<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
OHIO POWER COMPANY
BY THE BOARD OF STOCKHOLDERS
The undersigned Vice President and Assistant Secretary of
Ohio Power Company, an Ohio corporation (the "Company"), with its
principal office located at Canton, Ohio, do hereby certify that
a meeting of shareholders of the Company entitled to vote on an
amendment to the Amended Articles of Incorporation of the Company
(the "Stockholders") was duly called for the purpose of adopting
this amendment and held on the third day of May, 1994, at which
meeting a quorum of the Stockholders was present in person or by
proxy, and by the affirmative vote of the holders of shares
entitling them to exercise more than two-thirds of the voting
power of the Company the following resolution to amend the
Amended Articles of Incorporation was adopted under authority of
subdivision (A) of Section 1701.71 of the Ohio Revised Code:
RESOLVED, that the Amended Articles of Incorporation of
Ohio Power Company, dated and filed in the office of the
Secretary of State of the State of Ohio on March 7, 1977,
subsequently as amended, be further amended by deleting the
first sentence of present Article FOURTH and substituting in
lieu thereof the following sentence:
The maximum number of shares of stock which the
Corporation is authorized to have outstanding is
forty-seven million seven hundred sixty-two
thousand four hundred three (47,762,403) shares,
divided into four classes as follows: (a) one
million seven hundred twelve thousand four hundred
three (1,712,403) shares are Cumulative Preferred
Stock of the par value of One Hundred Dollars
($100) each (hereinafter sometimes referred to as
"Cumulative Preferred Stock ($100 voting)"); (b)
two million fifty thousand (2,050,000) shares are
Cumulative Preferred Stock, $100 Non-Voting of the
par value of One Hundred Dollars ($100) each
(hereinafter sometimes referred to as "Cumulative
Preferred Stock ($100 non-voting)"); (c) four
million (4,000,000) shares are Cumulative Pre-
ferred Stock, $25 Non-Voting of the par value of
Twenty-five Dollars ($25) each (hereinafter
sometimes referred to as "Cumulative Preferred
Stock ($25 non-voting)"); and (d) forty million
(40,000,000) shares are Common Stock without par
value.
IN WITNESS WHEREOF, the undersigned Vice President and
Assistant Secretary of Ohio Power Company, acting for and on
behalf of said corporation, have hereunto subscribed their names
this 3rd day of May, 1994.
OHIO POWER COMPANY
By:__/s/ G. P. Maloney______
Vice President
By:__/s/ Jeffrey D. Cross___
Assistant Secretary
</PAGE>
<PAGE>
Exhibit 3(c)
[COMPOSITE]
AMENDED ARTICLES OF INCORPORATION
OF
OHIO POWER COMPANY
OHIO POWER COMPANY, a corporation for profit, heretofore
organized and now existing under the laws of the State of Ohio,
makes and files these Amended Articles of Incorporation and
states:
FIRST: The name of the Corporation shall be Ohio
Power Company.
SECOND: The place in Ohio where the principal office
of the Corporation is to be located is 301 Cleveland Avenue,
S.W., Canton, Ohio.
THIRD: The purposes for which the Corporation is
formed are:
To produce, buy, acquire, lease, use, furnish,
supply, sell, transmit, and distribute light, heat and power
generated by means of gas, electricity, steam, hot water or
other sources of energy, or any or all of them, for public
and private use, and in connection therewith to acquire,
purchase, own, construct, use, sell, lease, operate or
manage any works, plants, constructions or parts thereof for
the production, use, transmission, distribution, regulation,
control or application of gas, electricity, steam, hot water
or other sources of energy and to do any and all things
necessary or convenient in the exercise of such powers;
To acquire, buy, hold, own, sell, lease, exchange,
dispose of, finance, deal in, construct, build, equip,
improve, use, operate, maintain and work upon:
(a) Any and all kinds of plants and systems for
the manufacture, production, storage, utilization,
purchase, sale, supply, transmission, distribution, or
disposition of electricity, gas, water or steam, or
power produced thereby, or of ice and refrigeration of
any and every kind;
(b) Any and all kinds of telephone, telegraph,
radio, wireless and other systems, facilities and
devices for the receipt and trans-mission of sounds and
signals, any and all kinds of interurban, city and
street railways and railroads and bus lines for the<PAGE>
transportation of passengers and/or freight,
transmission lines, systems, appliances, equipment and
devices and tracks, stations, buildings and other
structures and facilities;
(c) Any and all kinds of works, power plants,
manufacture, structures, substations, systems, tracks,
machinery, generators, motors, lamps, poles, pipes,
wires, cables, conduits, apparatus, devices, equipment,
supplies, articles and merchandise of every kind
pertaining to or in anywise connected with the
construction, operation or maintenance of telephone,
telegraph, radio, wireless and other systems,
facilities and devices for the receipt and transmission
of sounds and signals, or of interurban, city and
street railways and railroads and bus lines, or in
anywise connected with or pertaining to the
manufacture, production, purchase, use, sale, supply,
transmission, distribution, regulation, control or
application of electricity, gas, water, steam, ice,
refrigeration and power or any other purposes;
To acquire, buy, hold, own, sell, lease, exchange,
dispose of, transmit, distribute, deal in, use, manufacture,
produce, furnish and supply street and interurban railway
and bus service, electricity, gas, light, heat, ice,
refrigeration, water and steam in any form and for any
purposes whatsoever, and any power or force or energy in any
form and for any purposes whatsoever;
To maintain and operate stores and commissaries
for the buying and selling of and to buy, sell and generally
deal in general merchandise, hardware, special merchandise,
machinery, supplies and any and all kinds of manufactured
and agricultural products;
To do a general mercantile business;
To acquire, organize, assemble, develop, build up
and operate constructing and operating and other
organizations and systems, and to hire, sell, lease,
exchange, turn over, deliver and dispose of such
organizations and systems in whole or in part and as going
organizations and systems and otherwise, and to enter into
and perform contracts, agreements and undertakings of any
kind in connection with any or all of the foregoing powers;
To do a general contracting business;
To purchase, acquire, develop, mine, explore,
drill, hold, own and dispose of lands, interests in and
2<PAGE>
rights with respect to lands and waters and fixed and
movable property;
To borrow money and contract debts when necessary
for the transaction of the business of the Corporation or
for the exercise of its corporate rights, privileges or
franchises or for any other lawful purpose of its
incorporation; to issue bonds, promissory notes, bills of
exchange, debentures and other obligations and evidences of
indebtedness payable at a specified time or times or payable
upon the happening of a specified event or events, whether
secured by mortgage, pledge or otherwise, or unsecured, for
money borrowed or in payment for property purchased or
acquired or any other lawful objects;
To guarantee, purchase, hold, sell, assign,
transfer, mortgage, pledge or otherwise dispose of the
shares of the capital stock of, or any bonds, securities or
evidences of indebtedness created by, any other corporation
or corporations of the State of Ohio or any other state or
government and, while the owner of such stock, to exercise
all the rights, powers and privileges of ownership,
including the right to vote thereon;
To aid in any manner any corporation or
association, domestic or foreign or any firm or individual,
any shares of stock in which or any bonds, debentures,
notes, securities, evidences of indebtedness, contracts, or
obligations of which are held by or for the Corporation or
in which or in the welfare of which the Corporation shall
have any interest, and to do any acts designed to protect,
preserve, improve or enhance the value of any property at
any time held or controlled by the Corporation, or in which
it may be at any time interested; and to organize or promote
or facilitate the organization of subsidiary companies;
To conduct business at one or more offices and
hold, purchase, mortgage and convey real and personal
property in the State of Ohio and in any of the several
states, territories, possessions and dependencies of the
United States, the District of Columbia and foreign
countries;
In any manner to acquire, enjoy, utilize and to
dispose of patents, copyrights and trademarks and any
licenses or other rights or interests therein and
thereunder;
To purchase, acquire, hold, own and dispose of
franchises, concessions, consents, privileges and licenses
necessary for and in its opinion useful or desirable for or
in connection with the foregoing powers;
3<PAGE>
To do any or all things herein set forth to the
same extent and as fully as natural persons might or could
do, in any part of the world, and as principal agent,
contractor, or otherwise, and either alone or in conjunction
with any other individuals, firms, associations,
corporations, syndicates or bodies politic;
To do any and all things necessary and proper for
the accomplishment of the objects herein enumerated or
necessary or incidental to the protection and benefit of the
Corporation, and in general to carry on any lawful business
necessary or incidental to the attainment of the purposes of
the Corporation, whether such business is similar in nature
to the objects and powers set forth in these Articles or any
amendment thereof;
To conduct its business in the State of Ohio,
other states, the District of Columbia, the territories,
colonies and possessions of the United States and in foreign
countries.
The Corporation may not construct a steam or
electric railroad in more than one County or State.
The objects and purposes specified in the
foregoing clauses of this Article Third shall, except where
other-wise expressed, be in no way limited or restricted by
reference to or inference from the terms of any other clause
of this or any other Article of these Articles. The objects
and purposes specified in each of the clauses of these
Articles shall be regarded as independent objects and
purposes and shall be construed as powers as well as objects
and purposes.
FOURTH: The maximum number of shares of stock which
the Corporation is authorized to have outstanding is forty-
seven million seven hundred sixty-two thousand four hundred
three (47,762,403) shares, divided into four classes as
follows: (a) one million seven hundred twelve thousand four
hundred three (1,712,403) shares are Cumulative Preferred
Stock of the par value of One Hundred Dollars ($100) each
(hereinafter sometimes referred to as "Cumulative Preferred
Stock ($100 voting)"); (b) two million fifty thousand
(2,050,000) shares are Cumulative Preferred Stock, $100 Non-
Voting of the par value of One Hundred Dollars ($100) each
(hereinafter sometimes referred to as "Cumulative Preferred
Stock ($100 non-voting)"); (c) four million (4,000,000)
shares are Cumulative Preferred Stock, $25 Non-Voting of the
par value of Twenty-five Dollars ($25) each (hereinafter
sometimes referred to as "Cumulative Preferred Stock ($25
non-voting)"); and (d) forty million (40,000,000) shares are
Common Stock without par value. The description of the
4<PAGE>
different classes of stock and the express terms of each of
such classes of stock and of the existing series of
Cumulative Preferred Stock are set forth in the following
paragraphs of this Article Fourth. All of the express terms
set forth below in the preamble and paragraphs (1) through
(10) under the heading "Cumulative Preferred Stock" shall be
equally applicable to the Cumulative Preferred Stock ($100
voting), to the Cumulative Preferred Stock ($100 non-voting)
and to the Cumulative Preferred Stock ($25 non-voting), and
such terms shall be deemed to state the express terms of all
shares of each of said classes, except to the extent that
any of such terms are expressly stated to be applicable only
to shares of one class or shares of one or more series of a
class, and whenever herein the words "Cumulative Preferred
Stock" without any prefix or parenthetical qualification
shall be used, they shall be deemed to refer to each of said
classes.
CUMULATIVE PREFERRED STOCK
Subject to and in accordance with the provisions of the
following paragraphs (1) through (34) hereof, the Board of
Directors is hereby authorized to cause shares of each class
of Cumulative Preferred Stock to be issued in series with
such variations in respect thereof (except in the case of
the shares of the series of Cumulative Preferred Stock ($100
voting) the express terms of which are set forth in
paragraphs (11) through (34) hereof) as may be determined by
an amendment to these Articles adopted by the Board of
Directors prior to the issue thereof:
(1) The shares of the Cumulative Preferred Stock
of each series of a class may vary as to:
(a) The distinctive series designations and
number of shares of such series;
(b) The rate of dividends (within such
limits as shall be permitted by law) payable on
the shares of the particular series;
(c) The dates from which such dividends
shall be cumulative as hereinafter in paragraph
(2) provided;
(d) The prices (not less than the amount
limited by law) and terms upon which the shares of
the particular series may be redeemed;
(e) The amount or amounts which shall be
paid to the holders of the shares of the
particular series in case of voluntary or
5<PAGE>
involuntary dissolution or any distribution of
assets;
(f) The sinking fund requirements (if any)
for the purchase or redemption of the shares of
the particular series;
(g) The rights (if any) to convert the
shares of the particular series into and/or
purchase stock of any other series or class or
other securities.
Except for the variations permitted in this paragraph,
the shares of all series of each class of the
Cumulative Preferred Stock shall in all other respects
be identical.
(2) The holders of each series of the Cumulative
Preferred Stock at the time outstanding shall be
entitled to receive, but only when and as declared by
the Board of Directors, out of funds legally available
for the payment of dividends, cumulative preferential
dividends, at the annual dividend rate for the
particular series fixed therefor as herein provided,
payable quarter-yearly on the first days of March,
June, September and December in each year, to
stockholders of record on the respective dates, not
exceeding thirty (30) days and not less than ten (10)
days preceding such dividend payment dates, fixed for
the purpose by the Board of Directors. No dividends
shall be declared on any series of the Cumulative
Preferred Stock in respect of any quarter-yearly
dividend period unless there shall likewise be declared
on all shares of all series of the Cumulative Preferred
Stock at the time outstanding, like proportionate
dividends, ratably, in proportion to the respective
annual dividend rates fixed therefor, in respect of the
same quarter-yearly dividend period, to the extent that
such shares are entitled to receive dividends for such
quarter-yearly dividend period. The dividends on
shares of all series of the Cumulative Preferred Stock
shall be cumulative. In the case of all shares of each
particular series, the dividends on shares of such
series shall be cumulative:
(a) If issued prior to the record date for
the first dividends on the shares of such series,
then from the date for the particular series fixed
therefor as herein provided;
(b) If issued during the period commencing
immediately after a record date for a dividend and
6<PAGE>
terminating at the close of the payment date for
such dividend, then from such dividend payment
date; and
(c) Otherwise from the quarter-yearly
dividend payment date next preceding the date of
issue of such shares;
so that unless dividends on all outstanding shares of
each series of the Cumulative Preferred Stock, at the
annual dividend rate and from the dates for
accumulation thereof fixed as herein provided shall
have been paid for all past quarter-yearly dividend
periods, but without interest on cumulative dividends,
no dividends shall be paid or declared and no other
distribution shall be made on the Common Stock, and no
Common Stock shall be purchased or otherwise acquired
for value by the Corporation; provided that during any
period when the Corporation shall be in default as to
any obligation of the Corporation with respect to any
sinking fund for the benefit of the shares of any
series of the Cumulative Preferred Stock, no dividend
shall be paid or declared and no other distribution
shall be made on the Common Stock or any other shares
of capital stock of the Corporation ranking junior to
the Cumulative Preferred Stock, and no Common Stock or
shares of such capital stock shall be purchased or
otherwise acquired for value by the Corporation, unless
all shares of the Cumulative Preferred Stock then
outstanding shall concurrently be redeemed, purchased
or otherwise acquired or unless the declaration or
payment of such dividend, or such distribution,
purchase or acquisition shall have been ordered,
permitted or approved by the Securities and Exchange
Commission, or by any successor agency thereto, under
the Public Utility Holding Company Act of 1935 or any
legislation enacted in substitution therefor. The
holders of the Cumulative Preferred Stock of any series
shall not be entitled to receive any dividends thereon
other than the dividends referred to in this paragraph
(2).
(3) The Corporation, by action of its Board of
Directors, may redeem the whole or any part of any
series of the Cumulative Preferred Stock, 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 the particular share is a part, from the date
from which dividends on such share became cumulative to
7<PAGE>
the date fixed for such redemption, less the aggregate
of the dividends theretofore or on such redemption date
paid thereon. Notice of every such redemption shall be
given by publication at least once in one daily
newspaper printed in the English language and of
general circulation in Canton, Ohio, and in one daily
newspaper printed in the English language and of
general circulation in the Borough of Manhattan, The
City of New York, the first publication in such
newspapers to be at least thirty (30) days and not more
than sixty (60) days prior to the date fixed for such
redemption. At least thirty (30) days and not more
than sixty (60) days previous notice of every such
redemption shall also be mailed to the holders of
record of the shares of the Cumulative Preferred Stock
so to be redeemed, at their respective addresses as the
same shall appear on the books of the Corporation; but
not failure to mail such notice nor any defect therein
or in the mailing thereof shall affect the validity of
the proceedings for the redemption of any shares of the
Cumulative Preferred Stock so to be redeemed. In case
of the redemption of a part only of any series of the
Cumulative Preferred Stock at the time outstanding, the
Corporation shall select by lot the shares so to be
redeemed. The Board of Directors shall have full power
and authority, subject to the limitations and
provisions herein contained, to prescribe the manner in
which, and the terms and conditions upon which, the
shares of the Cumulative Preferred Stock shall be
redeemed from time to time. If such notice of
redemption shall have been duly given by publication,
and if on or before 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
account of 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 so called for redemption shall not have been
surrendered for cancellation, from and after the date
fixed for redemption, the shares represented thereby
shall no longer be deemed outstanding, the right to
receive dividends thereon shall cease to accrue and all
rights with respect to such shares so called for
redemption shall forthwith on such redemption date
cease and terminate, except only the right of the
holders thereof to receive, out of the funds so set
aside in trust, the amount payable upon redemption
thereof, without interest; provided, however, that the
Corporation may, after giving notice by publication of
any such redemption as hereinbefore provided or after
giving to the bank or trust company hereinafter
8<PAGE>
referred to irrevocable authorization to give such
notice by publication, 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, funds necessary for such redemption with a
bank or trust company in good standing, organized under
the laws of the United States of American or of the
State of New York, doing business in the Borough of
Manhattan, The City of New York, and having capital,
surplus and undivided profits aggregating at least
$5,000,000 or organized under the laws of the State of
Ohio, doing business in the City of Cleveland, Ohio,
and having capital, surplus and undivided profits
aggregating at least $5,000,000, designated in such
notice of redemption, 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 the redemption thereof, without interest.
Nothing herein contained shall limit any right of the
Corporation to purchase or otherwise acquire any shares
of the Cumulative Preferred Stock; provided, however,
that the Corporation shall not redeem (whether through
operation of any sinking fund or otherwise), purchase
or otherwise acquire any shares of any series of the
Cumulative Preferred Stock during any period when the
Corporation shall be in default in the payment of
dividends on any shares of any series of the Cumulative
Preferred Stock, unless all shares of Cumulative
Preferred Stock then outstanding shall concurrently be
so redeemed, purchased or otherwise acquired or unless
such redemption, purchase or acquisition shall have
been ordered, permitted or approved by the Securities
and Exchange Commission, or by any successor commission
thereto, under the Public Utility Holding Company Act
of 1935 or any legislation enacted in substitution
therefor.
(4) Before any amount shall be paid to, or any
assets distributed among, the holders of the Common
Stock upon any liquidation, dissolution or winding up
of the Corporation, and after paying or providing for
the payment of all creditors of the Corporation, the
holders of each series of the Cumulative Preferred
Stock at the time outstanding shall be entitled to be
paid in cash the amount for the particular series fixed
therefor as herein provided, together with a sum in the
case of each share of each series, computed at the
9<PAGE>
annual dividend rate for the series of which the
particular share is a part, from the date from which
dividends on such share became cumulative to the date
fixed for the payment of such distributive amount ,less
the aggregate of the dividends theretofore or on such
date paid thereon; but no payments on account of such
distributive amounts shall be made to the holders of
any series of the Cumulative Preferred Stock unless
there shall likewise be paid at the same time to the
holders of each other series of the Cumulative
Preferred Stock at the time outstanding 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 Stock of any series
shall not be entitled to receive any amounts with
respect thereto upon any liquidation, dissolution or
winding up of the Corporation other than the amounts
referred to in this paragraph. 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 Corporation.
