Income (Loss) $159,683 $(21,744) $103,633
Federal Income Taxes on Pre-tax Book Income (Loss) at
Statutory Rate (35% in 1994 and 1993; 34% in 1992) $55,889 $(7,610) $35,235
Increase (Decrease) in Federal Income Taxes
Resulting From the Following Items:
Deferred Zimmer Plant Carrying Charges 3 928 (6,021)
Corporate Owned Life Insurance (2,787) (3,351) (2,702)
Depreciation 7,335 8,604 7,773
Zimmer Plant Disallowance - 42,346 -
Federal Income Tax Accrual Adjustments (3,300) - -
Amortization/Reversal of Deferred Investment
Tax Credits (net) (3,929) (5,468) (3,760)
Other (3,373) (1,295) (3,136)
Total Federal Income Taxes as Reported $49,838 $34,154 $27,389
Effective Federal Income Tax Rate 31.2% N/A 26.4%
</TABLE>
<PAGE>
The following tables show the elements of the net deferred tax liability
and the significant temporary differences that gave rise to it:
December 31,
1994 1993
(in thousands)
Deferred Tax Assets $ 74,752 $ 75,687
Deferred Tax Liabilities (542,345) (549,977)
Net Deferred Tax Liabilities $(467,593) $(474,290)
Property Related Temporary
Differences $(330,434) $(322,299)
Amounts Due From Customers For
Future Federal Income Taxes (100,128) (101,725)
Deferred Return - Zimmer Plant (21,546) (26,477)
All Other (net) (15,485) (23,789)
Total Net Deferred
Tax Liabilities $(467,593) $(474,290)
The Company and its subsidiaries join in the filing of a consolidated
federal income tax return with their affiliates in the AEP System. The
allocation of the AEP System's current consolidated federal income tax to the
System companies is in accordance with SEC rules under the 1935 Act. These
rules permit the allocation of the benefit of current tax losses to the
System companies giving rise to them in determining their current tax
expense. The tax loss of the System parent company, AEP, is allocated to its
subsidiaries with taxable income. With the exception of the loss of the
parent company, the method of allocation approximates a separate return
result for each company in the consolidated group.
The AEP System has settled with the Internal Revenue Service (IRS) all
issues from the audits of the consolidated federal income tax returns for the
years prior to 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.
9. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1994 1993 1992
(in thousands)
Cash was paid (received)
for:
Interest (net of
capitalized amounts) $83,251 $88,141 $93,428
Income Taxes 59,218 35,514 (7,643)
Noncash Acquisitions under
Capital Leases were 14,899 8,672 4,017
<PAGE>
10. LEASES:
Leases of property, plant and equipment are for periods up to 31 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 rental costs are as follows:
Year Ended December 31,
1994 1993 1992
(in thousands)
Operating Leases $ 7,850 $ 8,873 $10,342
Amortization of Capital
Leases 4,050 3,032 2,289
Interest on Capital Leases 1,092 763 644
Total Rental Costs $12,992 $12,668 $13,275
Properties under capital leases and
related obligations recorded on the
Consolidated Balance Sheets are as follows:
December 31,
1994 1993
(in thousands)
Electric Utility Plant:
Production $ 1,952 $ 1,952
Transmission 4 330
General 33,415 21,093
Total Electric Utility Plant 35,371 23,375
Other Property 1,167 2,548
Total Properties 36,538 25,923
Accumulated Amortization 12,086 10,686
Net Properties under Capital Leases $24,452 $15,237
Obligations under Capital Leases:
Noncurrent Liability $19,562 $12,162
Liability Due Within One Year 4,890 3,075
Total Capital Lease Obligations $24,452 $15,237
Properties under operating leases and
related obligations are not included in the
Consolidated Balance Sheets.
