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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, 1993
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ________ to ________
----------------
COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER
FILE NUMBER ADDRESS; AND TELEPHONE NUMBER IDENTIFICATION NO.
----------- ----------------------------------- ------------------
1-3525 American Electric Power Company, Inc. 13-4922640
(A New York Corporation)
1 Riverside Plaza
Columbus, Ohio 43215
Telephone (614) 223-1000
0-18135 AEP Generating Company 31-1033833
(An Ohio Corporation)
1 Riverside Plaza
Columbus, Ohio 43215
Telephone (614) 223-1000
1-3457 Appalachian Power Company 54-0124790
(A Virginia Corporation)
40 Franklin Road, S.W.
Roanoke, Virginia 24011
Telephone (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 41105
Telephone (606) 327-1111
1-6543 Ohio Power Company 31-4271000
(An Ohio Corporation)
301 Cleveland Avenue, S.W.
Canton, Ohio 44702
Telephone (216) 456-8173
----------------
AEP Generating Company, Columbus Southern Power Company and Kentucky Power
Company meet the conditions set forth in General Instruction J(1)(a) and (b) of
Form 10-K and are therefore filing this Form 10-K with the reduced disclosure
format specified in General Instruction J(2) to such Form 10-K.
----------------
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X . No .
---- ----
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED
---------- ------------------- ---------------------
AEP Generating Company None
American Electric Power Common Stock,
Company, Inc. $6.50 par value............... New York Stock 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%....................... Midwest Stock Exchange
7.08%........................ New York Stock Exchange
Kentucky Power Company None
Ohio Power Company Cumulative Preferred Stock,
Voting, $100 par value:
7.60%........................ New York Stock Exchange
7 6/10%...................... New York Stock Exchange
8.04%........................ New York Stock Exchange
Indicate by check mark if disclosure of delinquent fil ers 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
-----
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
REGISTRANT TITLE OF EACH CLASS
---------- -------------------
AEP Generating Company None
American Electric Power None
Company, Inc.
Appalachian Power None
Company
Columbus Southern None
Power Company
Indiana Michigan None
Power Company
Kentucky Power Company None
Ohio Power Company 4 1/2% Cumulative Preferred Stock, Voting, $100 par
value
AGGREGATE MARKET VALUE NUMBER OF SHARES
OF VOTING STOCK HELD OF COMMON STOCK
BY NON-AFFILIATES OF OUTSTANDING OF
THE REGISTRANTS AT THE REGISTRANTS AT
FEBRUARY 4, 1994 FEBRUARY 4, 1994
---------------------- ------------------
AEP Generating Company None 1,000
($1,000 par value)
American Electric Power $6,296,000,000 184,535,000
Company, Inc. ($6.50 par value)
Appalachian Power Company 43,000,000 13,499,500
(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 Company None 1,009,000
($50 par value)
Ohio Power Company 154,000,000 27,952,473
(no par value)
NOTE ON MARKET VALUE OF VOTING STOCK HELD BY NON-AFFILIATES
All of the common stock of AEP Generating Company, Appalachian Power Company,
Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power
Company and Ohio Power Company is owned by American Electric Power Company,
Inc. (see Item 12 herein). The voting stock owned by non-affiliates of (i)
Appalachian Power Company consists of 555,365 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 4, 1994 for series traded on the New
York or Philadelphia Stock Exchange, or the most recent reported bid prices for
those series not recently traded. Where recent market price information was not
available with respect to a series, the market price for such series is based
on the price of a recently traded series with an adjustment related to any
difference in the current yields of the two series.
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K
INTO WHICH DOCUMENT
DESCRIPTION IS INCORPORATED
----------- -------------------
Portions of Annual Reports of the following companies for
the fiscal year ended December 31, 1993: 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 10, 1994, for Annual Meeting
of Shareholders Part III
Portions of Information Statements of the following
companies for 1994 Annual Meeting of Shareholders, to be filed
within 120 days after December 31, 1993: Part III
Appalachian Power Company
Ohio Power Company
----------------
THIS COMBINED FORM 10-K IS SEPARATELY FILED BY AEP GENERATING COMPANY,
AMERICAN ELECTRIC POWER COMPANY, INC., APPALACHIAN POWER COMPANY, COLUMBUS
SOUTHERN POWER COMPANY, INDIANA MICHIGAN POWER COMPANY, KENTUCKY POWER COMPANY
AND OHIO POWER COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL
REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EXCEPT FOR AMERICAN
ELECTRIC POWER COMPANY, INC., EACH REGISTRANT MAKES NO REPRESENTATION AS TO
INFORMATION RELATING TO THE OTHER REGISTRANTS.