(5) Whenever the full dividends on all series of
the Cumulative Preferred Stock at the time out-standing
for all past quarter-yearly dividend periods shall have
been paid or declared and set apart for payment, then,
subject to the provisions of paragraph (2) and
subparagraph (7)(B)(c) hereof, such dividends (payable
in cash, stock or otherwise) as may be determined by
the Board of Directors may be declared and paid on the
Common Stock, but only out of funds legally available
for the payment of dividends; provided, however, that
so long as any shares of the Cumulative Preferred Stock
of any series are outstanding, the Corporation shall
not declare or pay any dividends on the Common Stock of
the Corporation except as follows:
(a) If and so long as the Common Stock
Equity at the end of the calendar month
immediately preceding the date on which a dividend
on Common Stock is declared is, or as a result of
such dividend would become, less than 20% of total
capitalization, the Corporation shall not declare
such dividend in an amount which, together with
all other dividends on Common Stock paid within
the year ending with and including the date on
which such dividend is payable, exceeds 50% of the
net income of the Corporation available for
dividends on the Common Stock (less any
10<PAGE>
Depreciation Deficiency) for the twelve full
calendar months immediately preceding the month in
which such dividend is declared, except in an
amount not exceeding the aggregate of dividends on
Common Stock which could have been, but have not
been, declared under this clause (a); and
(b) If and so long as the Common Stock
Equity at the end of the calendar month
immediately preceding the date on which a dividend
on Common Stock is declared is, or as a result of
such dividend would become, less than 25% but not
less than 20% of total capitalization, the
Corporation shall not declare such dividend in an
amount which, together with all other dividends on
Common Stock paid within the year ending with and
including the date on which such dividend is
payable, exceeds 75% of the net income of the
Corporation available for dividends on the Common
Stock (less any Depreciation Deficiency) for the
twelve full calendar months immediately preceding
the month in which such dividend is declared,
except in an amount not exceeding the aggregate of
dividends on Common Stock which could have been,
but have not been, declared under clause (a) above
and this clause (b); and
(c) At any time when the Common Stock Equity
is 25% or more of total capitalization, the
Corporation may not declare dividends on shares of
the Common Stock which would reduce the Common
Stock Equity below 25% of total capitalization,
except to the extent provided in clause (a) and
clause (b) above.
For the purposes of this paragraph (5) only:
(i) The term "Common Stock Equity"
shall mean the sum of the par value of, or
stated value or capital represented by, the
shares of Common Stock of the Corporation
outstanding, and the surplus, earned,
capital, and paid-in, of the Corporation
(including any premiums on Common Stock but
excluding any premiums on the Cumulative
Preferred Stock) whether or not available for
the payment of dividends on the Common Stock;
provided, however, that there shall be
deducted from such sum (I) the amount of any
Depreciation Deficiency for the period from
December 31, 1952 to the end of the calendar
month immediately preceding the date on which
11<PAGE>
a dividend on Common Stock is declared and
(II) the amount, if any, by which the
aggregate of all amounts payable upon the
involuntary dissolution, liquidation or
winding up of the Corporation to the holders
of the Cumulative Preferred Stock and of any
other class of stock ranking prior to or on a
parity with the Cumulative Preferred Stock as
to dividends or distributions exceeds the
aggregate of the capital of the Corporation
applicable to such Cumulative Preferred Stock
and class of stock ranking prior to or on a
parity with the Cumulative Preferred Stock as
to dividends or distributions;
(ii) The term "total capitalization"
shall mean the sum of the par value of, or
stated value or capital represented by, the
capital stock of all classes of the
Corporation outstanding, the surplus, earned,
capital and paid-in, of the Corporation
(including any premiums on any such capital
stock), whether or not available for the
payment of dividends on the Common Stock, and
the principal amount of all debt of the
Corporation outstanding, maturing more than
twelve months after the date of the
determination of the total capitalization,
less any amount required to be deducted in
the determination of Common Stock Equity as
in clause (i) above provided;
(iii) The term "dividends on Common
Stock" shall embrace dividends on Common
Stock of the Corporation (other than
dividends payable only in shares of such
Common Stock), distributions on, and
purchases or other acquisitions for value of
any Common Stock of the Corporation; and
(iv) The term "Depreciation Deficiency"
shall mean, as to any specified period, the
amount by which the aggregate of (I) all
amounts credited to the depreciation reserve
account of the Corporation through charges to
operating revenue deductions or otherwise as
provided in the Uniform System of Accounts
prescribed for Public Utilities and Licensees
by the Federal Power Commission and of (II)
all charges for maintenance, shall have been
less than 15% of all operating revenues of
the Corporation (excluding therefrom non-
12<PAGE>
operating income and revenues derived
directly from pro-perties leased to the
Corporation), less all charges to income made
by the Corporation for purchased power and
for the net amount of electric energy
received by the Corporation through
interchange.
(6) In the event of any liquidation, dissolution
or winding up of the Corporation, 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 shares of all series of the Cumulative
Preferred Stock of the full distributive amounts to
which they are respectively entitled as herein
provided, shall be divided among and paid to the
holders of the Common Stock according to their
respective rights and interests.
(7)(A) So long as any shares of the Cumulative
Preferred Stock are outstanding, the Corporation shall
not, without the consent (given by vote at a meeting
called for that purpose) of the holders of at least
two-thirds of the total number of votes which holders
of the outstanding shares of Cumulative Preferred Stock
are entitled to cast, voting together for such purpose
as a single class:
(a) Increase the total authorized amount of
the Cumulative Preferred Stock; or
(b) Create or authorize any shares of any
class of stock ranking prior to the Cumulative
Preferred Stock as to dividends or assets or issue
any shares of any such prior ranking stock more
than twelve months after the date as of which the
Corporation was empowered to create or authorize
such prior ranking stock; or
(c) Amend, alter, change or repeal any of
the express terms of the Cumulative Preferred
Stock or of any series of the Cumulative Preferred
Stock then outstanding in a manner substantially
prejudicial to the holders thereof; provided,
however, that if any such amendment, alteration,
change or repeal would be substantially
prejudicial to the holders of one or more, but not
all, of the series of the Cumulative Preferred
Stock at the time outstanding, only the consent of
the holders of two-thirds of the total number of
votes which holders of the shares of each series
13<PAGE>
prejudicially affected are entitled to cast shall
be required, voting for such purpose as a single
class.
(B) So long as any shares of the Cumulative
Preferred Stock are outstanding, the Corporation shall
not, without the consent (given by vote at a meeting
called for that purpose) of the holders of a majority
of the total number of votes which holders of the
outstanding shares of Cumulative Preferred Stock are
entitled to cast, voting together for such purpose as a
single class:
(a) Merge or consolidate with or into any
other corporation or corporations, or sell or
otherwise dispose of all or substantially all of
its properties, unless such merger or
consolidation, or the issuance and assumption of
all securities to be issued or assumed in
connection with any such merger or consolidation,
or such sale or disposition, shall have been
ordered, approved or permitted by the Securities
and Exchange Commission, or by any successor
agency thereto, under the provisions of the Public
Utility Holding Company Act of 1935 or any
legislation enacted in substitution therefor;
provided that the provisions of this clause (a)
shall not apply to a purchase or other acquisition
by the Corporation of franchises or assets of
another corporation in any manner which does not
involved a merger or consolidation; or
(b) Issue or assume any unsecured debt
securities for purposes other than
(i) the reacquisition, redemption or
other retirement of any evidences of
indebtedness theretofore issued or assumed by
the Corporation, or
(ii) the reacquisition, redemption or
other retirement of all outstanding shares of
the Cumulative Preferred Stock,
if immediately after such issue or assumption, the
total principal amount of all unsecured debt
securities (other than the principal amount of all
long-term unsecured debt securities not in excess
of 10% of the Capitalization of the Corporation)
issued or assumed by the Corporation and then
outstanding would exceed 10% of the Capitalization
of the Corporation.
14<PAGE>
For the purposes of this subparagraph (b)
only:
(I) "unsecured debt securities" shall
be deemed to mean any unsecured notes,
debentures, or other securities representing
unsecured indebtedness, but shall not include
contractual commitments and agreements for
the purchase of property, materials or
equipment to be used or consumed in the
ordinary course of the Corporation's
business;
(II) "long-term unsecured debt
securities" shall be deemed to mean all
unsecured debt securities, which, at the time
of issuance or assumption by the Corporation,
matured by their terms on a date ten or more
years subsequent to such issuance or
assumption to the extent that, as of any
specified time of computation, such unsecured
debt securities do not mature by their terms
and are not required to be redeemed,
reacquired or otherwise retired, through
sinking fund or other debt retirement
provision, on a date less than five years
subsequent to such time of computation; and
(III) the "Capitalization of the
Corporation" shall be deemed to mean, as of
any specified time of computation, an amount
equal to the sum of the total principal
amount of all bonds or other debt securities
representing secured indebtedness issued or
assumed by the Corporation and then to be
outstanding, and the aggregate of the par
value of, or stated capital represented by,
the outstanding shares of all classes of
stock and of the surplus of the Corporation,
paid in, earned and other, if any.
(c) Issue, sell or otherwise dispose of any
shares of the Cumulative Preferred Stock or of any
other class of stock ranking prior to or on a
parity with the Cumulative Preferred Stock as to
dividends or distributions, unless (i) the net
income of the Corporation, determined in
accordance with generally accepted accounting
practices to be available for the payment of
dividends for a period of twelve (12) consecutive
calendar months within the fifteen (15) calendar
months immediately preceding the issuance, sale or
15<PAGE>
disposition of such stock (but less any
Depreciation Deficiency for such period), shall
have been at least equal to twice the annual
dividend requirements on all outstanding shares of
the Cumulative Preferred Stock and of al other
classes of stock ranking prior to or on a parity
with the Cumulative Preferred Stock as to
dividends or distributions, including the shares
proposed to be issued; (ii) the gross income of
the Corporation for said period, determined in
accordance with generally accepted accounting
practices (but in any event after deducting the
amount for said period charged by the Corporation
on its books to depreciation expense and in
addition thereto any Depreciation Deficiency for
said period) to be available for the payment of
interest, shall have been at least one and one-
half times the sum of (I) the annual interest
charges on all interest bearing indebtedness of
the Corporation and (II) the annual dividend
requirements on all outstanding shares of the
Cumulative Preferred Stock and of all other
classes of stock ranking prior to or on a parity
with the Cumulative Preferred Stock as to
dividends or distributions, including the shares
proposed to be issued; and (iii) the aggregate of
the capital of the Corporation applicable to the
Common Stock and of the surplus of the Corporation
immediately after such issuance, sale or other
disposition, less any Depreciation Deficiency for
the period from December 31, 1952 to such date,
shall be not less than the amount payable upon the
involuntary dissolution, liquidation or winding up
of the Corporation to the holders of the
Cumulative Preferred Stock and of such other class
of stock, excluding from the foregoing computation
all stock which is to be retired in connection
with such additional issue; provided, that the
Corporation shall not thereafter pay any dividends
on the Common Stock unless immediately thereafter
the aggregate of the capital of the Corporation
applicable to the Common Stock and of the surplus
of the Corporation, less any Depreciation
Deficiency for the period from December 31, 1952
to such date, shall be not less than the amount
payable upon the involuntary dissolution,
liquidation or winding up of the Corporation to
the holders of the Cumulative Preferred Stock and
of such other class of stock.
For the purposes of this subparagraph (c)
only, the term "Depreciation Deficiency" shall
16<PAGE>
mean, as to any specified period, the amount by
which the aggregate of (i) all amounts credited to
the depreciation reserve account of the
Corporation through charges to operating revenue
deductions or otherwise as provided in the Uniform
System of Accounts prescribed for Public Utilities
and Licensees by the Federal Power Commission and
of (ii) all charges for maintenance, shall have
been less than 15% of all operating revenues of
the Corporation (excluding therefrom non-operating
income and revenues derived directly from
properties leased to the Corporation), less all
charges to income made by the Corporation for
purchased power and for the net amount of electric
energy received by the Corporation through
interchange.
(8) No holder of shares of any series of the
Cumulative Preferred Stock shall be entitled as such as
a matter of right to subscribe for or purchase any part
of any new or additional issue of stock, or securities
convertible into stock of any class whatsoever, whether
now or hereafter authorized, and whether issued for
cash, property, services, by way of dividends, or
otherwise.
(9)(A) Except as otherwise provided in this
paragraph (9) or in paragraph (7) hereof, or as
otherwise required by the laws of the State of Ohio;
(i) Every holder of Cumulative Preferred
Stock ($100 voting) shall be entitled to cast one
vote for each share of Cumulative Preferred Stock
($100 voting) held by him for the election of
Directors and upon all other matters;
(ii) The holders of Cumulative Preferred
Stock ($100 non-voting) and Cumulative Preferred
Stock ($25 non-voting) shall not be entitled to
vote; and
(iii) Every holder of Common Stock shall be
entitled to cast one vote for each share of Common
Stock held by him for the election of Directors
and upon all other matters.
Whenever, pursuant to the provisions of this paragraph
(9) or paragraph (7) hereof, the holders of Cumulative
Preferred Stock ($100 voting), Cumulative Preferred
Stock ($100 non-voting) and Cumulative Preferred Stock
($25 non-voting) shall be entitled to vote together as
a single class for the election of Directors or on any
17<PAGE>
other matter, every holder of shares of Cumulative
Preferred Stock ($100 voting) or Cumulative Preferred
Stock ($100 non-voting) shall be entitled to cast one
vote for each such share held by him and every holder
of Cumulative Preferred Stock ($25 non-voting) shall be
entitled to cast one-quarter of one vote for each such
share held by him. In addition to any provisions
herein, whenever the consent or the affirmative vote of
the holders of any class of the Cumulative Preferred
Stock, voting as a single class, shall be required for
the adoption of any amendment to these Articles
pursuant to any provision of law, the consent or
affirmative vote of the holders of at least a majority
of the total number of shares of such class then
outstanding shall be required for such purpose. Except
when some mandatory provision of law shall be
controlling and except as otherwise provided in
subparagraphs (7)(A)(c), 12(c), (14)(c) and (16)(c)
hereof, whenever shares of two or more series of any
class of Cumulative Preferred Stock are outstanding, no
particular series of such class shall be entitled to
vote as a separate series on any matter.
(B) If and when dividends payable on the
Cumulative Preferred Stock shall be in default in an
amount equivalent to four full quarter-yearly dividends
on all shares of all series of the Cumulative Preferred
Stock at the time outstanding, and until all dividends
in default on the Cumulative Preferred Stock shall have
been paid, the holders of all shares of the Cumulative
Preferred Stock, voting separately as one class, shall
be entitled to elect the smallest number of Directors
necessary to constitute a majority of the full Board of
Directors, and the holders of the Common Stock, voting
separately as a class, shall be entitled to elect the
remaining Directors of the Corporation. The terms of
office of all persons who may be Directors of the
Corporation at the time shall terminate upon the
election of a majority of the Board of Directors by the
holders of the Cumulative Preferred Stock, except that
if the holders of the Common Stock shall not have
elected the remaining Directors of the Corporation,
then, and only in that event, the Directors of the
Corporation in office just prior to the election of a
majority of the Board of Directors by the holders of
the Cumulative Preferred Stock shall elect the
remaining Directors of the Corporation.
(C) If and when all dividends then in default
on the Cumulative Preferred Stock at the time
outstanding shall be paid (and such dividends shall be
declared and paid out of any funds legally available
18<PAGE>
therefor as soon as reasonably practicable), the
Cumulative Preferred Stock shall thereupon be divested
of any special right with respect to the election of
Directors provided in subparagraph (B) hereof, and the
voting power of the Cumulative Preferred Stock and the
Common Stock shall revert to the status existing before
the occurrence of such default; but always subject to
the same provisions for vesting such special rights in
the Cumulative Preferred Stock in case of further like
default or defaults in dividends thereon. Upon the
termination of any such special right the terms of
office of all persons who may have been elected
Directors of the Corporation by vote of the holders of
the Cumulative Preferred Stock, as a class, pursuant to
such special right shall forthwith terminate.
(D) In case of any vacancy in the Board of
Directors occurring among the Directors elected by the
holders of the Cumulative Preferred Stock, as a class,
pursuant to subparagraph (B) hereof, the holders of the
Cumulative Preferred Stock then outstanding and
entitled to vote may elect a successor to hold office
for the unexpired term of the Director whose place
shall be vacant. In case of a vacancy in the Board of
Directors occurring among the Directors elected by the
holders of the Common Stock, as a class, or by the
Directors in office just prior to the election of a
majority of the Board of Directors by the holders of
the Cumulative Preferred Stock, pursuant to
subparagraph (B) hereof, the holders of the Common
Stock then outstanding and entitled to vote may elect a
successor to hold office for the unexpired term of the
Director whose place shall be vacant. In all other
cases, any vacancy occurring among the Directors shall
be filled by the vote of a majority of the remaining
Directors.
(E) Whenever the holders of the Cumulative
Preferred Stock, as a class, become entitled, to elect
Directors of the Corporation pursuant to either
subparagraphs (B) or (D) hereof, it shall be the duty
of the president, a vice-president or the secretary of
the Corporation forthwith to call, and to cause notice
to be given to the stockholders entitled to vote at, a
meeting to be held at such time as the Corporation's
officers may fix, not less than thirty nor more than
sixty days after the accrual of such right, for the
purpose of electing Directors. The notice so given
shall be mailed to each holder of record of the
Cumulative Preferred Stock at his address as it appears
upon the records of the Corporation and shall set
forth, among other things, (i) that by reason of the
19<PAGE>
fact that dividends payable on the Cumulative Preferred
Stock are in default in an amount equivalent to four
full quarter-yearly dividends or more per share, the
holders of the Cumulative Preferred Stock, voting
separately as a class, have the right to elect the
smallest number of Directors necessary to constitute a
majority of the full Board of Directors of the
Corporation, (ii) that any holder of the Cumulative
Preferred Stock has the right, at any reasonable time,
to inspect, and make copies of, the list or lists of
holders of the Cumulative Preferred Stock maintained at
the principal office of the Corporation or at the
office of any Transfer Agent of the Cumulative
Preferred Stock, and (iii) either the entirety of this
paragraph or the substance thereof with respect to the
number of shares of the Cumulative Preferred Stock
required to be represented at any meeting, or
adjournment thereof, called for the election of
Directors of the Corporation. At the first meeting of
stockholders held for the purpose of electing Directors
during such time as the holders of the Cumulative
Preferred Stock shall have the special right, voting
separately as a class, to elect Directors, the presence
in person or by proxy of the holders of a majority of
the outstanding Common Stock shall be required to
constitute a quorum of such class for the election of
Directors, and the presence in person or by proxy of
the holders of a majority of the total number of votes
which holders of the outstanding shares of Cumulative
Preferred Stock are entitled to cast shall be required
to constitute a quorum of such class for the election
of Directors; provided, however, that in the absence of
a quorum of the holders of the Cumulative Preferred
Stock, no election of Directors shall be held, but a
majority of the holders of the Cumulative Preferred
Stock who are present in person or by proxy shall have
power to adjourn the election of the Directors to a
date not less than fifteen nor more than fifty days
from the giving of the notice of such adjourned meeting
hereinafter provided for; and provided, further, that
at such adjourned meeting, the presence in person or by
proxy of the holders of 35% of the total number of
votes which holders of the outstanding shares of
Cumulative Preferred Stock are entitled to cast shall
be required to constitute a quorum of such class for
the election of Directors. In the event such first
meeting of stockholders shall be so adjourned, it shall
be the duty of the president, a vice-president or the
secretary of the Corporation, within ten days from the
date on which such first meeting shall have been
adjourned, to cause notice of such adjourned meeting to
be given to the stockholders entitled to vote thereat,
20<PAGE>
such adjourned meeting to be held not less than fifteen
days nor more than fifty days from the giving of such
second notice. Such second notice shall be given in
the form and manner hereinabove provided for with
respect to the notice required to be given of such
first meeting of stockholders, and shall further set
forth that a quorum was not present at such first
meeting and that the holders of 35% of the total number
of votes which holders of the outstanding shares of
Cumulative Preferred Stock are entitled to cast shall
be required to constitute a quorum of such class for
the election of Directors at such adjourned meeting.