<PAGE>
Future minimum lease payments consisted of
the following at December 31, 1994:
Non-
cancelable
Capital Operating
Leases Leases
(in thousands)
1995 $ 6,127 $ 5,949
1996 4,826 5,889
1997 3,973 5,625
1998 3,310 5,392
1999 2,787 5,045
Later Years 8,089 16,362
Total Future Minimum Lease Payments 29,112 $44,262
Less Estimated Interest Element 4,660
Estimated Present Value of
Future Minimum Lease Payments $24,452
11. COMMON SHAREOWNER'S EQUITY:
The Company received from AEP Co., Inc. a cash capital contribution of $20
million in 1992 which was credited to paid-in capital. In 1994 charges to
paid-in capital of $404,000 represented issuance expenses of cumulative
preferred stock. There were no other material transactions affecting the
common stock and paid-in capital accounts in 1994, 1993 and 1992.
12. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1994 1993
(in thousands)
First Mortgage Bonds $856,767 $ 876,926
Installment Purchase Contracts 90,841 90,787
Notes Payable due 1995 50,000 50,000
997,608 1,017,713
Less Portion Due Within One Year 80,000 20,700
Total $917,608 $ 997,013 <PAGE>
First mortgage bonds outstanding were as follows:
December 31,
1994 1993
(in thousands)
% Rate Due
8.95 1995 - December 20 $ 30,000 $ 30,000
8-5/8 1996 - February 1 - 100,000
6-1/4 1997 - October 1 14,640 14,640
9.15 1998 - February 2 57,000 57,000
7 1998 - June 1 24,750 24,750
9 1999 - December 1 - 19,700
9.31 2001 - August 1 30,000 30,000
7.95 2002 - July 1 40,000 40,000
7.25 2002 - October 1 75,000 75,000
7.15 2002 - November 1 20,000 20,000
6.80 2003 - May 1 50,000 50,000
6.60 2003 - August 1 40,000 40,000
6.10 2003 - November 1 20,000 20,000
6.55 2004 - March 1 50,000 -
6.75 2004 - May 1 50,000 -
9 2017 - March 1 - 100,000
9.625 2021 - June 1 50,000 50,000
8.70 2022 - July 1 35,000 35,000
8.40 2022 - August 1 15,000 15,000
8.55 2022 - August 1 15,000 15,000
8.40 2022 - August 15 40,000 40,000
8.40 2022 - October 15 15,000 15,000
7.90 2023 - May 1 50,000 50,000
7.75 2023 - August 1 40,000 40,000
7.45 2024 - March 1 50,000 -
7.60 2024 - May 1 50,000 -
Unamortized Discount (net) (4,623) (4,164)
856,767 876,926
Less Portion Due Within One year 30,000 20,700
Total $826,767 $856,226
Certain indentures relating to the first
mortgage bonds contain improvement, maintenance
and replacement provisions requiring the
deposit of cash or bonds with the trustee, or
in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into
in connection with the issuance of pollution control
revenue bonds by the Ohio Air Quality Development
Authority as follows:
December 31,
1994 1993
(in thousands)
% Rate Due
6-3/8 2020 - December 1 $48,550 $48,550
6-1/4 2020 - December 1 43,695 43,695
Unamortized Discount (1,404) (1,458)
Total $90,841 $90,787
<PAGE>
Under the terms of the installment purchase contracts, the Company is
required to pay amounts sufficient to enable the payment of interest on and
the principal of related pollution control revenue bonds issued to finance
the Company's share of construction of pollution control facilities at the
Zimmer Plant.
The notes payable due April 24, 1995 were issued under a term loan
agreement in 1991 and bear interest at a fixed rate of 8.79% until maturity.
At December 31, 1994 annual long-term debt payments, excluding premium or
discount, are as follows:
Principal Amount
(in thousands)
1995 $ 80,000
1996 -
1997 14,640
1998 81,750
1999 -
Later Years 827,245
Total $1,003,635
Short-term debt borrowings are limited by provisions of the 1935 Act to
$200 million and further limited by provisions of the notes payable to $163
million. Lines of credit are shared with AEP System companies and at
December 31, 1994 and 1993 were available in the amounts of $518 million and
$512 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. At December 31, 1993 outstanding short-term
debt consisted of $12.5 million of notes payable and $12.7 million of
commercial paper with weighted average interest rates of 3.6% and 3.8%,
respectively.
13. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The carrying amounts of cash and cash equivalents, accounts receivable,
short-term debt and accounts payable approximate fair value because of the
short-term maturity of these instruments. At December 31, 1994 and 1993 fair
values for preferred stock subject to mandatory redemption were $153 million
and $138 million, and for long-term debt were $921 million and $1,076
million, respectively. The carrying amounts for preferred stock subject to
mandatory redemption were $150 million and $125 million, and for long-term
debt were $998 million and $1,018 million 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 instru-
ments of the same remaining maturities.
14. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
1994
March 31 $255,829 $43,468 $24,652
June 30 256,754 44,523 25,242
September 30 280,470 61,597 42,528
December 31 238,098 36,280 17,423 (a)
(a) Includes favorable federal income tax adjustments of $3.3 million related
to the resolution of various issues with the IRS.
(b) Includes loss from Zimmer Disallowance as discussed in Note 2.
Quarterly Periods Operating Operating Net
Ended Revenues Income Income (Loss)
1993
March 31 $219,875 $29,960 $ 18,230
June 30 219,820 33,136 18,650
September 30 276,438 50,795 (110,257)(b)
December 31 237,519 36,325 17,479
<PAGE>
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration
Statement No. 33-50447 of Columbus Southern Power Company 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
Columbus Southern Power Company 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
COLUMBUS SOUTHERN POWER COMPANY
Annual Report on Form lO-K for the Fiscal Year Ended
December 31, 1994
The undersigned directors of COLUMBUS SOUTHERN POWER
COMPANY, an Ohio corporation (the "Company"), do hereby consti-
tute 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/ Wm. J. Lhota
P. J. DeMaria Wm. J. Lhota
/s/ E. Linn Draper, Jr. /s/ G. P. Maloney
E. Linn Draper, Jr. G. P. Maloney
/s/ Carl A. Erikson /s/ James J. Markowsky
Carl A. Erikson James J. Markowsky
/s/ Henry W. Fayne
Henry W. Fayne
/PAGE
<PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000022198
<NAME> COLUMBUS SOUTHERN POWER COMPANY
<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> 1,845,340
<OTHER-PROPERTY-AND-INVEST> 26,744
<TOTAL-CURRENT-ASSETS> 183,821
<TOTAL-DEFERRED-CHARGES> 63,418
<OTHER-ASSETS> 475,019
<TOTAL-ASSETS> 2,594,342
<COMMON> 41,026
<CAPITAL-SURPLUS-PAID-IN> 565,642
<RETAINED-EARNINGS> 46,976
<TOTAL-COMMON-STOCKHOLDERS-EQ> 653,644
150,000
0
<LONG-TERM-DEBT-NET> 917,608
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 80,000
0
<CAPITAL-LEASE-OBLIGATIONS> 19,562
<LEASES-CURRENT> 4,890
<OTHER-ITEMS-CAPITAL-AND-LIAB> 768,638
<TOT-CAPITALIZATION-AND-LIAB> 2,594,342
<GROSS-OPERATING-REVENUE> 1,031,151
<INCOME-TAX-EXPENSE> 46,807
<OTHER-OPERATING-EXPENSES> 798,476
<TOTAL-OPERATING-EXPENSES> 845,283
<OPERATING-INCOME-LOSS> 185,868
<OTHER-INCOME-NET> 7,030
<INCOME-BEFORE-INTEREST-EXPEN> 192,898
<TOTAL-INTEREST-EXPENSE> 83,053
<NET-INCOME> 109,845
12,084
<EARNINGS-AVAILABLE-FOR-COMM> 97,761
<COMMON-STOCK-DIVIDENDS> 68,788
<TOTAL-INTEREST-ON-BONDS> 68,471
<CASH-FLOW-OPERATIONS> 194,544
<EPS-PRIMARY> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1> All common stock owned by parent company; no EPS required.
</FN>
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