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TABLE OF CONTENTS
PAGE
NUMBER
------
Glossary of Terms............................................... i
Part I
Item 1. Business............................................. 1
Item 2. Properties........................................... 37
Item 3. Legal Proceedings.................................... 42
Item 4. Submission of Matters to a Vote of Security
Holders............................................. 44
Executive Officers of the Registrants............... ......... 44
Part II
Item 5. Market for Registrants' Common Equity and
Related Stockholder Matters......................... 47
Item 6. Selected Financial Data.............................. 47
Item 7. Management's Discussion and Analysis of Results
of Operations and Financial Condition............... 48
Item 8. Financial Statements and Supplementary Data.......... 48
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.............. 49
Part III
Item 10. Directors and Executive Officers of the
Registrants......................................... 50
Item 11. Executive Compensation............................... 51
Item 12. Security Ownership of Certain Beneficial Owners
and Management...................................... 55
Item 13. Certain Relationships and Related Transactions....... 56
Part IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K................................. 57
Signatures...................................................... 59
Index to Financial Statement Schedules.......................... S-1
Independent Auditors' Report.................................... S-2
Exhibit Index................................................... E-1
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report,
they have the meanings indicated below.
TERM MEANING
---- -------
AEGCo.................... AEP Generating Company, an electric utility subsidiary of AEP.
AEP...................... American Electric Power Company, Inc.
AEP System or the System. The American Electric Power System, an integrated electric
utility system, owned and operated by AEP's electric utility
subsidiaries.
AFUDC.................... Allowance for funds used during construction. Defined in
regulatory systems of accounts as the net cost of borrowed
funds used for construction and a reasonable rate of return
on other funds when so used.
APCo..................... Appalachian Power Company, an electric utility subsidiary of
AEP.
Buckeye.................. Buckeye Power, Inc., an unaffiliated corporation.
CCD Group................ CSPCo, CG&E and DP&L.
CG&E..................... The Cincinnati Gas & Electric Company, an unaffiliated utility
company.
Cook Plant............... The Donald C. Cook Nuclear Plant, owned by I&M.
CSPCo.................... Columbus Southern Power Company, an electric utility
subsidiary of AEP.
DOE...................... United States Department of Energy.
DP&L..................... The Dayton Power and Light Company, an unaffiliated utility
company.
Federal EPA.............. United States Environmental Protection Agency.
FERC..................... Federal Energy Regulatory Commission (an independent
commission within the DOE).
I&M...................... Indiana Michigan Power Company, an electric utility subsidiary
of AEP.
IURC..................... Indiana Utility Regulatory Commission.
KEPCo.................... Kentucky Power Company, an electric utility subsidiary of AEP.
KPSC..................... Kentucky Public Service Commission.
MPSC..................... Michigan Public Service Commission.
NEIL..................... Nuclear Electric Insurance Limited.
NPDES.................... National Pollutant Discharge Elimination System.
NRC...................... Nuclear Regulatory Commission.
Ohio EPA................. Ohio Environmental Protection Agency.
OPCo..................... Ohio Power Company, an electric utility subsidiary of AEP.
OVEC..................... Ohio Valley Electric Corporation, an electric utility company
in which AEP and CSPCo own a 44.2% equity interest.
PCB's.................... Polychlorinated biphenyls.
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.
RCRA..................... Resource Conservation and Recovery Act of 1976.
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.
i
PART I -------------------------------------------------------------------
Item 1.BUSINESS
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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, 1993, the subsidiaries of AEP had a total of 20,007 employees. AEP, as
such, has no employees. The principal operating subsidiaries of AEP are:
APCo (organized in Virginia in 1926), which is engaged in the generation,
purchase, transmission and distribution of electric power to approximately
838,000 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, 1993, APCo and its wholly owned subsidiaries had 4,587
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. Among the principal industries served by APCo are coal
mining, primary metals, chemicals, textiles, paper, stone, clay, glass and
concrete products and furniture. In addition to its AEP System
interconnection, 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), which is engaged in the generation,
purchase, transmission and distribution of electric power to approximately
578,000 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, 1993, CSPCo had 2,143 employees.