If the requisite quorum of holders of the Cumulative
Preferred Stock shall not be present at said adjourned
meeting, then the Directors of the Corporation then in
office shall remain in office until the next Annual
Meeting of the Corporation, or special meeting in lieu
thereof, and until their successors shall have been
elected and shall qualify. Neither such first meeting
nor such adjourned meeting shall be held on a date
within sixty days of the date of the next Annual
Meeting of the Corporation or special meeting in lieu
thereof. At each Annual Meeting of the Corporation, or
special meeting in lieu thereof, held during such time
as the holders of the Cumulative Preferred Stock,
voting separately as a class, shall have the right to
elect a majority of the Board of Directors, the
foregoing provisions of this subparagraph shall govern
such Annual Meeting, or special meeting in lieu
thereof, as if said Annual Meeting or special meeting
were the first meeting of stockholders held for the
purpose of electing Directors after the right of the
holders of the Cumulative Preferred Stock, voting
separately as a class, to elect a majority of the Board
of Directors, should have accrued with the exception
that, until the holders of the Cumulative Preferred
Stock shall have elected a majority of the Board of
Directors, if at any adjourned Annual Meeting, or
special meeting in lieu thereof, holders of 35% of the
total number of votes which holders of the outstanding
shares of Cumulative Preferred Stock are entitled to
cast are not present in person or by proxy, all the
Directors to be elected shall be elected by a vote of
the holders of a majority of the Common Stock of the
Corporation present or represented at the meeting.
(F) So long as any shares of the Cumulative
Preferred Stock of any series are outstanding, the
Board of Directors of the Corporation shall consist of
not less than three (3) persons and not more than the
number of persons set forth in the Corporation's Code
of Regulations.
21<PAGE>
(10) The Corporation may, at any time and from
time to time, issue and dispose of any of the
authorized and unissued shares of the Cumulative
Preferred Stock and Common Stock for such consideration
as may be fixed by the Board of Directors, subject to
any provisions of law then applicable, and subject to
the provisions of any resolutions of the stockholders
of the Corporation relating to the issue and
disposition of such shares.
(11) The Corporation hereby classifies $20,240,300
par value of the Cumulative Preferred Stock ($100
voting) as a series of such Cumulative Preferred Stock
($100 voting), which shall be designated as "4-1/2%
Cumulative Preferred Stock," consisting of 202,403
shares of the par value of $100 per share.
(12) The preferences or restrictions or qualifica-
tions and the descriptions and terms of the shares of
the 4-1/2% Cumulative Preferred Stock, in the respects
in which the shares of such series may vary from shares
of other series of the Cumulative Preferred Stock ($100
voting), shall be as follows:
(a) The annual dividend rate for such series
shall be 4-1/2% per annum and the date from which
dividends on all shares of such series issued
prior to the record date for the dividend payable
June 1, 1941, shall be cumulative, shall be March
1, 1941;
(b) The redemption price for such series
shall be $112.50 per share until March 1, 1946; on
and after March 1, 1946 and until March 1, 1951,
$111 per share; and on and after March 1, 1951,
$110 per share;
(c) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any liquidation, dissolution or winding up of
the Corporation shall be:
$110 per share, upon any voluntary
liquidation, dissolution or winding up of the
Corporation, except that if such voluntary
liquidation, dissolution or winding up of the
Corporation shall have been approved by the
vote in favor thereof of the holders of a
majority of the total number of shares of the
4-1/2% Cumulative Preferred Stock then
outstanding, given at a meeting called for
that purpose, the amount so payable on such
22<PAGE>
voluntary liquidation, dissolution, or
winding up shall be $100 per share; or
$100 per share, in the event of any
involuntary liquidation, dissolution or
winding up of the Corporation;
(d) There shall not be any sinking fund
provided for the purchase or redemption of shares
of the 4-1/2% Cumulative Preferred Stock; and
(e) The shares of the 4-1/2% Cumulative
Preferred Stock shall not have any rights to
convert the same into and/or purchase stock of any
other series or class or other securities, or any
special rights other than those specified herein.
(13) The Corporation hereby classifies $10,000,000
par value of the Cumulative Preferred Stock ($100
voting) as a series of such Cumulative Preferred Stock
($100 voting), which shall be designated as "4.40%
Cumulative Preferred Stock," consisting of 100,000
shares of the par value of $100 per share.
(14) The preferences or restrictions or qualifica-
tions and the descriptions and terms of the shares of
the 4.40% Cumulative Preferred Stock, in the respects
in which the shares of such series may vary from shares
of other series of the Cumulative Preferred Stock ($100
voting), shall be as follows:
(a) The annual dividend rate for such series
shall be 4.40% per annum and the date from which
dividends on all shares of such series issued
prior to the record date for the dividend payable
March 1, 1953, shall be cumulative, shall be the
date of issuance of the shares of such series;
(b) The redemption price for such series
shall be $107.50 per share on or prior to January
1, 1960; $106.00 per share after January 1, 1960
but on or prior to January 1, 1965; $105.00 per
share after January 1, 1965 but on or prior to
January 1, 1970; and $104.00 per share thereafter.
(c) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any liquidation, dissolution or winding up of
the Corporation shall be:
The redemption price in effect at the
date of any voluntary liquidation,
23<PAGE>
dissolution or winding up of the Corporation,
except that if such voluntary liquidation,
dissolution or winding up of the Corporation
shall have been approved by the vote in favor
thereof of the holders of a majority of the
total number of shares of the 4.40%
Cumulative Preferred Stock then outstanding,
given at a meeting called for that purpose,
the amount so payable on such voluntary
liquidation, dissolution, or winding up shall
be $100 per share; or
$100 per share, in the event of any
involuntary liquidation, dissolution or
winding up of the Corporation;
(d) There shall not be any sinking fund
provided for the purchase or redemption of shares
of the 4.40% Cumulative Preferred Stock; and
(e) The shares of the 4.40% Cumulative
Preferred Stock shall not have any rights to
convert the same into and/or purchase stock of any
other series or class or any other securities, or
any special rights other than those specified
herein.
(15) The Corporation hereby classifies $5,000,000
par value of the Cumulative Preferred Stock ($100
voting) as a series of such Cumulative Preferred Stock
($100 voting), which shall be designated as "4.08%
Cumulative Preferred Stock," consisting of 50,000
shares of the par value of $100 per share.
(16) The preferences or restrictions or qualifica-
tions and the descriptions and terms of the shares of
the 4.08% Cumulative Preferred Stock, in the respects
in which the shares of such series may vary from shares
of other series of the Cumulative Preferred Stock ($100
voting), shall be as follows:
(a) The annual dividend rate for such series
shall be 4.08% per annum and the date from which
dividends on all shares of such series issued
prior to the record date for the dividend payable
June 1, 1954, shall be cumulative, shall be the
date of issuance of the shares of such series;
(b) The redemption price of such series
shall be $106 per share on or prior to April 1,
1959; $105 per share after April 1, 1959 but on or
prior to April 1, 1964; $104 per share after April
24<PAGE>
1, 1964 but on or prior to April 1, 1969; and $103
per share thereafter;
(c) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any liquidation, dissolution or winding up of
the Corporation shall be:
The redemption price in effect at the
date of any voluntary liquidation,
dissolution or winding up of the Corporation,
except that if such voluntary liquidation,
dissolution or winding up of the Corporation
shall have been approved by the vote in favor
thereof of the holders of a majority of the
total number of shares of the 4.08%
Cumulative Preferred Stock then outstanding,
given at a meeting called for that purpose,
the amount so payable on such voluntary
liquidation, dissolution, or winding up shall
be $100 per share; or
$100 per share, in the event of any
involuntary liquidation, dissolution or
winding up of the Corporation;
(d) There shall not be any sinking fund
provided for the purchase or redemption of shares
of the 4.08% Cumulative Preferred Stock; and
(e) The shares of the 4.08% Cumulative
Preferred Stock shall not have any rights to
convert the same into and/or purchase stock of any
other series or class or any other securities, or
any special rights other than those specified
herein.
(17) The Corporation hereby classifies $6,000,000
par value of the Cumulative Preferred Stock ($100
voting) as a series of such Cumulative Preferred Stock
($100 voting), which shall be designated as "4.20%
Cumulative Preferred Stock," consisting of 60,000
shares of the par value of $100 per share.
(18) The preferences or restrictions or qualifica-
tions and the descriptions and terms of the shares of
the 4.20% Cumulative Preferred Stock, in the respects
in which the shares of such series may vary from shares
of other series of the Cumulative Preferred Stock ($100
voting), shall be as follows:
25<PAGE>
(a) The annual dividend rate for such series
shall be 4.20% per annum and the date from which
dividends on all shares of such series issued
prior to the record date for the dividend payable
December 1, 1955, shall be cumulative, shall be
the date of issuance of the shares of such series;
(b) The redemption price for such series
shall be $105.20 per share on or prior to
September 1, 1960; $104.20 per share after
September 1, 1960 but on or prior to September 1,
1965; and $103.20 per share after September 1,
1965;
(c) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any liquidation, dissolution or winding up of
the Corporation shall be the redemption price in
effect at the date of any voluntary liquidation,
dissolution or winding up of the Corporation; or
$100 per share, in the event of any involuntary
liquidation, dissolution or winding up of the
Corporation;
(d) There shall not be any sinking fund
provided for the purchase or redemption of shares
of the 4.20% Cumulative Preferred Stock; and
(e) The shares of the 4.20% Cumulative
Preferred Stock shall not have any rights to
convert the same into and/or purchase stock of any
other series or class or any other securities, or
any special rights other than those specified
herein.
(19) The Corporation hereby classifies $15,000,000
par value of the Cumulative Preferred Stock ($100
voting) as a series of such Cumulative Preferred Stock
($100 voting), which shall be designated as "8.04%
Cumulative Preferred Stock," consisting of 150,000
shares of the par value of $100 per share.
(20) The preferences or restrictions or qualifica-
tions and the descriptions and terms of the shares of
the 8.04% Cumulative Preferred Stock, in the respects
in which the shares of such series may vary from shares
of other series of the Cumulative Preferred Stock ($100
voting), shall be as follows:
(a) The annual dividend rate for such series
shall be 8.04% per annum and the date from which
dividends on all shares of such series issued
26<PAGE>
prior to the record date for the dividend payable
June 1, 1971, shall be cumulative, shall be the
date of issuance of the shares of such series;
(b) The redemption price for such series
shall be $109.81 per share prior to March 1, 1976;
$107.80 per share on and after March 1, 1976 but
prior to March 1, 1981; $105.79 per share on and
after March 1, 1981 but prior to March 1, 1986;
$103.78 per share on and after March 1, 1986 but
prior to March 1, 1991; and $102.58 per share on
March 1, 1991 and thereafter; provided, however,
that no share of such series shall be redeemed
prior to March 1, 1976 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
capital stock ranking equally with or prior to the
shares of such series 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 capital
stock has an effective dividend cost to the
Corporation (so computed), of less than 8.02% per
annum;
(c) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any liquidation, dissolution or winding up of
the Corporation shall be the redemption price in
effect at the date of any voluntary liquidation,
dissolution or winding up of the Corporation; or
$100 per share, in the event of any involuntary
liquidation, dissolution or winding up of the
Corporation;
(d) There shall not be any sinking fund
provided for the purchase or redemption of shares
of such series; and
(e) The shares of such series shall not have
any rights to convert the same into and/or
purchase stock of any other series or class or any
other securities, or any special rights other than
those specified herein.
(21) The Corporation hereby classifies $10,000,000
par value of the Cumulative Preferred Stock ($100
voting) as a series of such Cumulative Preferred Stock
($100 voting), which shall be designated as "7.72%
Cumulative Preferred Stock," consisting of 100,000
shares of the par value of $100 per share.
27<PAGE>
(22) The preferences or restrictions or qualifica-
tions and the descriptions and terms of the shares of
the 7.72% Cumulative Preferred Stock, in the respects
in which the shares of such series may vary from shares
of other series of the Cumulative Preferred Stock ($100
voting), shall be as follows:
(a) The annual dividend rate for such series
shall be 7.72% per annum and the date from which
dividends on all shares of such series issued
prior to the record date for the dividend payable
June 1, 1971, shall be cumulative, shall be the
date of issuance of the shares of such series;
(b) The redemption price for such series
shall be $109.30 per share prior to April 1, 1976;
$107.37 per share on and after April 1, 1976 but
prior to April 1, 1981; $105.44 per share on and
after April 1, 1981 but prior to April 1, 1986;
$103.51 per share on and after April 1, 1986 but
prior to April 1, 1991; and $102.35 per share on
April 1, 1991 and thereafter; provided, however,
that no share of such series shall be redeemed
prior to April 1, 1976 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
capital stock ranking equally with or prior to the
shares of such series 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 capital
stock has an effective dividend cost to the
Corporation (so computed), of less than 7.69% per
annum;
(c) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any liquidation, dissolution or winding up of
the Corporation shall be the redemption price in
effect at the date of any voluntary liquidation,
dissolution or winding up of the Corporation; or
$100 per share, in the event of any involuntary
liquidation, dissolution or winding up of the
Corporation;
(d) There shall not be any sinking fund
provided for the purchase or redemption of shares
of such series; and
(e) The shares of such series shall not have
any rights to convert the same into and/or
28<PAGE>
purchase stock of any other series or class or any
other securities, or any special rights other than
those specified herein.
(23) The Corporation hereby classifies $35,000,000
par value of the Cumulative Preferred Stock ($100
voting) as a series of such Cumulative Preferred Stock
($100 voting), which shall be designated as "7.60%
Cumulative Preferred Stock," consisting of 350,000
shares of the par value of $100 per share.
(24) The preferences or restrictions or qualifica-
tions and the descriptions and terms of the shares of
the 7.60% Cumulative Preferred Stock, in the respects
in which the shares of such series may vary from shares
of other series of the Cumulative Preferred Stock ($100
voting), shall be as follows:
(a) The annual dividend rate for such series
shall be 7.60% per annum and the date from which
dividends on all shares of such series issued
prior to the record date for the dividend payable
December 1, 1971, shall be cumulative, shall be
the date of issuance of the shares of such series;
(b) The redemption price for such series
shall be $109.10 per share prior to October 1,
1976; ($107.20 per share on or after October 1,
1976 but prior to October 1, 1981; $105.30 per
share on and after October 1, 1981 but prior to
October 1, 1986; $103.40 per share on and after
October 1, 1986 but prior to October 1, 1991; and
$102.26 per share on October 1 1991 and
thereafter; provided, however, that no share of
such series shall be redeemed prior to October 1,
1976 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 capital stock ranking
equally with or prior to the shares of such series
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 capital stock has an
effective dividend cost to the Corporation (so
computed), of less than 7.57% per annum;
(c) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any liquidation, dissolution or winding up of
the Corporation shall be the redemption price in
effect at the date of any voluntary liquidation,
29<PAGE>
dissolution or winding up of the Corporation; or
$100 per share, in the event of any involuntary
liquidation, dissolution or winding up of the
Corporation;
(d) There shall not be any sinking fund
provided for the purchase or redemption of shares
of such series; and
(e) The shares of such series shall not have
any rights to convert the same into and/or
purchase stock of any other series or class or any
other securities, or any special rights other than
those specified herein.
(25) The Corporation hereby classifies $35,000,000
par value of the Cumulative Preferred Stock ($100
voting) as a series of such Cumulative Preferred Stock
($100 voting), which shall be designated as "7-6/10%
Cumulative Preferred Stock," consisting of 350,000
shares of the par value of $100 per share.
(26) The preferences or restrictions or qualifica-
tions and the descriptions and terms of the shares of
the 7-6/10% Cumulative Preferred Stock, in the respects
in which the shares of such series may vary from shares
of other series of the Cumulative Preferred Stock ($100
voting), shall be as follows:
(a) The annual dividend rate for such series
shall be 7-6/10% per annum and the date from which
dividends on all shares of such series issued
prior to the record date for the dividend payable
June 1, 1972, shall be cumulative, shall be the
date of issuance of the shares of such series;
(b) The redemption price for such series
shall be $108.95 per share prior to April 1, 1977;
$107.05 per share on and after April 1, 1977 but
prior to April 1, 1982; $105.15 per share on and
after April 1, 1982 but prior to April 1, 1987;
$103.25 per share on and after April 1, 1987 but
prior to April 1, 1992; and $102.11 per share on
April 1, 1992 and thereafter; provided, however,
that no share of such series shall be redeemed
prior to April 1, 1977 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
capital stock ranking equally with or prior to the
shares of such series as to dividends or assets,
if such debt has an effective interest cost to the
30<PAGE>
Corporation (computed in accordance with generally
accepted financial practice), or such capital
stock has an effective dividend cost to the
Corporation (so computed), of less than 7.58% per
annum;
(c) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any liquidation, dissolution or winding up of
the Corporation shall be the redemption price in
effect at the date of any voluntary liquidation,
dissolution or winding up of the Corporation; or
$100 per share, in the event of any involuntary
liquidation, dissolution or winding up of the
Corporation;
(d) There shall not be any sinking fund
provided for the purchase or redemption of shares
of such series; and
(e) The shares of such series shall not have
any rights to convert the same into and/or
purchase stock of any other series or class or any
other securities, or any special rights other than
those specified herein.
(27) The Corporation hereby classifies $45,000,000
par value of the Cumulative Preferred Stock ($100
voting) as a series of such Cumulative Preferred Stock
($100 voting), which shall be designated as "7.76%
Cumulative Preferred Stock," consisting of 450,000
shares of the par value of $100 per share.
(28) The preferences or restrictions or qualifica-
tions and the descriptions and terms of the shares of
the 7.76% Cumulative Preferred Stock, in the respects
in which the shares of such series may vary from shares
of other series of the Cumulative Preferred Stock ($100
voting), shall be as follows:
(a) The annual dividend rate for such series
shall be 7.76% per annum and the date from which
dividends on all shares of such series issued
prior to the record date for the dividend payable
December 1, 1972, shall be cumulative, shall be
the date of issuance of the shares of such series;
(b) The redemption price for such series
shall be $109.20 per share prior to October 1,
1977; $107.26 per share on and after October 1,
1977 but prior to October 1, 1982; $105.32 per
share on and after October 1, 1982 but prior to
31<PAGE>
October 1, 1987; $103.38 per share on and after
October 1, 1987 but prior to October 1, 1992; and
$102.22 per share on October 1, 1992 and
thereafter; provided, however, that no share of
such series shall be redeemed prior to October 1,
1977 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 capital stock ranking
equally with or prior to the shares of such series
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 capital stock has an
effective dividend cost to the Corporation (so
computed), of less than 7.74% per annum;
(c) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any liquidation, dissolution or winding up of
the Corporation shall be the redemption price in
effect at the date of any voluntary liquidation,
dissolution or winding up of the Corporation; or
$100 per share, in the event of any involuntary
liquidation, dissolution or winding up of the
corporation;
(d) There shall not be any sinking fund
provided for the purchase or redemption of shares
of such series; and
(e) The shares of such series shall not have
any rights to convert the same into and/or
purchase stock of any other series or class or any
other securities, or any special rights other than
those specified herein.
(29) The Corporation hereby classifies $30,000,000
par value of the Cumulative Preferred Stock ($100
voting) as a series of such Cumulative Preferred Stock
($100 voting), which shall be designated as "8.48%
Cumulative Preferred Stock," consisting of 300,000
shares of the par value of $100 per share.
(30) The preferences or restrictions or qualifications
and the descriptions and terms of the shares of 8.48%
Cumulative Preferred Stock, in the respects in which the
shares of such series may vary from shares of other series
of the Cumulative Preferred Stock ($100 voting), shall be as
follows:
32<PAGE>
(a) The annual dividend rate for such series
shall be 8.48% per annum and the date from which
dividends on all shares of such series issued
prior to the record date for the dividend payable
September 1, 1973 shall be cumulative, shall be
the date of issuance of the shares of such series;
(b) The redemption price for such series
shall be $110.03 per share prior to August 1,
1978; $107.91 per share on and after August 1,
1978 but prior to August 1, 1983; $105.79 per
share on and after August 1, 1983 but prior to
August 1, 1988; $103.67 per share on and after
August 1, 1988 but prior to August 1, 1993; and
$102.40 per share on August 1, 1993 and
thereafter; provided, however, that no share of
such series shall be redeemed prior to August 1,
1978 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 capital stock ranking
equally with or prior to the shares of such series
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 capital stock has an
effective divided cost to the Corporation (so
computed), of less than 8.45% per annum;
(c) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any liquidation, dissolution or winding up of
the Corporation shall be the redemption price in
effect at the date of any voluntary liquidation,
dissolution or winding up of the Corporation; or
$100 per share, in the event of any involuntary
liquidation, dissolution or winding up of the
Corporation;
(d) There shall not be any sinking fund
provided for the purchase or redemption of shares
of such series; and
(e) The shares of such series shall not have
any rights to convert the same into and/or
purchase stock of any other series or class or any
other securities, or any special rights other than
those specified herein.
(31) The Corporation hereby classifies $25,000,000
par value of the Cumulative Preferred Stock ($100
voting) as a series of such Cumulative Preferred Stock
33<PAGE>
($100 voting), which shall be designated as "14%
Cumulative Preferred Stock," consisting of 250,000
shares of the par value of $100 per share.
(32) The preferences or restrictions or qualifica-
tions and the descriptions and terms of the shares of
the 14% Cumulative Preferred Stock, in the respects in
which the shares of such series may vary from shares of
other series of the Cumulative Preferred Stock ($100
voting), shall be as follows:
(a) The annual dividend rate for such series
shall be 14% per annum and in the case of each
share of such series issued prior to the record
date for the first dividend payable on the shares
of such series, the date from which dividends on
such share of such series shall be cumulative
shall be the date of issuance of such share, and
in the case of each other share of such series, as
otherwise provided in this Article.
(b) The redemption prices at which shares of
such series may be redeemed at the option of the
Corporation shall be an amount per share equal to
(i) 101% of the sum of $100 and the annual
dividend prior to March 1, 1985, (ii) $100 plus
50% of the annual dividend on or after March 1,
1985 but prior to March 1, 1990, (iii) $100 plus
25% of the annual dividend on or after March 1,
1990 but prior to March 1, 1995, and (iv) $100
plus 10% of the annual dividend on or after March
1, 1995; provided, however, that no share of such
series shall be redeemed prior to March 1, 1980 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 capital stock ranking
equally with or prior to the shares of said series
as to dividends or assets, if such debt has an
effective interest cost to the Corporation
(computed in accordance with generally accepted
financial practices), or such capital stock has an
effective dividend cost to the Corporation (so
computed), of less than 14.6% per annum.
(c) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any liquidation, dissolution or winding up of
the Corporation shall be the redemption price
provided in subparagraph (b) of this paragraph
(32) in effect at the date of any voluntary
liquidation, dissolution or winding up of the
34<PAGE>
Corporation; or $100 per share, in the event of
any involuntary liquidation, dissolution or
winding up of the Corporation.
(d)(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 March 1 in each
year commencing with the year 1980, redeem as and
for a sinking fund requirement, out of funds
legally available therefor, 12,500 shares, at a
redemption price of $100 per share. The sinking
fund requirement shall be cumulative so that if on
any such March 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 March 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 subparagraph (d)(1) hereof, to redeem
at a redemption price of $100 per share, an
additional 12,500 shares. No redemption made
pursuant to this subparagraph (d)(2) shall be
deemed to fulfill any sinking fund requirement
established pursuant to subparagraph (d)(1).
(3) The Corporation shall be entitled, at
its election, to credit against any sinking fund
requirement due on March 1 of any year pursuant to
subparagraph (d)(1) of this paragraph (32), shares
of such series theretofore purchased or otherwise
acquired by the Corporation.
(e) The shares of such series shall not have
any rights to convert the same into and/or
purchase stock of any other series or class or any
other securities, or any special rights other than
those specified herein.
(33) The Corporation hereby classifies $40,000,000
par value of the Cumulative Preferred Stock ($100
voting) as a series of such Cumulative Preferred Stock
($100 voting), which shall be designated as "14%
Cumulative Preferred Stock, Series A," consisting of
400,000 shares of the par value of $100 per share.
(34) The preferences or restrictions or qualifica-
tions and the descriptions and terms of the shares of
35<PAGE>
the 14% Cumulative Preferred Stock, Series A, in the
respects in which the shares of such series may vary
from shares of other series of the Cumulative Preferred
Stock ($100 voting), shall be as follows:
(a) The annual dividend rate for such series
shall be 14% per annum and in the case of each
shares of such series issued prior to the record
date for the first dividend payable on the shares
of such series, the date from which dividends on
such share of such series shall be cumulative
shall be the date of issuance of such share, and
in the case of each other share of such series, as
otherwise provided in this Article.
(b) The redemption prices at which shares of
such series may be redeemed at the option of the
Corporation shall be an amount per share equal to
(i) $100.00 plus the annual dividend prior to June
1, 1985, (ii) $100.00 plus 50% of the annual
dividend on or after June 1, 1985 but prior to
June 1, 1990, (iii) $100.00 plus 25% of the annual
divided on or after June 1, 1990 but prior to June
1, 1995, and (iv) $100.00 plus 10% of the annual
dividend on or after June 1, 1995; provided,
however, that no share of such series shall be
redeemed prior to June 1, 1980 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
capital stock ranking equally with or prior to the
shares of said series 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 capital
stock has an effective dividend cost to the
Corporation (so computed), of less than 14.63% per
annum.
(c) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any liquidation, dissolution or winding up of
the Corporation shall be the redemption price
provided in subparagraph (b) of this paragraph
(34) in effect at the date of any voluntary
liquidation, dissolution or winding up of the
Corporation; or $100 pe share, in the event of any
involuntary liquidation, dissolution or winding up
of the Corporation.
(d)(1) A sinking fund shall be established
for the retirement of the shares of such series.
36<PAGE>
So long as there shall remain outstanding any
shares of such series, the Corporation shall, to
the extent permitted by law on June 1 in each year
commencing with the year 1980, 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 classified in para-
graph (33) hereof, at a redemption price of $100
per share. The sinking fund requirement shall be
cumulative so that if on any such June 1 the
sinking fund requirement shall not have been met,
then such sinking fund require-ment, to the extent
not met, shall become an additional sinking fund
requirement for the next succeeding June 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 subparagraph (d)(1) hereof, to redeem
at a redemption price of $100 per share an
additional number of shares equal to 5% of the
total number of shares classified in paragraph
(33) hereof. No redemption made pursuant to this
subparagraph (d)(2) shall be deemed to fulfill any
sinking fund requirement established pursuant to
subparagraph (d)(1).
(3) The Corporation shall be entitled, at
its election, to credit against any sinking fund
requirement due on June 1 of any year pursuant to
subparagraph (d)(1) of this para-graph (34),
shares of such series theretofore purchased or
otherwise acquired by the Corporation.
(e) The shares of such series shall not have
any rights to convert the same into and/or
purchase stock of any other series or class or any
other securities, or any special rights other than
those specified herein.
(35) The Corporation hereby classifies $40,000,000 par
value of the Cumulative Preferred Stock ($25 non-voting) as
a series of such Cumulative Preferred Stock ($25 non-
voting), which shall be designated as "$2.27 Cumulative
Preferred Stock", consisting of 1,600,000 shares of the par
value of $25 per share.
(36) The preferences or restrictions or qualifications
and the descriptions and terms of the shares of the $2.27
Cumulative Preferred Stock, in the respects in which the
shares of such series may vary from shares of other series
37<PAGE>
of the Cumulative Preferred Stock ($25 non-voting), shall be
as follows:
(a) The annual dividend rate for such series
shall be $2.27 per annum and in the case of each
share of such series issued prior to the record
date for the first dividend payable on the shares
of such series, the date from which dividends on
such share of such series shall be cumulative
shall be the date of issuance of such share, and
in the case of each other share of such series, as
otherwise provided in this Article.
(b) The redemption prices at which shares of
such series may be redeemed at the option of the
Corporation shall be an amount per share equal to
(i) $25 plus the annual dividend prior to March 1,
1983, (ii) $25 plus 75% of the annual dividend on
or after March 1, 1983 but prior to March 1, 1988,
(iii) $25 plus 50% of the annual dividend on or
after March 1, 1988 but prior to March 1, 1993,
(iv) $25 plus 25% of the annual dividend on or
after March 1, 1993 but prior to March 1, 1998,
and (v) $25 plus 10% of the annual dividend on or
after March 1, 1998; provided, however, that no
share of such series shall be redeemed prior to
March 1, 1983 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
capital stock ranking equally with or prior to the
shares of said series 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 capital
stock has an effective dividend cost to the
Corporation (so computed), of less than $9.46% per
annum.
(c) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any liquidation, dissolution or winding up of
the Corporation shall be the redemption price
provided in subparagraph (b) of this paragraph
(36) in effect at the date of any voluntary
liquidation, dissolution or winding up of the
Corporation; or $25 per share, in the event of any
involuntary liquidation, dissolution or winding up
of the Corporation.
38<PAGE>
(d) There shall not be any sinking fund
provided for the purchase or redemption of shares
of such series.
(e) The shares of such series shall not have
any rights to convert the same into and/or
purchase stock of any other series or class or any
other securities, or any special rights other than
those specified herein.
(37) The corporation hereby classifies $30,000,000
par value of the Cumulative Preferred Stock ($25 non-
voting) as a series of such Cumulative Preferred Stock
($25 non-voting), which shall be designated as "$3.75
Cumulative Preferred Stock", consisting of 1,200,000
shares of the par value of $25 per share.
(38) The preferences or restrictions or qualifica-
tions and the descriptions and terms of the shares of
the $3.75 Cumulative Preferred Stock, in the respects
in which the shares of such series may vary from shares
of other series of the Cumulative Preferred Stock ($25
non-voting), shall be as follows:
(a) The annual dividend rate for such series
by $3.75 per annum and in the case of each share
of such series issued prior to the record date for
the first dividend payable on the shares of such
series, the date from which dividends on such
share of such series shall be cumulative shall be
the date of issuance of such share, and in the
case of each other share of such series, as
otherwise provided in this Article.
(b) The redemption prices at which shares of
such series may be redeemed at the option of the
Corporation shall be an amount per share equal to
(i) $25 plus the annual dividend prior to March 1,
1987, (ii) $25 plus 75% of the annual dividend on
or after March 1, 1987 but prior to March 1, 1992,
(iii) $25 plus 50% of the annual dividend on or
after March 1, 1992 but prior to March 1, 1997,
(iv) $25 plus 25% of the annual dividend on or
after March 1, 1997 but prior to March 1, 2002,
and (v) $25 plus 10% of the annual dividend on or
after March 1, 2002; provided, however, that no
share of such series shall be redeemed prior to
March 1, 1987 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
capital stock ranking equally with or prior to the
39<PAGE>
shares of said series 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 capital
stock has an effective dividend cost to the
Corporation (so computed), of less than 15.34% per
annum.
(c) The preferential amounts to which the
holders of shares of such series shall be entitled
upon any liquidation, dissolution or winding up of
the Corporation shall be the redemption price pro-
vided in subparagraph (b) of this paragraph (38)
in effect at the date of any voluntary
liquidation, dissolution or winding up of the
Corporation; or $25 per share, in the event of any
involuntary liquidation, dissolution or winding up
of the Corporation.
(d)(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 March 1 in each
year commencing with the year 1987, 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
designated as $3.75 Cumulative Preferred Stock in
paragraph (37) hereof at a redemption price of $25
per share. The sinking fund requirement shall be
cumulative so that if on any such March 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 March 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 subparagraph (d)(1) hereof, to redeem
at a redemption price of $25 per share, an
additional number of shares equal to 5% of the
total number of shares designated as $3.75
Cumulative Preferred Stock in paragraph (37)
hereof. No redemption made pursuant to this sub-
paragraph (d)(2) shall be deemed to fulfill any
sinking fund requirement established pursuant to
subparagraph (d)(1).
(3) The Corporation shall be entitled, at
its election, to credit against the sinking fund
40<PAGE>
requirement due on March 1 of any year pursuant to
subparagraph (d)(1) shares of such series
theretofore purchased or otherwise acquired by the
Corporation.
(e) The shares of such series shall not have
any rights to convert the same into and/or
purchase stock of any other series or class or any
other securities, or any special rights other than
those specified herein.
(39) The Corporation hereby classifies $30,000,000
par value of the Cumulative Preferred Stock ($100 non-
voting) as a series of such Cumulative Preferred Stock
($100 non-voting), which shall be designated as "6.35%
Cumulative Preferred Stock", consisting of 300,000
shares of the par value of $100 per share.
(40) The preferences, rights, restrictions or
qualifications and the description and terms of the
6.35% Cumulative Preferred Stock, in the respects in
which the shares of such series vary from shares of
other series of the Cumulative Preferred Stock, ($100
non-voting), shall be as follows:
(a) The annual dividend rate for such series
shall be 6.35% per annum, which dividend shall be
calculated, per share, at such percentage
multiplied by $100. Dividends on all shares of
said series issued prior to the record date for
the initial dividend payable on all shares of such
series shall be cumulative from the date of
initial issuance of the shares of such series.
(b) Such series shall not be subject to
redemption prior to April 1, 2003; the regular
redemption price for shares of such series shall
be $100 per share on or after April 1, 2003, plus
an amount equal to accrued and unpaid dividends to
the date of redemption.
(c) 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 to the date of redemption.
(d)(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
41<PAGE>
the extent permitted by law, on June 1, 2003, and
on each June 1 thereafter to and including June 1,
2007, 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
Paragraph 39 hereof, at a sinking fund redemption
price of $100 per share plus accrued and unpaid
dividends to the date of redemption. The sinking
fund requirement shall be cumulative so that if on
any such June 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 June 1 on which such redemption
may be effected.
(2) The remaining shares of such series
outstanding on June 1, 2008 will be redeemed, to
the extent permitted by law, by mandatory
redemption, out of funds legally available
therefor, on such date at a mandatory redemption
price of $100 per share plus accrued and unpaid
dividends to the date of redemption.
(3) The Corporation shall be entitled, at
its election, to credit against the sinking fund
requirement due on June 1 of any year pursuant to
clause (d)(1) of this Paragraph 40, shares of such
series theretofore purchased or otherwise acquired
by the Corporation and not previously credited
against any such sinking fund requirement.
(e) The shares of such series shall not have
any rights to convert the same into and/or
purchase stock of any other series or class or any
other securities, or any special rights other than
those specified herein.
(41) The Corporation hereby classifies $40,000,000
par value of the Cumulative Preferred Stock ($100 non-
voting) as a series of such Cumulative Preferred Stock
($100 non-voting), which shall be designated as "6.02%
Cumulative Preferred Stock", consisting of 400,000
shares of the par value of $100 per share.
(42) The preferences, rights, restrictions or
qualifications and the description and terms of the
6.02% Cumulative Preferred Stock, in the respects in
which the shares of such series vary from shares of
other series of the Cumulative Preferred Stock, ($100
non-voting), shall be as follows:
42<PAGE>
(a) The annual dividend rate for such series
shall be 6.02% per annum, which dividend shall be
calculated, per share, at such percentage
multiplied by $100. Dividends on all shares of
said series issued prior to the record date for
the initial dividend payable on all shares of such
series shall be cumulative from the date of
initial issuance of the shares of such series.
(b) Such series shall not be subject to
redemption prior to October 1, 2003; the regular
redemption price for shares of such series shall
be $100 per share on or after October 1, 2003,
plus an amount equal to accrued and unpaid
dividends to the date of redemption.
(c) 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.
(d)(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 December 1, 2003,
and on each December 1 thereafter to and including
December 1, 2007, 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
Paragraph 41 hereof, at a sinking fund redemption
price of $100 per share plus accrued and unpaid
dividends to the date of redemption. The
remaining shares of such series outstanding on
December 1, 2008 will be redeemed as a final
sinking fund requirement, to the extent permitted
by law, out of funds legally available therefor,
on such date at a sinking fund redemption price of
$100 per share plus accrued and unpaid dividends
to the date of redemption. The sinking fund
requirement shall be cumulative so that if on any
such December 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 December 1 on which such
redemption may be effected.
43<PAGE>
(2) The Corporation shall be entitled, at
its election, to credit against the sinking fund
requirement due on December 1 of any year pursuant
to clause (d)(1) of this Paragraph 42, shares of
such series theretofore purchased or otherwise
acquired by the Corporation and not previously
credited against any such sinking fund
requirement.
(e) The shares of such series shall not have
any rights to convert the same into and/or
purchase stock of any other series or class or any
other securities, or any special rights other than
those specified herein.
(43) The Corporation hereby classifies $45,000,000
par value of the Cumulative Preferred Stock ($100
voting) as a series of such Cumulative Preferred Stock
($100 voting), which shall be designated as "5.90%
Cumulative Preferred Stock", consisting of 450,000
shares of the par value of $100 per share.
(44) The preferences, rights, restrictions or
qualifications and the description and terms of the
5.90% Cumulative Preferred Stock, in the respects in
which the shares of such series vary from shares of
other series of the Cumulative Preferred Stock ($100
voting), shall be as follows:
(a) The annual dividend rate for such series
shall be 5.90% per annum, which dividend shall be
calculated, per share, at such percentage
multiplied by $100. Dividends on all shares of
said series issued prior to the record date for
the initial dividend payable on all shares of such
series shall be cumulative from the date of
initial issuance of the shares of such series.
(b) Such series shall not be subject to
redemption prior to November 1, 2003; the
redemption price for shares of such series shall
be $100 per share on or after November 1, 2003,
plus an amount equal to accrued and unpaid
dividends to the date of redemption.
(c) 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.