CSPCo's service area is comprised of two areas in Ohio, which include
portions of twenty-five counties. One area includes the City of Columbus
and the other is a predominantly rural area in south central Ohio.
Approximately 80% of CSPCo's retail revenues are derived from the Columbus
area. Among the principal industries served are food processing, chemicals,
primary metals, electronic machinery and paper products. In addition to its
AEP System interconnection, 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), which is engaged in the generation,
purchase, transmission and distribution of electric power to approximately
525,000 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, 1993, I&M had 3,944
1
employees. Among the principal industries served are transportation
equipment, primary metals, 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 interconnection, 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), which is engaged in the
generation, purchase, transmission and distribution of electric power to
approximately 161,000 customers in an area in eastern Kentucky, and in
supplying electric power at wholesale to other utilities and municipalities
in Kentucky. At December 31, 1993, KEPCo had 842 employees. In addition to
its AEP System interconnection, 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), which 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, 1993, Kingsport
Power Company had 102 employees.
OPCo (organized in Ohio in 1907 and reincorporated in 1924), which is
engaged in the generation, purchase, transmission and distribution of
electric power to approximately 657,000 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, 1993, OPCo and its wholly owned subsidiaries had 5,749
employees. Among the principal industries served by OPCo are primary
metals, stone, clay, glass and concrete products, rubber and plastic
products, petroleum refining, chemicals and metal and wire products. In
addition to its AEP System interconnection, 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), which 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, 1993, Wheeling Power Company
had 143 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.
COST REDUCTION PROGRAM
On November 5, 1992, AEP announced a major cost-control program. The program
outlined plans to combine certain operations of CSPCo and OPCo, focusing on the
functions performed in the headquarters of each company, and to restructure and
downsize the operations of the Service Corporation in Columbus, Ohio. The
program has resulted in the elimination of over 1,000 positions.
2
REGULATION
General
AEP and its subsidiaries are subject to the broad regulatory provisions of
the Public Utility Holding Company Act of 1935 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.
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 the Public Utility Holding
Company Act of 1935 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, 1993 are as follows:
AEP
AEGCO APCO CSPCO I&M KEPCO OPCO SYSTEM (A)
----- ---- ----- --- ----- ---- ----------
(IN THOUSANDS)
Retail
Residential
Without Electric
Heating................ $ -- $ 242,177 $284,593 $ 205,315 $ 43,325 $ 256,547 $1,052,233
With Electric Heating.. -- 308,242 100,185 97,568 54,139 132,606 728,569
-------- ---------- -------- ---------- -------- ---------- ----------
Total Residential..... -- 550,419 384,778 302,883 97,464 389,153 1,780,802
Commercial............. -- 273,147 328,854 220,938 53,892 241,426 1,153,207
Industrial............. -- 359,946 137,460 250,939 90,501 609,140 1,514,691
Miscellaneous.......... -- 30,627 14,689 5,593 808 8,107 62,879
-------- ---------- -------- ---------- -------- ---------- ----------
Total Retail.......... -- 1,214,139 865,781 780,353 242,665 1,247,826 4,511,579
Wholesale (sales for
resale)................. 229,196 289,187 74,942 404,910 48,399 438,855 687,072
-------- ---------- -------- ---------- -------- ---------- ----------
Total from KWH Sales.. 229,196 1,503,326 940,723 1,185,263 291,064 1,686,681 5,198,651
Provision for Revenue
Refunds................. -- (331) -- (755) -- -- (926)
-------- ---------- -------- ---------- -------- ---------- ----------
Total Net of Provision
for
Revenue Refunds...... 229,196 1,502,995 940,723 1,184,508 291,064 1,686,681 5,197,725
Other Operating
Revenues................ 77 16,109 12,929 18,135 3,188 21,896 71,117
-------- ---------- -------- ---------- -------- ---------- ----------
Total Electric
Operating
Revenues............. $229,273 $1,519,104 $953,652 $1,202,643 $294,252 $1,708,577 $5,268,842
======== ========== ======== ========== ======== ========== ==========
- --------
(a) Includes revenues of other subsidiaries not shown and elimination of
intercompany transactions.
3
AEP SYSTEM POWER POOL, OFF-SYSTEM POWER SALES AND TRANSMISSION SERVICES
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, 1991, 1992 and 1993:
1991 1992 1993
---- ---- ----
(IN THOUSANDS)
APCo........................................... $(235,000) $(243,000) $(260,000)
CSPCo.......................................... (142,000) (118,000) (141,000)
I&M............................................ 148,000 71,000 183,000
KEPCo.......................................... 15,000 26,000 1,000
OPCo........................................... 214,000 264,000 217,000
In addition, 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 benefits and burdens associated with
their 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."