44<PAGE>
(d)(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 January 1, 2004,
and on each January 1 thereafter to and including
January 1, 2008, 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
Paragraph 43 hereof, at a sinking fund redemption
price of $100 per share plus accrued and unpaid
dividends to the date of redemption. The
remaining shares of such series outstanding on
January 1, 2009 will be redeemed as a final
sinking fund requirement, to the extent permitted
by law, out of funds legally available therefor,
on such date at a sinking fund redemption price of
$100 per share plus accrued and unpaid dividends
to the date of redemption. The sinking fund
requirement shall be cumulative so that if on any
such January 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 January 1 on which such redemption
may be effected.
(2) The Corporation shall be entitled, at
its election, to credit against the sinking fund
requirement due on January 1 of any year pursuant
to clause (d)(1) of this Paragraph 44, shares of
such series theretofore purchased or otherwise
acquired by the Corporation and not previously
credited against any such sinking fund
requirement.
(e) The shares of such series shall not have
any rights to convert the same into and/or
purchase stock of any other series or class or any
other securities, or any special rights other than
those specified herein.
COMMON STOCK
Each share of the Common Stock shall be equal in all
respects to every other share of the Common Stock.
No holder of shares of Common Stock shall be entitled as
such as a matter of right to subscribe for or purchase any part
of any new or additional issue of stock, or securities
convertible into stock, of any class whatsoever, whether now or
45<PAGE>
hereafter authorized, and whether issued for cash, property,
services, by way of dividends or otherwise.
FIFTH: These Amended Articles of Incorporation
supersede and take the place of the heretofore existing
Agreement of Merger, dated January 21, 1955, between the
Corporation and Central Ohio Light & Power Company and any
and all amendments thereto.
</PAGE>
46<PAGE>
<PAGE>
<TABLE>
EXHIBIT 12
OHIO POWER COMPANY
Computation of Consolidated Ratio 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. . . . . . . . . . . . . . . $ 67,079 $ 71,765 $ 83,572 $ 74,121 $ 63,805
Interest on Other Long-term Debt. . . . . . . . . . . . . . . 28,425 28,575 26,611 24,510 21,453
Interest on Short-term Debt . . . . . . . . . . . . . . . . . 4,943 5,973 2,711 1,122 992
Miscellaneous Interest Charges. . . . . . . . . . . . . . . . 3,177 3,237 2,800 2,958 5,140
Estimated Interest Element in Lease Rentals . . . . . . . . . 25,000 22,800 22,800 15,300 13,900
Total Fixed Charges. . . . . . . . . . . . . . . . . . . $128,624 $132,350 $138,494 $118,011 $105,290
Earnings:
Net Income. . . . . . . . . . . . . . . . . . . . . . . . . . $179,990 $166,102 $160,553 $185,770 $162,626
Plus Federal Income Taxes . . . . . . . . . . . . . . . . . . 72,816 78,480 75,783 64,244 74,822
Plus State Income Taxes . . . . . . . . . . . . . . . . . . . 2,771 1,898 1,082 2,626 3,375
Plus Fixed Charges (as above) . . . . . . . . . . . . . . . . 128,624 132,350 138,494 118,011 105,290
Total Earnings . . . . . . . . . . . . . . . . . . . . . $384,201 $378,830 $375,912 $370,651 $346,113
Ratio of Earnings to Fixed Charges. . . . . . . . . . . . . . . 2.98 2.86 2.71 3.14 3.28
</TABLE>
<PAGE>
<TABLE>
EXHIBIT 12
OHIO POWER COMPANY
Computation of Consolidated Ratio of Earnings to Fixed Charges
and Preferred Stock Dividend Requirements Combined
(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 . . . . . . . . . . . . . . . $ 67,079 $ 71,765 $ 83,572 $ 74,121 $ 63,805
Interest on Other Long-term Debt . . . . . . . . . . . . . . . 28,425 28,575 26,611 24,510 21,453
Interest on Short-term Debt. . . . . . . . . . . . . . . . . . 4,943 5,973 2,711 1,122 992
Miscellaneous Interest Charges . . . . . . . . . . . . . . . . 3,177 3,237 2,800 2,958 5,140
Estimated Interest Element in Lease Rentals. . . . . . . . . . 25,000 22,800 22,800 15,300 13,900
Total Fixed Charges . . . . . . . . . . . . . . . . . . . 128,624 132,350 138,494 118,011 105,290
Preferred Stock Dividend Requirements (1) . . . . . . . . . . . 24,915 24,972 24,895 22,801 22 253
Total Fixed Charges and Preferred Stock
Dividend Requirements Combined. . . . . . . . . . . . . $153,539 $157,322 $163,389 $140,812 $127,543
Earnings:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . $179,990 $166,102 $160,553 $185,770 $162,626
Plus Federal Income Taxes. . . . . . . . . . . . . . . . . . . 72,816 78,480 75,783 64,244 74,822
Plus State Income Taxes. . . . . . . . . . . . . . . . . . . . 2,771 1,898 1,082 2,626 3,375
Plus Fixed Charges (as above). . . . . . . . . . . . . . . . . 128,624 132,350 138,494 118,011 105,290
Total Earnings. . . . . . . . . . . . . . . . . . . . . . $384,201 $378,830 $375,912 $370,651 $346,113
Ratio of Earnings to Fixed Charges and Preferred Stock
Dividend Requirements . . . . . . . . . . . . . . . . . . . . 2.50 2.40 2.30 2.63 2.71
(1) Represents preferred stock dividend requirements less the effect of preferred stock dividend deduction for federal
income tax purposes ($872,000 in years ended December 31, 1990 through 1992 and $847,000 in years ended December
31, 1993 and 1994) multiplied by the ratio of earnings before income taxes to net income with the preferred stock
dividend deduction added to the result of the calculation.
</TABLE>
<PAGE>
<TABLE>
Selected Consolidated Financial Data
<CAPTION>
Year Ended December 31,
1994 1993 1992 1991 1990
(in thousands)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENTS DATA:
Operating Revenues $1,738,726 $1,708,577 $1,691,597 $1,679,168 $1,778,824
Operating Expenses 1,493,853 1,440,390 1,439,826 1,412,961 1,510,112
Operating Income 244,873 268,187 251,771 266,207 268,712
Nonoperating Income 7,722 18,075 22,391 7,513 11,146
Income Before Interest
Charges 252,595 286,262 274,162 273,720 279,858
Interest Charges 89,969 100,492 113,609 107,618 99,868
Net Income 162,626 185,770 160,553 166,102 179,990
Preferred Stock Dividend
Requirements 15,301 16,990 17,115 17,112 17,804
Earnings Applicable to
Common Stock $ 147,325 $ 168,780 $ 143,438 $ 148,990 $ 162,186
<CAPTION>
December 31,
1994 1993 1992 1991 1990
(in thousands)
<S> <C> <C> <C> <C> <C>
BALANCE SHEETS DATA:
Electric Utility Plant $4,938,121 $4,802,327 $4,733,782 $4,761,356 $4,624,077
Accumulated Depreciation
and Amortization 2,077,626 1,992,082 1,916,011 1,871,711 1,776,299
Net Electric Utility Plant $2,860,495 $2,810,245 $2,817,771 $2,889,645 $2,847,778
Regulatory Assets $ 521,855 $ 496,875 $ 31,795 $ 30,305 $ 35,444
Total Assets $4,133,609 $4,116,305 $3,722,354 $3,714,425 $3,613,761
Common Stock and Paid-in
Capital $ 784,301 $ 784,301 $ 786,108 $ 786,108 $ 786,110
Retained Earnings 483,222 474,500 445,955 436,689 420,755
Total Common Shareowner's
Equity $1,267,523 $1,258,801 $1,232,063 $1,222,797 $1,206,865
Cumulative Preferred Stock:
Not Subject to Mandatory
Redemption $ 126,240 $ 126,240 $ 232,978 $ 232,978 $ 233,133
Subject to Mandatory
Redemption (a) 115,000 115,000 - - -
Total Cumulative
Preferred Stock $ 241,240 $ 241,240 $ 232,978 $ 232,978 $ 233,133
Long-term Debt (a) $1,188,989 $1,194,483 $1,366,221 $1,240,140 $1,198,314
Obligations Under Capital
Leases (a) $ 127,735 $ 97,329 $ 96,168 $ 112,802 $ 107,207
Total Capitalization and
Liabilities $4,133,609 $4,116,305 $3,722,354 $3,714,425 $3,613,761
(a) Including portion due within one year.
</TABLE>
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Shareowners and Board of
Directors of Ohio Power Company:
We have audited the accompanying consolidated balance sheets of Ohio 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 Ohio 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>
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Net Income Decreased
Net income decreased 12% in 1994 due to a fuel cost disallowance recorded
in 1994 related to the idling of a dragline at a subsidiary's strip mining
operation and the lack of full recovery of the cost of idling another
dragline in 1994 at the strip mine. In 1993 net income increased 16% due
mainly to improved retail sales reflecting a return to normal weather and
an improvement in the industrial economy in the Company's service territory,
and decreased interest expense due to the refinancing of long-term debt at
lower interest rates and decreased borrowings.
Operating Revenues and Energy Sales
Operating revenues increased 2% in 1994 and 1% in 1993. Retail sales grew
in 1994 and 1993 while wholesale sales declined in both years. The
change in operating revenues can be analyzed as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1994 1993
Amount % Amount %
Retail:
Price Variance. . . . .$ 10.0 $ (6.6)
Volume Variance . . . . 12.9 41.1
Fuel Cost Recoveries. . (17.9) 7.2
5.0 0.4 41.7 3.5
Wholesale:
Price Variance. . . . . 52.6 13.4
Volume Variance . . . . (43.3) (38.2)
Fuel Cost Recoveries. . 4.0 (0.7)
13.3 3.0 (25.5) (5.5)
Other Operating Revenues. 11.8 53.9 0.8 3.7
Total . . . . . . . .$ 30.1 1.8 $ 17.0 1.0
The increase in retail revenues in 1994 reflects a 2% increase in retail
energy sales resulting from growth in the number of residential, commercial
and industrial customers and increased usage by industrial and commercial
customers. Energy sales to residential customers remained constant in 1994
as mild weather during most of the year offset the effect of the severe
weather in January and the unseasonably hot weather in June. Reduced fuel
clause recoveries from retail customers offset much of the increase in retail
revenues. The increase in retail energy sales was offset by a 10% decline in
wholesale sales resulting in a 2% decline in net energy sales.
Although wholesale energy sales declined by 10% in 1994, wholesale revenues
increased 3% reflecting increased revenues from OPCo's share of revenues from
the American Electric Power System Power Pool (Power Pool). Power Pool
revenues increased although energy sales declined due to increased take-or-
pay capacity charges from unaffiliated utilities. Capacity charges are to
reserve a specified quantity of generating capacity and must be paid even
when the energy is not taken. The increase in capacity charges resulted from
an increase in capacity reserved under a long-term contract and short-term
contracts with unaffiliated utilities in the summer of 1994 because of a
forced outage at an unaffiliated generating unit. The increase in capacity
reservation did not lead to a corresponding increase in energy sold due to
mild weather throughout most of 1994. Also contributing to the higher
wholesale revenues were increased fuel cost recoveries from energy deliveries
to the Power Pool. Energy sales to the Power Pool are priced to compensate
the supplying Power Pool member for its out-of-pocket costs. While severe
winter weather in January 1994 and hot June weather increased short-term
wholesale sales made by the Power Pool, the mild weather throughout the
remainder of 1994, combined with increased competition in the wholesale
market, reduced the Power Pool's short-term sales for the year.
The increase in other operating revenues in 1994 was caused by additional
charges collected from unaffiliated utilities for transmission of energy as
well as revenues from residential customers for energy conservation demand-
side management programs.
The increase in retail revenues in 1993 reflects a return to more normal
hot summer weather, which increased sales to residential and commercial
customers, and an improvement in industrial sales. The increase in
industrial sales was mainly due to improved business conditions which
increased the number of industrial customers and the sales to existing
customers.
Wholesale sales decreased in 1993 largely as a result of reduced demand
from the Power Pool mainly due to the return to service of the nuclear
generating units of an affiliated company after refueling and maintenance
outages in 1992. Partially offsetting the decreased Power Pool sales were
increased short-term energy sales to unaffiliated utilities due to decreased
availability of unaffiliated generating units combined with the return to
normal hot summer weather.
Operating Expenses
Operating expenses rose 4% in 1994 after remaining unchanged in 1993.
Changes in the components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1994 1993
Amount % Amount %
Fuel. . . . . . . . . . $ 41.6 6.5 $(22.1) (3.3)
Purchased Power . . . . (11.3)(15.9) 10.2 16.7
Other Operation . . . . (11.5) (5.3) 9.3 4.4
Maintenance . . . . . . 9.8 7.0 (14.4) (9.3)
Depreciation and
Amortization. . . . . 3.8 3.0 4.2 3.4
Taxes Other Than
Federal Income Taxes. 12.7 7.5 8.5 5.3
Federal Income Taxes. . 8.4 11.8 4.9 7.5
Total Operating
Expenses. . . . . . $ 53.5 3.7 $ 0.6 -
Fuel expense increased in 1994 primarily due to a fuel cost disallowance,
lack of full recovery of the cost of idling a dragline at a subsidiary's
strip mine and an increase in net generation. As part of a May 1994 electric
fuel component (EFC) review, the PUCO ruled that the Big Muskie Dragline
lease buyout in 1993 by Central Ohio Coal Company (COCCo) was not recoverable
in the fuel period under review. In June 1994 COCCo idled another leased
dragline. Management concluded that this mining equipment would no longer be
needed due to the Muskingum River Plant's Clean Air Act Amendments of 1990
(CAAA) compliance plan to use low sulfur coal from unaffiliated sources. The
increase in generation in 1994 was due to the unavailability of an affiliated
company's nuclear generating units due to scheduled refueling and maintenance
outages in 1994. In 1993 fuel expense decreased due to a lower average cost
of fuel consumed and decreased generation reflecting the reduced Power Pool
demand as a result of the return to service of an affiliate's nuclear units
after refueling outages in 1992.
The decline in purchased power expense in 1994 and increase in 1993
resulted from a variation in Power Pool energy purchases. Reduced energy
purchases in 1994 resulted from the refueling outages of the nuclear units of
an affiliate. Purchases from the Power Pool increased in 1993 to meet the
increased retail power demand.
Other operation expense decreased in 1994 primarily due to a reduction in
the amortization of pressurized fluidized bed combustion demonstration plant
cost concurrent with a reduction in recoveries through fuel clause revenues
marking the completion of the recovery of capital costs.
Scheduled outages for boiler inspections and repairs at the generating
units caused maintenance expense to increase in 1994. In 1993 fewer sched-
uled power plant outages were responsible for the reduction in maintenance
expense.
The increase in taxes other than federal income taxes in 1994 and 1993 was
mainly due to an increase in the generation-based West Virginia business and
occupation tax reflecting an increase in generation at West Virginia power
plants. Also contributing to the increase in 1994 was increased Ohio real
and personal property taxes due to an increase in property valuation rates.
The increase in federal income tax expense attributable to operations in
1994 was primarily due to changes in certain book/tax differences accounted
for on a flow-through basis. The increase in federal income tax expense
attributable to operations in 1993 was due primarily to increased pre-tax
operating income, offset in part by favorable accrual adjustments recorded in
1992 for prior years' federal income tax returns.
Nonoperating Income and Interest Charges
The decline in nonoperating income in 1994 was due primarily to the effect
of interest income recorded in 1993 on a court ordered reversal of a prior
refund in the Company's Federal Energy Regulatory Commission jurisdiction and
on tax refunds received from the Internal Revenue Service (IRS) in March 1993
in connection with the settlement of audits of prior years' tax returns, and
the favorable effect of adopting a new accounting standard for income taxes
in January 1993. From 1992 to 1993 nonoperating income declined due to the
effect of interest income recorded in 1992 on accrued federal income tax
refunds in connection with the settlement of audits of prior years' tax
returns and on receivables from customers for the collection of prior years'
fuel costs resulting from the favorable resolution of litigation.
A refinancing program during 1993 and the early part of 1994 reduced the
average interest rate on outstanding long-term debt as well as the average
levels of long-term debt outstanding causing the decline in interest expense
in 1994 and 1993. Over the past two years management refinanced and retired
$748 million principal amount of long-term debt to take advantage of low
interest rates.
Construction Spending
Total plant and property additions were $219 million in 1994 and $197
million in 1993. Management estimates construction expenditures for the next
three years to be $432 million including expenditures necessary to meet the
requirements of the Clean Air Act Amendments of 1990. Funds for construction
of new facilities and improvement of existing facilities come from a combi-
nation of internally generated funds, short-term and long-term borrowings and
equity investments by the Company's parent, American Electric Power Company,
Inc. (AEP Co., Inc.). However, all of the construction expenditures for the
next three years are expected to be financed internally.
Capital Resources
When necessary the Company generally issues short-term debt to provide for
interim financing of capital expenditures that exceed internally generated
funds. At December 31, 1994, unused short-term lines of credit shared with
other AEP System companies of $558 million were available. A charter
provision limits short-term borrowings to $218 million. Short-term
borrowings decreased by $23 million in 1994. Periodic reductions of out-
standing short-term debt are made through issuances of long-term debt,
preferred stock and equity capital contributions by the parent company.
The Company received regulatory approval to issue up to $85 million of
long-term debt and $85 million of preferred stock. Management expects to use
the proceeds of future long-term financings to retire short-term debt,
refinance higher cost and maturing long-term debt, refund cumulative pre-
ferred stock and fund construction expenditures.
The Company presently exceeds all minimum coverage requirements for
issuance of preferred stock and long-term debt. At December 31, 1994, the
long-term debt and preferred stock coverage ratios were 4.55 and 2.58,
respectively.
Competition
In exchange for the exclusive right to provide electric generation,
transmission and distribution services within a designated service territory
at cost-based regulated prices that provide the opportunity to earn a
regulator-determined reasonable rate of return on shareholders' equity,
electric utilities are obligated to serve all customers within such service
territories. While the Company is a regulated monopoly, we have competed
historically with self-generation and with distributors of alternative
sources of energy, such as natural gas, fuel oil and coal, within our service
area. In recent years regulated electric utilities have also competed with
independent power producers for the right to build and operate new generating
plant. The primary competitive factors have been price, reliability of
service and the ability of customers to utilize sources of energy other than
electric power. The Company has maintained a favorable competitive position
on the basis of all of these factors. This is evidenced by the lack of
independent power producers and significant self generation in our service
territory. With respect to alternative energy sources, the Company believes
that the convenience and versatility of electricity and reliability of our
service coupled with the limited ability of customers to substitute other
energy sources for electric power have placed us in a favorable competitive
position. However, we continue to work to improve the competitiveness,
effectiveness and reliability of our product. The Company, for example,
markets high-efficiency heat pumps and off-peak storage water heaters which
make electricity competitive with natural gas for space and water heating.
Competition in the wholesale market, that is, the sale of bulk power to
other public and municipal utilities, is not new and has been increasing for
a number of years. This is particularly true in the short-term market. The
National Energy Policy Act of 1992 (the Energy Act) facilitated competition
in the short and long-term wholesale market since, among other things, it
authorized the Federal Energy Regulatory Commission (FERC) to order
transmission access for wholesale transactions. The principal factors in
competing for wholesale sales are price including fuel costs, availability of
capacity, transmission capability and cost, and reliability of service.
Management believes that over the years the Company has generally maintained
a favorable competitive position in these factors. However, due to the
recent availability of additional capacity of other utilities and reduced
fuel prices, price competition, particularly in the short-term wholesale
market, has been, and is expected to be important in the future.