The following table shows the net credits or (charges) allocated among the
parties to the Transmission Agreement during the years ended December 31,
1991, 1992 and 1993:
1991 1992 1993
---- ---- ----
(IN THOUSANDS)
APCo................................................ $ (7,000) $(8,000) $(3,200)
CSPCo............................................... (31,400) (29,900) (31,200)
I&M................................................. 46,200 48,200 47,400
KEPCo............................................... 5,700 4,200 3,800
OPCo................................................ (13,500) (14,500) (16,800)
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, 1991, 1992 and 1993:
1991(A) 1992(A) 1993(A)
------- ------- -------
(IN THOUSANDS)
AEGCo(b)............................................. $ 33,900 $ 33,000 $ 32,500
APCo(c).............................................. 23,600 18,100 23,600
CSPCo(c)............................................. 12,500 9,100 12,000
I&M(c)(d)............................................ 35,600 31,300 35,300
KEPCo(c)............................................. 4,800 3,700 4,900
OPCo(c).............................................. 21,500 15,700 20,700
-------- -------- --------
Total System......................................... $131,900 $110,900 $129,000
======== ======== ========
- --------
(a) Such sales do not include wholesale sales to entities such as municipal
agencies that may be full/partial requirement customers of AEP System
companies within their service areas. See the table under Classes of
Service for revenues from wholesale sales.
(b) All amounts for AEGCo are from sales made pursuant to a long-term power
agreement. See AEGCo--Unit Power Agreements.
(c) All amounts 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
1991, 1992 and 1993 were made on a short-term basis, except that
$7,300,000, $11,500,000 and $16,800,000, 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 1990, 1991 and 1992
amounts for I&M includes $21,100,000, $20,800,000 and $21,600,000 from a
long-term agreement to sell 250 megawatts of power scheduled to terminate
in 2009.
4
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 for at least five years through March 1997 to unaffiliated utilities. 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.
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, 1991, 1992 and 1993:
1991 1992 1993
------- ------- -------
(IN THOUSANDS)
APCo.................................................... $ 2,800 $ 3,000 $ 2,900
CSPCo................................................... 2,400 2,500 2,500
I&M..................................................... 6,400 6,600 7,700
KEPCo................................................... 500 600 600
OPCo.................................................... 9,800 10,100 9,900
------- ------- -------
Total System(a)......................................... $22,600 $23,500 $24,200
======= ======= =======
- --------
(a) Includes revenues of other System companies not shown.
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. See Rates--APCo for discussion of a current
proceeding in which certain municipal customers seek the FERC to order the AEP
System to provide certain transmission services.
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 1,929,000 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 $271,000,000 in 1993, 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 1993. 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. The Clinton Administration is
considering closing either the Portsmouth, Ohio uranium enrichment plant or
DOE's other enrichment plant in Kentucky.
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 297 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.
5
CERTAIN INDUSTRIAL CONTRACTS
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. Because the
price of electricity to Ravenswood and Ormet is based on generation costs at
the Muskingum River and Kammer Plants, respectively, the implementation of the
Clean Air Act Amendments of 1990 or an unfavorable resolution of the stack
height regulation litigation (in the case of Kammer Plant) and administrative
proceedings, described under Environmental and Other Matters, could result in a
decrease in operations or closure of Ravenswood's and Ormet's aluminum
reduction plants. See Legal Proceedings for a discussion of litigation
involving Ormet.
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 37% of
AEGCo's operating revenue in 1993 was derived from its sales to VEPCo.
6
Capital Funds Agreement
AEGCo and AEP have entered into a capital funds agreement pursuant to which,
among other things, AEP has unconditionally agreed to make cash capital
contributions, or in certain circumstances subordinated loans, to AEGCo to the
extent necessary to enable AEGCo to (i) maintain such an equity component of
capitalization as required by governmental regulatory authorities, (ii) provide
its proportionate share of the funds required to permit commercial operation of
the Rockport Plant, (iii) enable AEGCo to perform all of its obligations,
covenants and agreements under, among other things, all loan agreements, leases
and related documents to which AEGCo is or becomes a party (AEGCo Agreements),
and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo
Obligations) under the AEGCo Agreements, other than indebtedness, obligations
or liabilities owing to AEP. The Capital Funds Agreement will terminate after
all AEGCo Obligations have been paid in full.