With the passage of the Energy Act, the potential for retail wheeling,
i.e., competition for retail sales, is getting considerable attention. While
the Energy Act gave the FERC broad authority to mandate transmission access
in the wholesale market, it prohibits the FERC from ordering retail wheeling.
A number of state legislatures and state regulatory agencies have begun to
study retail wheeling with encouragement from major industrial customers.
If it occurs, increased competition may require the resolution of some
complex issues, such as stranded investment and the obligation to serve.
When a customer leaves a utility system, there is an issue of who pays for
regulatory assets, plant investment and commitments that are no longer
needed. If a customer leaves its native electric supplier and later decides
to return, the issue of whether the original local utility has an obligation
to serve the returning customer must also be addressed. If not recovered
directly from customers that choose another supplier and/or from the
remaining regulated customers, the Company like all electric utilities, will
be required to address stranded investment losses that could result from any
future loss of customers or reduced pricing from head-to-head competition.
Management intends to seek recovery of any stranded investment, including
regulatory assets, as an appropriate recovery of previously approved cost of
service.
Activity-based budgeting and cost management techniques are being developed
to enable management to cost logical work activities and services. By
examining our operations by logical work units, the cost of all major
activities can be better controlled, identified and evaluated to properly
price our products and to eliminate unnecessary activities and their cost.
Management believes these activities will enhance our ability to compete.
The development of tools and training to enable management to better manage
the costs of operations is only one of the options the Company is currently
pursuing. In 1994 the Company's management team has been:
- Reviewing and streamlining operations and staffing,
- Reducing layers of supervision,
- Expanding customer relations and service activities,
- Expanding its ability to help customers adopt new electro-technologies to
reduce their usage of electricity, and
- Expanding strategic planning and management training activities.
Management is committed to maintaining and enhancing the Company's core
business. Although the Company's relatively low cost of generation is
competitive, management is moving in "new directions" to maintain and improve
its competitive position. Whether competition expands or not, these efforts
will serve to maintain our relatively low rates and improve sales through
economic development in our service territory.
Affiliated Coal
For a number of years OPCo has been limited in its recovery of the cost of
coal produced by its affiliated mines. Under a 1992 stipulation agreement a
predetermined price of $1.64 per million Btu's was established for the cost
of coal burned at four of OPCo's generating plants (the Gavin, Mitchell,
Muskingum River and Cardinal plants) three of which burn affiliated coal from
the Meigs, Muskingum and Windsor mines. The stipulation covered the three-
year period ending November 30, 1994. Beginning December 1, 1994 an
inflation adjusted 15-year predetermined price of $1.575 per million Btu's
for coal burned at the Gavin Plant was established by the 1992 stipulation
agreement. As discussed below under "Clean Air Act" a Settlement Agreement
sets an overall predetermined EFC rate at 1.465 cents per kwh for the period
June 1, 1995 through November 30, 1998. The Gavin Plant predetermined price
remains effective through November 2009 subject to escalation from $1.575 per
million Btu's. Afterwards the price that OPCo can recover for coal from its
affiliated Meigs mine, which supplies the Gavin Plant, will be limited to the
lower of cost or the then-current market price. The predetermined prices
provide OPCo with an opportunity to recover its Ohio jurisdictional invest-
ment in and liabilities and closing costs of the Meigs, Muskingum and Windsor
mining operations to the extent the actual cost of coal burned at the Gavin
Plant is less than the predetermined prices. Based on the estimated future
cost of coal at Gavin Plant, management believes that the Company should be
able to recover, under the terms of the 1992 stipulation agreement in
conjunction with the Settlement Agreement, the Ohio jurisdictional portion
of the cost of the affiliated mining operations including mine closure costs.
As discussed below, compliance with the January 1, 2000 Phase II deadline
of the Clean Air Act Amendments of 1990 may cause the affiliated Muskingum
and Windsor mines to close. Management intends to seek from ratepayers
adequate and timely recovery of the non-Ohio jurisdictional portion of the
investment in and the liabilities and closing costs of the Muskingum and
Windsor mining operations as well as for the Meigs mining operation. The
estimated shutdown costs for the Meigs, Muskingum and Windsor mines, which
include the investment in the mines, leased asset buyouts, reclamation costs
and employee benefits, are approximately $500 million after tax at December
31, 1994 of which the non-Ohio jurisdictional portion is estimated to be $200
million after tax at December 31, 1994. In the event those costs and/or the
cost of such affiliated coal production in the interim cannot be recovered,
results of operations and possibly financial condition would be adversely
affected.
Environmental Concerns
Clean Air Act
To comply with the Clean Air Act Amendments of 1990 (CAAA) which requires
substantial reductions in sulfur dioxide and nitrogen oxides emitted from
electric generating plants, an AEP Systemwide least-cost compliance plan was
developed. The cornerstone of the compliance strategy is the installation of
flue gas desulfurization systems (scrubbers) on OPCo's two-unit Gavin Plant.
The Gavin Plant has been responsible for about 25% of the AEP System's total
sulfur dioxide emissions. By selecting scrubbers, the compliance plan allows
the continued use of Ohio high-sulfur coal at the Gavin Plant. The scrubbers
for Gavin Unit 1 were completed in December 1994 and the Unit 2 scrubbers are
expected to be completed in March 1995. The cost of the leased scrubbers is
estimated to be $675 million. The Company's capital expenditures for all
other CAAA related facilities for the next three years are estimated to be
$15 million.
The PUCO approved the compliance plan for OPCo as a least-cost compliance
strategy in November 1992, and under Ohio law the plan is deemed prudent for
subsequent PUCO rate proceedings.
Under the approved plan, fuel switching would be the compliance method at
OPCo's Muskingum River Plant in 1995 and 2000 and at OPCo's Cardinal Plant
Unit 1 in 2001 although the PUCO in a subsequent fuel cost recovery
proceeding recommended that OPCo consider employing fuel switching as early
as 1995 at the Cardinal Plant. The plants are currently supplied by OPCo's
wholly-owned, high-sulfur coal-mining subsidiaries which operate the
Muskingum and Windsor mines. Consequently, these affiliated mining
operations could shut down resulting in substantial costs.
Recovery of CAAA capital and operating compliance costs is being sought
through the rate-making process. In 1994 OPCo filed with the PUCO for an
annual revenue increase of $152.5 million with half of the requested rate
increase to recover costs associated with the Gavin Plant's scrubbers. In
February 1995 OPCo and certain other parties to the proceeding entered into a
Settlement Agreement to resolve, among other issues, the pending base rate
case and the current electric fuel component (EFC) proceeding. Under the
terms of the Settlement Agreement base rates would increase by $66 million
annually which includes recovery of the annual cost of the scrubbers; the EFC
rate would be fixed at 1.465 cents per kwh from June 1995 through November
1998; OPCo would be provided an opportunity under a 1992 predetermined price
agreement for coal burned at the Gavin Plant (which is described above) to
recover its Ohio jurisdictional portion of the investment in and the future
shutdown costs of all affiliated mines; and OPCo may proceed with its CAAA
compliance plan as filed with the PUCO. The Settlement Agreement allows the
Company to continue to operate the Muskingum and Windsor mines through the
end of Phase I, January 1, 2000. The Settlement Agreement is subject to PUCO
approval.
Efforts are continuing to obtain timely recovery of the compliance costs in
jurisdictions other than OPCo's Ohio jurisdiction, although there can be no
assurance that regulators will provide for recovery of all CAAA compliance
costs on a timely basis. Compliance with the CAAA, including potential mine
closure costs, will have an adverse effect on results of operations and
possibly financial condition if not recovered from ratepayers or through
asset dispositions.
Hazardous Material
By-products from the generation of electricity include materials such as
ash, slag and sludge. Coal combustion by-products, which constitute the
overwhelming percentage of these materials, are typically disposed of or
treated in captive disposal facilities or are beneficially utilized. In
addition, the generating plants and transmission and distribution facilities
have used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and
non-hazardous materials. The Company is currently incurring costs to
safely dispose of such substances, and additional costs could be incurred
to comply with new laws and regulations if enacted.
The Comprehensive Environmental Response, Compensation and Liability Act
(Superfund) addresses clean-up of hazardous substance disposal sites and
authorizes the United States Environmental Protection Agency (Federal EPA) to
administer the clean-up programs. OPCo has been named by the Federal EPA as
a "potentially responsible party" (PRP) for two sites as of December 31,
1994. Liability has been settled for one of these sites with no significant
effect on results of operation. In addition, there are five sites for which
OPCo has received information requests which could lead to PRP designations.
In all instances where the Company has been named a PRP or defendant, the
disposal or recycling activity of the Company was in accordance with
applicable laws and regulations. However Superfund does not recognize
compliance as a defense, but imposes strict liability on parties who fall
within its broad statutory categories. As a result, the Company has
instituted a number of policies that have raised the standard of care by
going beyond regulatory requirements where appropriate.
While the potential liability for each Superfund site must be evaluated
separately, several general statements can be made regarding such potential
liability. The disposal at a particular site by the Company is often
unsubstantiated; the quantity of material the Company disposed of at a site
was generally small; and the nature of the material generally disposed of was
non-hazardous. Typically, OPCo is one of many parties named as PRPs for a
site and, although liability is joint and several, at least some of the other
parties are financially sound enterprises. Therefore, the Company's present
estimates do not anticipate material cleanup costs for identified sites for
which OPCo has been declared a PRP. However, if for unknown reasons
significant costs are incurred for cleanup, results of operations and
possibly financial condition would be adversely affected unless the costs can
be recovered from insurance proceeds and/or, with regulatory approval, from
ratepayers.
Notice of Violation - Kammer Plant
In August 1994 the Federal EPA issued a Notice of Violation (NOV) to OPCo
alleging that the Kammer Plant has been operating in violation of applicable
federally enforceable air pollution control requirements since January 1,
1989. By law the Federal EPA may seek penalties of up to $25,000 per day for
each day of violation. A Consent Decree was negotiated and filed on November
15, 1994, which resolves that portion of the NOV relating to compliance. The
portion of the NOV relating to penalties will be addressed independently. At
this time management is unable to estimate the amount of any civil penalties
that the Federal EPA may impose. It is not anticipated that the ultimate
resolution of this matter will have a material adverse impact on results of
operations.
Global Climate Change
Concern about global climate change, or "the greenhouse effect," has been
the focus of intensive debate within the United States and around the world.
Much of the uncertainty about what effects greenhouse gas concentrations will
have on the global climate results from a myriad of factors that affect
climate. Based on the terms of a 1992 United Nations treaty that pledged the
United States to reduce greenhouse gas emissions, the Clinton Administration
developed a voluntary plan to reduce greenhouse gas emissions to 1990 levels
by the year 2000. As part of this plan, AEP is participating with the U.S.
Department of Energy and other electric utility companies in the climate
change program to limit future greenhouse gas emissions.
AEP's climate challenge program applies a policy of proactive environmental
stewardship, whereby actions are taken that make economic and environmental
sense on their own merits, irrespective of the uncertain threat of global
climate change. The plan includes energy conservation programs, improvements
in fossil generation efficiency, increased use of nuclear capacity and forest
management activities. However, should it be determined necessary to enact
significant new measures to control the burning of coal, the cost of such
measures if not recovered from ratepayers, could adversely impact results of
operations and possibly financial condition.
EMF
The potential for electric and magnetic fields (EMF) from transmission and
distribution facilities to adversely affect the public health is being exten-
sively researched. Management continues to support research to help
determine the extent, if any, to which EMF may adversely impact public
health. Our concern is that new laws imposing EMF limits may be passed or
new regulations promulgated without sufficient scientific study and evidence
to support them. As long as there is uncertainty about EMF, management and
other electric utilities will have difficulty finding acceptable sites for
their facilities, which could hamper economic growth within our operating
territory. If the present energy delivery system must be changed because of
EMF concerns, or if the courts conclude that EMF exposure harms individuals
and that utilities are liable for damages, then results of operations and
financial condition could be adversely affected, unless the costs can be
recovered from ratepayers.
Litigation
The Company is involved in a number of legal proceedings and claims. While
we are unable to predict the outcome of such litigation, it is not expected
that the resolution of these matters will have a material adverse effect on
financial condition.
Proposed Revision of the Public Utility Holding Company Act
The Public Utility Holding Company Act of 1935 (1935 Act) currently
requires that service, sales and construction contracts (other than power
sales) between companies in a registered holding company system, such as the
AEP System, be performed at cost with limited exceptions. Over the years,
the AEP System has developed numerous affiliated service, sales and
construction relationships and in some cases invested significant capital and
developed significant operations in reliance upon the ability to recover
their full costs under these provisions.
The Securities and Exchange Commission is studying the 1935 Act to
determine whether the rules to administer it should be updated or the 1935
Act should be amended or repealed. Proposals being considered to modernize
the 1935 Act could eliminate the assurance that affiliated companies will
recover their full cost of providing intra-system services. These proposals
may price such transactions at a market-based price if it is lower than cost
or generally eliminate the application of the 1935 Act to such transactions.
The effect of the adoption of these proposals on the Company'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.
The 1935 Act was premised upon the fact that utilities were vertically
integrated and operated as monopolies in an assigned territory. With the
passage of the Energy Act and the possibility of increased competition in the
electric utility industry, it is essential that the Company's ability to com-
pete not be restricted by its status as a subsidiary of a registered holding
company under the 1935 Act. To be prepared for these possible changes in the
nature of the industry, management has concluded that it supports the repeal
of the 1935 Act.
Effect of Inflation
Inflation affects the cost of replacing utility plant and the cost of
operating and maintaining such plant. The rate-making process limits
recovery to the historical cost of assets resulting in economic losses when
the effects of inflation are not recovered from customers on a timely basis.
However, economic gains that result from the repayment of long-term debt with
inflated dollars partly offset such losses.
<PAGE>
<TABLE>
Consolidated Statements of Income
<CAPTION>
Year Ended December 31,
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
OPERATING REVENUES $1,738,726 $1,708,577 $1,691,597
OPERATING EXPENSES:
Fuel 682,537 640,963 663,120
Purchased Power 59,956 71,260 61,057
Other Operation 207,292 218,793 209,511
Maintenance 150,568 140,756 155,140
Depreciation and Amortization 132,498 128,668 124,461
Taxes Other Than Federal Income Taxes 181,435 168,772 160,295
Federal Income Taxes 79,567 71,178 66,242
Total Operating Expenses 1,493,853 1,440,390 1,439,826
OPERATING INCOME 244,873 268,187 251,771
NONOPERATING INCOME 7,722 18,075 22,391
INCOME BEFORE INTEREST CHARGES 252,595 286,262 274,162
INTEREST CHARGES 89,969 100,492 113,609
NET INCOME 162,626 185,770 160,553
PREFERRED STOCK DIVIDEND REQUIREMENTS 15,301 16,990 17,115
EARNINGS APPLICABLE TO COMMON STOCK $ 147,325 $ 168,780 $ 143,438
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
Consolidated Balance Sheets
<CAPTION>
December 31,
1994 1993
(in thousands)
<S> <C> <C>
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,516,390 $2,412,973
Transmission 790,736 767,548
Distribution 798,387 766,639
General (including mining assets) 782,719 754,347
Construction Work in Progress 49,889 100,820
Total Electric Utility Plant 4,938,121 4,802,327
Accumulated Depreciation and Amortization 2,077,626 1,992,082
NET ELECTRIC UTILITY PLANT 2,860,495 2,810,245
OTHER PROPERTY AND INVESTMENTS 120,856 138,224
CURRENT ASSETS:
Cash and Cash Equivalents 30,700 20,803
Accounts Receivable:
Customers 94,984 118,133
Affiliated Companies 37,257 27,269
Miscellaneous 26,440 34,733
Allowance for Uncollectible Accounts (1,019) (960)
Fuel - at average cost 147,152 179,554
Materials and Supplies - at average cost 67,719 66,791
Accrued Utility Revenues 28,775 32,234
Prepayments 43,894 43,907
TOTAL CURRENT ASSETS 475,902 522,464
REGULATORY ASSETS 521,855 496,875
DEFERRED CHARGES 154,501 148,497
TOTAL $4,133,609 $4,116,305
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 - 40,000,000 Shares
Outstanding - 27,952,473 Shares $ 321,201 $ 321,201
Paid-in Capital 463,100 463,100
Retained Earnings 483,222 474,500
Total Common Shareowner's Equity 1,267,523 1,258,801
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 126,240 126,240
Subject to Mandatory Redemption 115,000 115,000
Long-term Debt 1,188,319 1,189,086
TOTAL CAPITALIZATION 2,697,082 2,689,127
OTHER NONCURRENT LIABILITIES 181,446 126,806
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 670 5,397
Short-term Debt 17,235 40,250
Accounts Payable - General 93,770 114,002
Accounts Payable - Affiliated Companies 28,662 26,087
Taxes Accrued 156,525 168,095
Interest Accrued 22,681 20,862
Obligations Under Capital Leases 25,314 21,916
Other 95,218 84,958
TOTAL CURRENT LIABILITIES 440,075 481,567
DEFERRED FEDERAL INCOME TAXES 695,115 725,283
DEFERRED INVESTMENT TAX CREDITS 42,828 45,795
DEFERRED CREDITS 77,063 47,727
COMMITMENTS AND CONTINGENCIES (Note 4)
TOTAL $4,133,609 $4,116,305
</TABLE>
<PAGE>
<TABLE>
Consolidated Statements of Cash Flows
<CAPTION>
Year Ended December 31,
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net Income $ 162,626 $ 185,770 $ 160,553
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization 147,347 144,292 143,960
Deferred Federal Income Taxes (9,471) (19,607) 3,002
Deferred Investment Tax Credits (3,630) (4,222) (4,138)
Deferred Fuel Costs (net) (8,030) 8,290 7,107
Changes in Certain Current Assets and
Liabilities: 21,513 (1,479) (67,141)
Accounts Receivable (net)
Fuel, Materials and Supplies 31,474 72,297 53,036
Accrued Utility Revenues 3,459 (2,557) 4,176
Accounts Payable (17,657) 53,417 873
Taxes Accrued (11,570) (1,311) 3,818
Other (net) (18,500) (43,224) (23,490)
Net Cash Flows From Operating Activities 297,561 391,666 281,756
INVESTING ACTIVITIES:
Construction Expenditures (151,255) (161,052) (197,001)
Proceeds from Sale of Property and Other 46,202 19,124 105,045
Net Cash Flows Used For Investing Activities (105,053) (141,928) (91,956)
FINANCING ACTIVITIES:
Issuance of Cumulative Preferred Stock - 113,610 -
Issuance of Long-term Debt 48,906 517,478 269,231
Retirement of Cumulative Preferred Stock - (109,187) -
Retirement of Long-term Debt (54,733) (704,959) (145,461)
Change in Short-term Debt (net) (23,015) 40,250 (133,533)
Dividends Paid on Common Stock (138,468) (140,042) (134,172)
Dividends Paid on Cumulative Preferred Stock (15,301) (17,141) (17,115)
Net Cash Flows Used For Financing Activities (182,611) (299,991) (161,050)
Net Increase (Decrease) in Cash
and Cash Equivalents 9,897 (50,253) 28,750
Cash and Cash Equivalents January 1 20,803 71,056 42,306
Cash and Cash Equivalents December 31 $ 30,700 $ 20,803 $ 71,056
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
Consolidated Statements of Retained Earnings
<CAPTION>
Year Ended December 31,
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Retained Earnings January 1 $474,500 $445,955 $436,689
Net Income 162,626 185,770 160,553
637,126 631,725 597,242
Deductions:
Cash Dividends Declared:
Common Stock 138,468 140,042 134,172
Cumulative Preferred Stock:
4.08% Series 204 204 204
4-1/2% Series 911 911 911
4.20% Series 252 252 252
4.40% Series 440 440 440
5.90% Series 2,655 199 -
6.02% Series 2,408 321 -
6.35% Series 1,905 1,196 -
7.60% Series 2,660 2,660 2,660
7-6/10% Series 2,660 2,660 2,660
7.72% Series - 691 772
7.76% Series - 3,337 3,492
8.04% Series 1,206 1,206 1,206
8.48% Series - 2,275 2,544
$2.27 Series - 789 1,974
Total Dividends 153,769 157,183 151,287
Capital Stock Expense 135 42 -
Total Deductions 153,904 157,225 151,287
Retained Earnings December 31 $483,222 $474,500 $445,955
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Organization
Ohio Power Company (the Company or OPCo) 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 northwestern, east
central, eastern and southern sections of 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, its facilities are operated
in conjunction with the facilities of certain other AEP affiliated utilities
as an integrated system.