INDUSTRY PROBLEMS
The electric utility industry, including the operating subsidiaries of AEP,
has encountered at various times in the last 15 years significant problems in a
number of areas, including: delays in and limitations on the recovery of fuel
costs from customers; proposed legislation, initiative measures and other
actions designed to prohibit construction and operation of certain types of
power plants under certain conditions and to eliminate or reduce the extent of
the coverage of fuel adjustment clauses; inadequate rate increases and delays
in obtaining rate increases; jurisdictional disputes with state public
utilities commissions regarding the interstate operations of integrated
electric systems; requirements for additional expenditures for pollution
control facilities; increased capital and operating costs; construction delays
due, among other factors, to pollution control and environmental considerations
and to material, equipment and fuel shortages; the economic effects on net
income (which when combined with other factors may be immediate and adverse)
associated with placing large generating units and related facilities in
commercial operation, including the commencement at that time of substantial
charges for depreciation, taxes, maintenance and other operating expenses, and
the cessation of AFUDC with respect to such units; uncertainties as to
conservation efforts by customers and the effects of such efforts on load
growth; depressed economic conditions in certain regions of the United States;
increasingly competitive conditions in the wholesale and retail markets;
proposals to deregulate certain portions of the industry, 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 during warmer summer
and cooler winter seasons because of the use of electricity by customers for
cooling and heating.
FRANCHISES
The operating companies of the AEP System hold franchises to provide electric
service in various municipalities in their service areas. These franchises have
varying provisions and expiration dates. In general, the operating companies
consider their franchises to be adequate for the conduct of their business.
COMPETITION
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
7
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 sources for electric power place them in a favorable competitive
position, even though their price may be higher than some such 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 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 will not 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 August 27,
1993, an administrative law judge recommended that the MPSC authorize such
retail wheeling on a voluntary basis and that the proposal had not been shown
to be in the public interest, could harm other ratepayers and did not
adequately address the issues of stranded investment and utilities' obligation
to serve. The MPSC has not yet issued an order in this proceeding. 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 the Public Utility Holding Company Act of 1935,
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.
New Generation
When the AEP System needs new generation, the public utility subsidiaries of
AEP which wish to provide it will have to compete with exempt wholesale
generators, independent power producers and other
8
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 baseload generating capacity is expected to be
constructed by the AEP System for some time. See Construction and Financing
Program.
Indiana: On June 30, 1993, the IURC issued a notice of proposed rulemaking
for integrated resource planning which among other things would permit a
utility to acquire additional generation through bidding programs or other
means. The proposed rules would permit the utility to participate in the
bidding process. The Indiana Electric Association, on behalf of a group of
utilities including I&M, filed comments that support competitive bidding as an
optional method to acquire new generation.
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. 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.
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 focus is international and domestic cogeneration,
the independent power market, and the privatization of generation facilities in
the international market.
AEPES has continued to offer consulting services and market 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, because of the absence of any assured return or rate of
return, 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
The AEP System companies are engaged in a continuing construction program,
involving 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. However, AEP's
current load forecast indicates no need for new coal-fired baseload generation
until sometime after the year 2005. For many
9
years System companies' loads grew at such a rate as to warrant efforts to
achieve major economies of scale, and thus reduce or limit the unit cost of the
power and energy supplied to the System's customers. 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 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 specific goal of the project is 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, 1993,
the Tidd Plant achieved 5,530 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. Original funding for
the Tidd Plant project included provisions for a three-year test period
extending through February 1994. At this time, planned funding for the Tidd
Plant project contemplates an additional year of operation extending through
February 1995. However, if additional testing is required, the test period
could be extended past February 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, 1993 were $181,898,000
and $25,076,000, respectively. At such date, OPCo had received funding from DOE
and the State of Ohio in the aggregate amounts of $59,548,000 and $10,000,000,
respectively, and had recovered $123,186,000 from its retail customers. The
estimated total construction and operating costs of the Tidd Plant project are
$185,000,000 and $40,000,000, respectively, and OPCo expects to receive
additional funding from DOE so that the aggregate amount received from it will
be $60,200,000. OPCo is currently recovering approximately $500,000 per month
from its Ohio electric fuel component jurisdictional customers for costs
associated with the Tidd Plant project that are not recovered from DOE or the
State of Ohio and incurred after December 1, 1986. The PUCO, however, may
consider distributing such costs over total OPCo sales which may result in a
prospective reduction in the amount recoverable by OPCo.