The Company has three wholly-owned coal-mining subsidiaries: Central Ohio
Coal Company (COCCo), Southern Ohio Coal Company (SOCCo) and Windsor Coal
Company (WCCo) which conduct mining operations at the Muskingum mine, Meigs
mine and Windsor mine, respectively. Coal produced by the coal-mining
subsidiaries is sold to the Company at cost plus a Securities and Exchange
Commission (SEC) approved return on investment.
Regulation
As a member of the AEP System, OPCo is subject to regulation by the 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 OPCo and its wholly-owned
subsidiaries. Significant intercompany items are eliminated in consol-
idation.
Basis of Accounting
As a cost-based rate-regulated entity, OPCo's consolidated financial
statements reflect the actions of regulators that result in the recognition of
revenues and expenses in different time periods than enterprises that are not
rate regulated. In accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of
Regulation, regulatory assets and liabilities are recorded 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 9.75% in 1994, 9.50% in 1993 and 7.25% in 1992, and the amounts of AFUDC
accrued were $4 million in 1994, $5 million in 1993 and $4 million in 1992.
Depreciation, Depletion and Amortization
Depreciation is provided on a straight-line basis over the estimated useful
lives of property other than coal-mining property and is calculated largely
through the use of composite rates by functional class as follows:
Functional Class Composite
of Property Annual Rates
Production:
Steam-Fossil-Fired 3.6%
Hydroelectric-Conventional 2.1%
Transmission 1.7%
Distribution 3.8%
General 2.1%
Amounts to be used for removal of plant are recovered through depreciation
charges included in rates. Depreciation, depletion and amortization of coal-
mining assets is provided over each asset's estimated useful life, ranging up
to 30 years, and is calculated using the straight-line method for mining
structures and equipment. The units-of-production method is used for coal
rights and mine development costs based on estimated recoverable tonnages at a
current average rate of 57 cents per ton. These costs are included in the
cost of coal charged to fuel expense.
Cash and Cash Equivalents
Cash and cash equivalents include temporary cash investments with original
maturities of three months or less.
Operating Revenues
Revenues include the accrual of electricity consumed but unbilled at
month-end as well as billed revenues.
Fuel Costs
Historically changes in retail fuel cost are deferred until reflected in
revenues in later months through a PUCO fuel cost recovery mechanism.
However, should the PUCO approve the Settlement Agreement in connection with
the current Ohio rate proceeding (described in Note 3), such deferral will be
suspended for three and one-half years reflecting a frozen fuel cost recovery
rate factor of 1.465 cents per kwh. 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 is 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. The excess of par value
over costs of preferred stock reacquired to meet sinking fund requirements is
credited to paid-in capital.
Other Property and Investments
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:
The consolidated financial statements include assets and liabilities
recorded in accordance with regulatory actions to match expenses and revenues
in cost-based rates. The regulatory assets are expected to be recovered in
future periods through the rate-making process and the 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 $413,000 $433,822
Unamortized Loss On
Reacquired Debt 21,440 23,528
Other 87,415 39,525
Total Regulatory Assets $521,855 $496,875
Regulatory Liabilities:
Deferred Investment Tax Credits $42,828 $45,795
Deferred Gains From Emission
Allowance Sales* 35,371 1,020
Deferred Overrecovery of
Fuel Costs* 14,210 22,240
Other Regulatory Liabilities* 5,712 3,360
Total Regulatory Liabilities $98,121 $72,415
*Included in Deferred Credits on Consolidated Balance Sheets.
3. RATE MATTERS:
Rate Activity
An application was filed by OPCo on July 6, 1994 with the Public Utilities
Commission of Ohio (PUCO) seeking a $152.5 million annual base retail rate
increase to recover, among other things, the costs associated with the Gavin
Plant's flue gas desulfurization systems (scrubbers). In February 1995 OPCo
and certain other parties to the proceeding entered into a Settlement
Agreement to resolve, among other issues, the pending base rate case and the
current electric fuel component (EFC) proceeding. Under the terms of the
Settlement Agreement base rates would increase by $66 million annually which
includes recovery of the annual cost of the scrubbers; the EFC rate would be
fixed at 1.465 cents per kwh from June 1995 through November 1998; OPCo is
provided with the opportunity to recover its Ohio jurisdictional share of the
investment in and the liabilities and the future shut-down costs of all
affiliated mines as well as any fuel costs incurred above the fixed rate; and
OPCo may proceed with its Clean Air Act Amendments of 1990 (CAAA) compliance
plan as filed with the PUCO. The Settlement Agreement allows the Company to
continue to operate the Muskingum and Windsor mines. If the Muskingum and
Windsor mines are operating after November 1998, they are subject to a market
price cap and any resulting losses, for a period of two years, will be
subject to recovery under the Gavin Plant predetermined price agreement. The
Settlement Agreement is subject to PUCO approval.
Recovery of Fuel Costs
Beginning December 1, 1994 the cost of coal burned at the Gavin Plant is
subject to a 15-year predetermined price of $1.575 per million Btu's with
quarterly escalation adjustments. As discussed above the Settlement
Agreement fixes the EFC factor to 1.465 cents per kwh for the period June 1,
1995 through November 30, 1998. After November 2009 the price that OPCo can
recover for coal from its affiliated Meigs mine which supplies the Gavin
Plant will be limited to the lower of cost or the then-current market price.
The predetermined Gavin Plant agreement, in conjunction with the above-
referenced Settlement Agreement, provides OPCo with an opportunity to recover
its investment in and the liabilities and closing costs and any operating
losses incurred under the predetermined or fixed price of its affiliated
mining operations attributable to its Ohio jurisdiction to the extent the
actual cost of coal burned at the Gavin Plant is below the predetermined
price.
Based on the estimated future cost of coal burned at Gavin Plant,
management believes that the Ohio jurisdictional portion of the investment in
and liabilities and closing costs of the affiliated mining operations will be
recovered under the terms of the predetermined price agreement.
As discussed in Note 4 under "Clean Air Act" the affiliated Muskingum and
Windsor mines may have to close by January 2000 as part of compliance with
Phase II requirements of the CAAA. The Muskingum and/or Windsor mines could
close prior to January 2000 depending on the economics of continued operation
under the terms of the above Settlement Agreement. Management believes that
costs of compliance with the CAAA should be recovered from ratepayers and
intends to seek adequate and timely recovery of the non-Ohio jurisdictional
portion of the investment in and the liabilities and closing costs of the
Muskingum and Windsor mining operations as well as for the Meigs mining
operation. The estimated shutdown costs for the Meigs, Muskingum and Windsor
mines, which include the investment in the mines, leased asset buyouts,
reclamation costs and employee benefits, are approximately $500 million after
tax at December 31, 1994 of which the non-Ohio jurisdictional portion is
estimated to be $200 million after tax at December 31, 1994. Unless those
costs and the cost of affiliated coal production can be recovered from
customers through regulated rates, results of operations and possibly
financial condition would be adversely affected.
PFBC Demonstration Plant
The Company constructed a pressurized fluidized bed combustion (PFBC)
demonstration plant to demonstrate and further test this new technology for
removing sulfur from coal. An initial three-year test operation of the PFBC
plant was completed February 28, 1994; the test operation of the PFBC plant
is continuing for a fourth year. The Company qualified for funding from the
U.S. Department of Energy (DOE), the State of Ohio and technology vendors and
has received $65 million, $11 million and $418,000, from the above parties,
respectively. The Company has recovered from ratepayers the PFBC plant costs
incurred after 1986 which are not being funded by the DOE, the State or
vendors through its retail EFC at a rate of 1 mill per kwh through November
1993 and a rate of 0.3228 mill per kwh thereafter. At December 31, 1994 the
remaining unrecovered costs of the demonstration plant were $15 million
excluding the pre-1986 costs. Continued recovery through the EFC is subject
to semi-annual review and approval by the PUCO. Recovery of $14 million of
pre-1986 research and development costs have been requested from the PUCO in
the current base retail rate application and is included in the stipulation
agreement filed with the PUCO for approval, discussed above under "Rate
Activity".
4. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Substantial construction commitments have been made. Such commitments do
not presently include any expenditures for new generating capacity. The
aggregate construction program expenditures for 1995-1997 are estimated to be
$432 million.
In addition to fuel acquired from coal-mining subsidiaries and spot-
markets, the Company has long-term fuel supply contracts with unaffiliated
companies. The contracts generally contain clauses that provide for periodic
price adjustments. The Company's retail jurisdictional fuel clause mechanism
provides, with the PUCO's review and approval, for deferral and subsequent
recovery or refund of changes in the cost of fuel except for coal received at
the Gavin Plant. During the period June 1, 1995 through November 30, 1998
the retail fuel clause mechanism would be suspended under the terms of a
proposed Settlement Agreement. (See Note 3 for further details on the
application of a predetermined price). The contracts are for various terms,
the longest of which extends to 2012, and contain clauses that would release
the Company from its obligation under certain force majeure conditions.
Clean Air Act
The CAAA requires significant reductions in sulfur dioxide and nitrogen
oxide emissions from various AEP System generating plants. The first phase
of reductions in sulfur dioxide emissions (Phase I) began on January 1, 1995
and the second, more restrictive phase (Phase II) begins January 1, 2000.
The law also established a permanent nationwide cap on sulfur dioxide
emissions after 1999.
In 1992 the PUCO approved a systemwide Phase I CAAA compliance plan. The
AEP System's compliance plan centers around the compliance method selected
for the Company's two-unit 2,600 mw Gavin Plant which has emitted about 25%
of the AEP System's total sulfur dioxide emissions. Under an Ohio law,
utilities could obtain advance PUCO approval of a least-cost compliance plan
which would be deemed prudent in subsequent PUCO rate proceedings.
The PUCO approved least-cost plan set forth compliance measures for the
System's affected generating units, which included: installing leased flue
gas desulfurization equipment (scrubbers) to burn Ohio high-sulfur coal at
Gavin; designating Gavin's coal supply sources to include the affiliated
Meigs mine at a reduced operating capacity and under predetermined prices,
new long-term contracts with unaffiliated sources and spot market purchases;
and switching from high-sulfur coal to an alternate fuel at other System
units.
Fuel switching may result in the shutdown of OPCo's affifliated Muskingum
and Windsor coal-mining operations. To meet Phase I compliance, fuel
switching is necessary at one of the Muskingum River generating units
beginning in 1995. In order to comply with Phase II requirements on a least-
cost basis, fuel switching is currently planned at all the Muskingum River
generating units in January 2000 and at the Cardinal generating unit in
January 2001.
As a result of the aforementioned PUCO approval of the Company's
least-cost compliance plan, OPCo entered into an agreement in 1992 for
construction and lease of the Gavin Plant scrubbers with JMG Funding
Partnership, an unaffiliated company. The lease will be accounted for as an
operating lease.
Management currently expects that the cost of the leased scrubbers will be
approximately $675 million. The scrubbers on Gavin Plant Unit 1 commenced
operation in December 1994 and the Unit 2 scrubbers are expected to commence
operation in March 1995. Capital expenditures for the Company's other CAAA-
related environmental protection facilities for the next three years are
estimated to be $15 million.
Recovery of compliance costs is being sought and will be sought through
the rate-making process. As detailed in Note 3 under "Rate Activity", OPCo
has filed an application with the PUCO seeking recovery of its cost of CAAA
compliance and entered into a Settlement Agreement regarding this rate
request. This Settlement Agreement provides, among other things, for OPCo to
recover the annual lease cost of the scrubbers and other compliance costs and
provides OPCo with an opportunity to recover its Ohio jurisdictional share of
its investment in and the liabilities and closing costs of the affiliated
Muskingum and Windsor mining operations to the extent the actual cost of coal
burned at the Gavin Plant is below a predetermined price. The Settlement
Agreement requires PUCO approval. The Company intends to also seek timely
recovery of all compliance costs, including mine shutdown costs, from its
non-Ohio jurisdictional customers. There can be no assurance that regulators
will provide for recovery of all CAAA compliance costs on a timely basis.
Compliance with the CAAA, including potential mine closure costs, will have
an adverse effect on results of operations and possibly financial condition
unless the cost can be recovered from ratepayers and/or from asset
dispositions.
Other Environmental Matters
The 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.
The Company has been named a "potentially responsible party" (PRP) by the
United States Environmental Protection Agency (Federal EPA) for two disposal
sites and has received information requests for five other sites. Although
the potential liability associated with each site must be evaluated indi-
vidually, several general statements can be made regarding such potential
liability.
Whether the Company disposed of hazardous substances at a particular site
is often unsubstantiated; the quantity of material disposed of at a site was
generally small; and the nature of the material generally disposed of was
non-hazardous. Typically, the Company is one of many parties named PRPs for
a site and, although liability is joint and several, generally at least some
of the other parties are financially sound enterprises. Therefore,
management does not anticipate material cleanup costs for identified disposal
sites. However, if for unknown reasons, significant costs are incurred for
cleanup, results of operations and financial condition would be adversely
affected unless the costs can be recovered from insurance proceeds and/or
customers.
Kammer Plant
In August 1994 the United States Environmental Protection Agency (Federal
EPA) issued a Notice of Violation (NOV) to OPCo alleging that the Kammer
Plant has been operating in violation of applicable federally enforceable air
pollution control requirements since January 1, 1989. By law, civil penal-
ties of up to $25,000 per day may be imposed for each day of violation. A
Consent Decree was negotitated and filed on November 15, 1994 which resolves
that portion of the NOV relating to compliance. The portion of the NOV
relating to penalties will be addressed independently. At this time
management is unable to estimate the amount of any civil penalties that may
be imposed by the Federal EPA. It is not anticipated that the ultimate
resolution of this matter will have a material adverse impact on results of
operations.
Litigation
The Company is involved in a number of other legal proceedings and claims.
While management is unable to predict the outcome of litigation, it is not
expected that the resolution of these matters will have a material adverse
effect on financial condition.
5. 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. The Company is a net supplier to the
pool and, therefore, receives net capacity credits from the Power Pool.
Operating revenues include $261.1 million in 1994, $255.7 million in 1993
and $291.9 million in 1992 for supplying energy and capacity to the Power
Pool. Purchased power expense includes charges of $20.9 million in 1994,
$38.9 million in 1993 and $29.1 million in 1992 for energy received from the
Power Pool.
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 $98.4 million in 1994, $97.3 million in
1993 and $79.8 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 $21.7
million in 1994, $12.7 million in 1993 and $14.6 million in 1992. Revenues
from these transactions are included in the above Power Pool wholesale
operating revenues.
Purchased power expense includes $2.1 million in 1994, $7.1 million in
1993
and $5.9 million in 1992 of energy bought from the Ohio Valley Electric
Corporation, an affiliated company that is not a member of the Power Pool.
Operating revenues include energy sold directly to Wheeling Power Company
in the amounts of $56.8 million in 1994 $57.6 million in 1993 and $62.1
million in 1992. Wheeling Power Company is an affiliated distribution
utility that is not a member of the Power Pool.
AEP System companies participate in a transmission equalization agreement.
This agreement combines certain AEP System companies' investments in
transmission facilities and shares the costs of ownership in proportion to
the System companies' respective peak demands. Pursuant to the terms of the
agreement, other operating expense includes equalization charges of $14.3
million, $16.8 million and $14.5 million in 1994, 1993 and 1992, respective-
ly.
Coal-transportation costs paid to affiliated companies aggregate
approximately $7.9 million, $8.6 million and $4 million in 1994, 1993 and
1992, respectively. These charges are included in fuel expense. The prices
charged by the affiliates are computed in accordance with orders issued by
the SEC.
The Company and an affiliate, Appalachian Power Company, jointly own
certain facilities at two power plants. The costs of operating these
facilities are apportioned between the owners based on ownership interests.
The Company's share of these costs is included in the appropriate expense
accounts on the Consolidated Statements of Income and the investment is
included in electric utility plant on the Consolidated Balance Sheet.
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.
<PAGE>
6. FEDERAL INCOME TAXES:
<TABLE>
The details of federal income taxes as reported are as follows:
<CAPTION>
Year Ended December 31,
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Charged (Credited) to Operating Expenses (net):
Current $89,638 $ 83,471 $57,487
Deferred (8,237) (10,477) 10,487
Deferred Investment Tax Credits (1,834) (1,816) (1,732)
Total 79,567 71,178 66,242
Charged (Credited) to Nonoperating Income (net):
Current (1,715) 4,602 19,432
Deferred (1,234) (9,130) (7,485)
Deferred Investment Tax Credits (1,796) (2,406) (2,406)
Total (4,745) (6,934) 9,541
Total Federal Income Taxes as Reported $74,822 $ 64,244 $75,783
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.
<CAPTION>
Year Ended December 31,
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Net Income $162,626 $185,770 $160,553
Federal Income Taxes 74,822 64,244 75,783
Pre-tax Book Income $237,448 $250,014 $236,336
Federal Income Taxes on Pre-tax Book Income at
Statutory Rate (35% in 1994 and 1993 and 34% in 1992) $83,107 $ 87,505 $80,354
Increase (Decrease) in Federal Income Taxes
Resulting From the Following Items:
Depreciation 12,670 9,644 10,179
Removal Costs (5,775) (9,030) (5,651)
Corporate Owned Life Insurance (7,552) (9,318) (9,010)
Sale of Martinka Mining Property - - 7,825
Investment Tax Credits (net) (3,630) (4,221) (3,986)
Other (3,998) (10,336) (3,928)
Total Federal Income Taxes as Reported $74,822 $ 64,244 $75,783
Effective Federal Income Tax Rate 31.5% 25.7% 32.1%
</TABLE>
<PAGE>
The following tables show the elements of the net deferred tax liabiity
and the significant temporary differences that gave rise to it:
December 31,
1994 1993
(in thousands)
Deferred Tax Assets $ 141,755 $ 134,642
Deferred Tax Liabilities (836,870) (859,925)
Net Deferred Tax Liabilities $(695,115) $(725,283)
Property Related Temporary
Differences $(583,884) $(589,901)
Amounts Due From Customers For
Future Federal Income Taxes (144,550) (151,838)
All Other (net) 33,319 16,456
Total Net Deferred
Tax Liabilities $(695,115) $(725,283)
The Company and its subsidiaries join in the filing of a consolidated
federal income tax return with their affiliated companies in the AEP System.
The allocation of the AEP System's current consolidated federal income tax to
the System companies is in accordance with SEC rules under the 1935 Act.
These rules permit the allocation of the benefit of current tax losses to the
System companies giving rise to them in determining their current tax ex-
pense. The tax loss of the System parent company, AEP Co., Inc., is
allocated to its subsidiaries with taxable income. With the exception of the
loss of the parent company, the method of allocation approximates a separate
return result for each company in the consolidated group.
The AEP System has settled with the Internal Revenue Service (IRS) all
issues from the audits of the consolidated federal income tax returns for the
years prior to 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.
7. BENEFIT PLANS:
AEP System Pension Plan
The Company and its subsidiaries participate in the AEP pension plan, a
trusteed, noncontributory defined benefit plan covering all employees meeting
eligibility requirements, except participants in the United Mine Workers of
America (UMWA) pension plans. Benefits are based on service years and
compensation levels. 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 the Employee Retirement Income Security Act of 1974.
The Company's share of net pension cost of the AEP System Pension Plan for
the years ended December 31, 1994, 1993 and 1992 was $5.8 million, $5.9
million and $8 million, respectively.
AEP System Savings Plan
An employee savings plan is offered to non-UMWA employees which allows
participants to contribute up to 17% of their salaries into three investment
alternatives, including AEP Co., Inc. common stock. An employer matching
contribution, equaling one-half of the employees' contribution to the plan up
to a maximum of 3% of the employees' base salary, is invested in AEP Co.,
Inc. common stock. The employer's annual contributions totaled $4.3 million
in 1994, 1993 and 1992.
UMWA Pension Plans
The Company's coal-mining subsidiaries provide UMWA pension benefits for
UMWA employees meeting eligibility requirements. Benefits are based on age
at retirement and years of service. As of June 30, 1994, the UMWA actuary
estimates that the coal-mining subsidiaries' share of the UMWA pension plans
unfunded vested liabilities was approximately $46 million. In the event the
coal-mining subsidiaries cease or significantly reduce mining operations or
contributions to the UMWA pension plans, a withdrawal obligation may be
triggered for all or a portion of their share of the unfunded vested
liability. Contributions are based on the number of hours worked, are
expensed when paid and totaled $1.6 million in both 1994 and 1993 and $2.1
million in 1992.
Postretirement Benefits Other Than Pensions
The AEP System provides certain other benefits for retired employees.
Substantially all non-UMWA employees are eligible for postretirement health
care and life insurance if they have at least 10 service years and are age 55
at retirement. Prior to 1993, net costs of these benefits were recognized as
an expense when paid and totaled $3.1 million in 1992.
Postretirement medical benefits for the Company's UMWA employees who have
retired or will retire after January 1, 1976 are the liability of the coal-
mining subsidiaries. They are eligible for postretirement medical and life
insurance benefits if they have at least 10 service years and are age 55 at
retirement. Non-active UMWA employees become eligible at age 55 if they have
20 service years. The cost of health care benefits for this group was
expensed when paid in 1992 and totaled $16.5 million.
SFAS 106, Employers' Accounting for Postretirement Benefits Other Than
Pensions, was adopted in January 1993 for the Company's aggregate liability
for postretirement benefits other than pensions (OPEB). SFAS 106 requires
the accrual of the present value liability for OPEB costs during the
employee's service years. Costs for the accumulated postretirement benefits
earned and not recognized at adoption are being recognized, in accordance
with SFAS 106, as a transition obligation over 20 years. OPEB costs are
determined by the application of AEP System actuarial assumptions to each
company's employee complement. The Company's annual accrued costs for 1994
and 1993 required by SFAS 106 for employees and retirees, which includes the
recognition of one-twentieth of the prior service transition obligation, was
$33.7 and $34.2 million, respectively.
A Voluntary Employees Beneficiary Association (VEBA) trust fund for OPEB
benefits for all non-UMWA employees was established and a corporate owned
life insurance (COLI) program was implemented, except where restricted by
state law. The insurance policies have a substantial cash surrender value
which is recorded, net of equally substantial policy loans, as other property
and investments. For the PUCO and FERC jurisdictions where OPEB recovery has
not been approved and rates are insufficient to absorb these additional
costs, the funding policy is to contribute cash generated by the COLI
program. Contributions to the VEBA trust fund, including amounts funded by
the COLI program were $3.3 million in 1994, $4.8 million in 1993 and $1.5
million in 1992.
The Company received authority from the FERC and PUCO to defer the
increased OPEB costs which are not being currently recovered in rates.
Future recovery of the FERC jurisdictional share of these deferrals and
annual ongoing OPEB costs will be sought in the next FERC base rate filing.
Recovery of the PUCO jurisdictional share of annual ongoing OPEB costs and
amortization over four years of previously deferred OPEB costs was requested
in the July 1994 base rate filing discussed in Note 3. At December 31, 1994
and 1993, $18.7 million and $9 million, respectively of such OPEB costs were
deferred.
Several UMWA health plans pay the postretirement medical benefits for the
Company's UMWA retirees who retired before January 2, 1976 and their
survivors plus retirees and others whose last employer is no longer a
signatory to the UMWA contract or is no longer in business. The UMWA health
plans are funded by payments from current and former UMWA wage agreement
signatories, the 1950 UMWA Pension Plan surplus and the Abandoned Mine Land
Reclamation Fund Surplus. Required annual payments to the UMWA health funds
made by the coal-mining subsidiaries were recognized as expense when paid and
totaled $800,000 in 1994, $1.2 million in 1993 and $9.8 million in 1992.
By law excess Black Lung Trust funds may be used to pay certain
postretirement medical benefits under one of the UMWA health plans. Excess
AEP Black Lung Trust funds used to reimburse the Company's coal companies for
medical benefits totaled $6.7 million in 1994 and $8 million in 1993. The
Company's coal mining subsidiaries share of the excess Black Lung Trust funds
at December 31, 1994 and 1993 was $12 million and $17 million, respectively.
<PAGE>
8. LEASES:
Leases of property, plant and equipment are for periods up to 30 years and
require payments of related property taxes, maintenance and operating costs.
The majority of the leases have purchase or renewal options and will be
renewed or replaced by other leases.
Lease rentals are primarily charged to operating expenses in accordance
with rate-making treatment. The components of rental cost are as follows:
Year Ended December 31,
1994 1993 1992
(in thousands)
Operating Leases $20,976 $26,432 $43,209
Amortization of
Capital Leases 23,355 20,352 20,034
Interest on
Capital Leases 6,955 6,539 8,371
Total Rental Cost $51,286 $53,323 $71,614
Properties under capital leases and related obligations on the
Consolidated Balance Sheets are as follows:
December 31,
1994 1993
(in thousands)
Electric Utility Plant:
Production $ 21,971 $ 5,248
General (including mining assets) 187,773 160,929
Total Electric Utility Plant 209,744 166,177
Accumulated Amortization 87,079 84,400
Net Electric Utility Plant 122,665 81,777
Other Property 5,070 15,552
Net Property under
Capital Leases $127,735 $ 97,329
Obligations under Capital Leases:
Noncurrent Liability $102,421 $75,413
Liability Due Within One Year 25,314 21,916
Total Capital Lease Obligations $127,735 $97,329
<PAGE>
Properties under operating leases and related obligations are not included
in the Consolidated Balance Sheets.
Future minimum lease rentals consisted of the following at December 31,
1994:
Non-
Cancelable
Capital Operating
Leases Leases
(in thousands)
1995 $ 32,103 $ 67,738
1996 26,330 66,681
1997 21,315 64,897
1998 16,710 63,205
1999 12,625 62,073
Later Years 44,496 692,323
Total Future Minimum
Lease Rentals 153,579 $1,016,917
Less Estimated
Interest Element 25,844
Estimated Present Value
of Future Minimum
Lease Rentals $127,735
9. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1994 1993 1992
(in thousands)
Cash was paid for:
Interest (net of
capitalized
amounts) $ 85,496 $101,659 $112,365
Income Taxes 107,514 95,684 83,164
Noncash Acquisitions
Under Capital Leases
were 65,008 33,097 23,036
In connection with a 1992 sale of coal-mining properties, a coal-mining
subsidiary is receiving cash payments of $77 million over a 13-1/2 year
period which had a net present value of $44.6 million at the time of the
sale.
<PAGE>
10. COMMON SHAREOWNER'S EQUITY:
Mortgage indentures, debentures, charter provisions and orders of
regulatory authorities place various restrictions on the use of retained
earnings for the payment of cash dividends on common stock. At December 31,
1994, $156.5 million of retained earnings were restricted. Regulatory
approval is required to pay dividends out of paid-in capital.
In 1993, charges to paid-in capital of $1.8 million represented the
issuance expense of new cumulative preferred stock and the write-off of
premiums on retired cumulative preferred stock. There were no other material
transactions affecting common stock and paid-in capital in 1994, 1993 or
1992.
11. CUMULATIVE PREFERRED STOCK:
At December 31, 1994, authorized shares of cumulative preferred stock were
as follows:
Par Value Shares Authorized
$100 3,762,403
25 4,000,000
Unissued shares of the cumulative preferred stock may or may not possess
mandatory redemption characteristics upon issuance. The cumulative preferred
stock is callable at the price indicated plus accrued dividends. The
involuntary liquidation preference is par value.
In 1993 the Company redeemed and cancelled all of the outstanding shares
of the following series of cumulative preferred stock not subject to
mandatory redemption: 7.72%, 100,000 shares; 7.76%, 450,000 shares; 8.48%,
300,000 shares; and $2.27, 869,500 shares.
<TABLE>
A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
<CAPTION>
Call Price Shares Amount
December 31, Par Outstanding December 31,
Series 1994 Value December 31, 1994 1994 1993
(in thousands)
<S> <C> <C> <C> <C> <C>
4.08% $103 $100 50,000 $ 5,000 $ 5,000
4-1/2% 110 100 202,403 20,240 20,240
4.20% 103.20 100 60,000 6,000 6,000
4.40% 104 100 100,000 10,000 10,000
7.60% 102.26 100 350,000 35,000 35,000
7-6/10% 102.11 100 350,000 35,000 35,000
8.04% 102.58 100 150,000 15,000 15,000
$126,240 $126,240
B. Cumulative Preferred Stock Subject to Mandatory Redemption:
<CAPTION>
Shares Amount
Par Outstanding December 31,
Series(a) Value December 31, 1994 1994 1993
(in thousands)
<S> <C> <C> <C> <C>
5.90% (b) $100 450,000 $ 45,000 $ 45,000
6.02% (c) 100 400,000 40,000 40,000
6.35% (d) 100 300,000 30,000 30,000
$115,000 $115,000
(a) Not callable until after 2002. There are no aggregate sinking fund
provisions through 1999.
(b) Shares issued November 1993. Commencing in 2004 and continuing through
the year 2008, a sinking fund for the 5.90% cumulative preferred stock will
require the redemption of 22,500 shares each year and the redemption of the
remaining shares outstanding on January 1, 2009, in each case at $100 per
share.
(c) Shares issued October 1993. Commencing in 2003 and continuing through
the year 2007, a sinking fund for the 6.02% cumulative preferred stock will
require the redemption of 20,000 shares each year and the redemption of the
remaining shares outstanding on December 1, 2008, in each case at $100 per
share.
(d) Shares issued April 1993. Commencing in 2003 and continuing through the
year 2007, a sinking fund for the 6.35% cumulative preferred stock will
require the redemption of 15,000 shares each year and the redemption of the
remaining shares outstanding on June 1, 2008, in each case at $100 per share.
</TABLE>
<PAGE>
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 $ 839,366 $ 842,981
Installment Purchase
Contracts 232,227 232,103
Notes Payable 90,000 95,000
Sinking Fund Debentures 17,478 17,884
Other 9,918 6,515
1,188,989 1,194,483
Less Portion Due Within
One Year 670 5,397
Total $1,188,319 $1,189,086
First mortgage bonds outstanding were as follows:
December 31,
1994 1993
(in thousands)
% RateDue
5 1996 - January 1 $ 38,759 $ 38,759
6-1/2 1997 - August 1 46,620 46,620
6-3/4 1998 - March 1 55,661 55,661
8.10 2002 - February 15 50,000 50,000
8.25 2002 - March 15 50,000 50,000
7-5/8 2002 - April 1 16,910 16,910
7-3/4 2002 - October 1 24,000 24,000
6.75 2003 - April 1 40,000 40,000
6.875 2003 - June 1 40,000 40,000
6.55 2003 - October 1 40,000 40,000
6.00 2003 - November 1 25,000 25,000
6.15 2003 - December 1 50,000 50,000
9-7/8 2020 - August 1 46,161 50,000
9.625 2021 - June 1 50,000 50,000
8.80 2022 - February 10 50,000 50,000
8.75 2022 - June 1 50,000 50,000
7.75 2023 - April 1 40,000 40,000
7.85 2023 - June 1 40,000 40,000
7.375 2023 - October 1 40,000 40,000
7.10 2023 - November 1 25,000 25,000
7.30 2024 - April 1 25,000 25,000
Unamortized Discount (net) (3,745) (3,969)
Total $839,366 $842,981
Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee or, in lieu thereof, certification of unfunded
property additions.
<PAGE>
Sinking fund debentures outstanding were as follows:
December 31,
1994 1993
(in thousands)
5-1/8% Series
due 1996 - January 1 $ 8,297 $ 8,691
6-5/8% Series
due 1997 - August 1 4,253 4,253
7-7/8% Series
due 1999 - March 1 4,905 4,905
Unamortized Premium 23 35
Total $17,478 $17,884
Prior to December 31, 1994 sufficient principal amounts of debentures had
been reacquired to satisfy all future sinking fund requirements. The Company
may make additional sinking fund payments of up to $1.5 million annually.
The notes payable have due dates ranging from January 1996 to January 2001
with variable and fixed interest payable quarterly at rates ranging from
5.66% to 7.19%.
Installment purchase contracts have been entered into in connection with
the issuance of pollution control revenue bonds by governmental authorities
as follows:
December 31,
1994 1993
(in thousands)
Ohio Air Quality Development
7.4% Series B
due 2009 - August 1 $ 50,000 $ 50,000
Mason County, West Virginia:
5.45% Series B
due 2016 - December 1 50,000 50,000
Marshall County, West Virginia:
5.45% Series B
due 2014 - July 1 50,000 50,000
5.90% Series D
due 2022 - April 1 35,000 35,000
6.85% Series C
due 2022 - June 1 50,000 50,000
Unamortized Discount (2,773) (2,897)
Total $232,227 $232,103
Under the terms of the installment purchase contracts, the Company is
required to pay amounts sufficient to enable the payment of interest on and
the principal (at stated maturities and upon mandatory redemption) of related
pollution control revenue bonds issued to finance the construction of
pollution control facilities at certain plants.
<PAGE>
At December 31, 1994, annual consolidated long-term debt payments,
excluding premium or discount, are as follows:
Principal Amount
(in thousands)
1995 $ 670
1996 56,046
1997 71,544
1998 73,012
1999 20,575
Later Years 973,637
Total $1,195,484
Short-term debt borrowings are limited by provisions of the 1935 Act to
$250 million and further limited by charter provisions to $218 million.
Lines of credit are shared with other AEP System companies and at December
31, 1994 and 1993 were available in the amounts of $558 million and $537
million, respectively. Commitment fees of approximately 3/16 of 1% of the
unused short-term lines of credit are paid each year to the banks to maintain
the lines of credit. Outstanding short-term debt consisted of:
Balance Weighted
Outstanding Average
(in thousands) Interest Rate
December 31, 1994:
Notes Payable $ 85 6.5%
Commercial Paper 17,150 6.3
Total $17,235 6.3
December 31, 1993:
Notes Payable $ 2,250 3.1%
Commercial Paper 38,000 3.6
Total $40,250 3.6
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. Fair values for preferred stock
subject to mandatory redemption were $98.2 million and $112.6 million and for
long-term debt were $1.11 billion and $1.25 billion at December 31, 1994 and
1993, respectively. The carrying amounts for preferred stock subject to
mandatory redemption were $115 million and for long-term debt were $1.2
billion at both December 31, 1994 and 1993. Fair values are based on quoted
market prices for the same or similar issues and the current dividend or
interest rates offered for instruments of the same remaining maturities.
<PAGE>
14. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
(in thousands)
1994
March 31 $487,041 $74,860 $54,235
June 30 417,352 55,755 33,976
September 30 429,496 62,190 42,398
December 31 404,837 52,068 32,017
1993
March 31 430,158 68,965 49,287
June 30 410,923 62,899 39,499
September 30 457,532 65,100 43,643
December 31 409,964 71,223 53,341
<PAGE>
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration
Statement Nos. 33-50373, 33-50139 and 33-53133 of Ohio 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 Ohio 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
OHIO POWER COMPANY
Annual Report on Form lO-K for the Fiscal Year Ended
December 31, 1994
The undersigned directors of OHIO POWER COMPANY, an Ohio
corporation (the "Company"), do hereby constitute and appoint E.
LINN DRAPER, JR., G. P. MALONEY and P. J. DeMARIA, and each of
them, their attorneys-in-fact and agents, to execute for them,
and in their names, and in any and all of their capacities, the
Annual Report of the Company on Form lO-K, pursuant to Section 13
of the Securities Exchange Act of 1934, for the fiscal year ended
December 31, 1994, and any and all amendments thereto, and to
file the same, with all exhibits thereto and other documents in
connection therewith, with the Securities and Exchange
Commission, granting unto said attorneys-in-fact and agents, and
each of them, full power and authority to do and perform every
act and thing required or necessary to be done, as fully to all
intents and purposes as the undersigned might or could do in
person, hereby ratifying and confirming all that said attorneys-
in-fact and agents, or any of them, may lawfully do or cause to
be done by virtue hereof.
IN WITNESS WHEREOF, the undersigned have signed these
presents this 22nd day of February, 1995.
/s/ P. J. DeMaria /s/ 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> 0000073986
<NAME> OHIO 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> 2,860,495
<OTHER-PROPERTY-AND-INVEST> 120,856
<TOTAL-CURRENT-ASSETS> 475,902
<TOTAL-DEFERRED-CHARGES> 154,501
<OTHER-ASSETS> 521,855
<TOTAL-ASSETS> 4,133,609
<COMMON> 321,201
<CAPITAL-SURPLUS-PAID-IN> 463,100
<RETAINED-EARNINGS> 483,222
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,267,523
115,000
126,240
<LONG-TERM-DEBT-NET> 1,188,319
<SHORT-TERM-NOTES> 85
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 17,150
<LONG-TERM-DEBT-CURRENT-PORT> 670
0
<CAPITAL-LEASE-OBLIGATIONS> 102,421
<LEASES-CURRENT> 25,314
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,290,887
<TOT-CAPITALIZATION-AND-LIAB> 4,133,609
<GROSS-OPERATING-REVENUE> 1,738,726
<INCOME-TAX-EXPENSE> 82,942
<OTHER-OPERATING-EXPENSES> 1,410,911
<TOTAL-OPERATING-EXPENSES> 1,493,853
<OPERATING-INCOME-LOSS> 244,873
<OTHER-INCOME-NET> 7,722
<INCOME-BEFORE-INTEREST-EXPEN> 252,595
<TOTAL-INTEREST-EXPENSE> 89,969
<NET-INCOME> 162,626
15,301
<EARNINGS-AVAILABLE-FOR-COMM> 147,325
<COMMON-STOCK-DIVIDENDS> 138,468
<TOTAL-INTEREST-ON-BONDS> 63,805
<CASH-FLOW-OPERATIONS> 297,561
<EPS-PRIMARY> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1> All common stock owned by parent company; no EPS required.
</FN>
</TABLE>