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 through at least January 1996. 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 state regulatory commission approval.
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 1991, 1992 and 1993 and their current estimate of 1994
construction expenditures, in each case including AFUDC but excluding nuclear
fuel and other assets acquired under leases. The construction expenditures for
the years 1991-1993 were applied, and it is anticipated that the estimated
construction expenditures for 1994 will be applied, approximately as follows to
construction of the following classes of assets:
10
1991 1992 1993 1994
ACTUAL ACTUAL ACTUAL ESTIMATE
-------- -------- -------- --------
(IN THOUSANDS)
AEGCO
Generating plant and facilities............. $ 3,700 $ 3,600 $ 3,100 $ 4,300
-------- -------- -------- --------
TOTAL..................................... $ 3,700 $ 3,600 $ 3,100 $ 4,300
======== ======== ======== ========
APCO
Generating plant and facilities (a)......... $ 33,800 $ 34,400 $ 51,200 $ 64,200
Transmission lines and facilities........... 42,500 54,200 36,700 45,800
Distribution lines and facilities........... 102,200 91,600 98,200 92,400
General plant and other facilities.......... 12,300 11,500 4,800 17,300
-------- -------- -------- --------
TOTAL..................................... $190,800 $191,700 $190,900 $219,700
======== ======== ======== ========
CSPCO
Generating plant and facilities............. $ 49,800 $ 21,900 $33,300 $ 39,500
Transmission lines and facilities........... 11,300 11,600 10,100 4,600
Distribution lines and facilities........... 42,900 40,800 40,700 46,400
General plant and other facilities.......... 3,300 1,100 2,200 8,200
-------- -------- -------- --------
TOTAL..................................... $107,300 $ 75,400 $ 86,300 $ 98,700
======== ======== ======== ========
I&M (b)
Generating plant and facilities............. $ 48,200 $ 66,400 $ 50,200 $ 55,800
Transmission lines and facilities .......... 31,700 17,300 10,100 20,000
Distribution lines and facilities........... 38,800 39,200 41,300 42,000
General plant and other facilities.......... 5,000 3,500 6,700 5,200
-------- -------- -------- --------
TOTAL..................................... $123,700 $126,400 $108,300 $123,000
======== ======== ======== ========
KEPCO
Generating plant and facilities............. $ 5,300 $ 4,100 $ 8,100 $ 25,000
Transmission lines and facilities........... 4,000 8,700 6,700 9,400
Distribution lines and facilities........... 19,900 17,500 20,300 19,900
General plant and other facilities.......... 0 1,500 0 4,100
-------- -------- -------- --------
TOTAL..................................... $ 29,200 $ 31,800 $ 35,100 $ 58,400
======== ======== ======== ========
OPCO
Generating plant and facilities (c)(d)...... $132,900 $124,900 $112,700 $ 77,800
Transmission lines and facilities........... 19,500 18,900 28,600 34,300
Distribution lines and facilities........... 41,500 42,800 46,000 47,000
General plant and other facilities.......... 10,000 5,900 10,500 11,300
-------- -------- -------- --------
TOTAL..................................... $203,900 $192,500 $197,800 $170,400
======== ======== ======== ========
AEP SYSTEM
Generating plant and facilities (a)(c)(d)... $273,700 $255,300 $258,600 $266,600
Transmission lines and facilities........... 110,000 111,900 92,800 115,100
Distribution lines and facilities........... 250,800 237,700 252,300 255,800
General plant and other facilities.......... 30,700 23,700 24,400 46,500
-------- -------- -------- --------
TOTAL..................................... $665,200 $628,600 $628,100 $684,000
======== ======== ======== ========
- --------
(a) Excludes expenditures for PFBC Utility Demonstration Project. See PFBC
Projects.
(b) Reflects restatement for 1991 to include effect of merging Michigan Power
Company into I&M.
(c) 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.
(d) Excludes expenditures associated with flue-gas desulfurization system
being constructed by a non-affiliate at the Gavin Plant which OPCo has
agreed to lease upon completion of construction. Actual expenditures for
1991, 1992 and 1993 and the current estimate for 1994 are $18,683,000,
$93,653,000, $256,673,000 and $230,000,000, respectively. See
Environmental and Other Matters--CAAA-AEP System Compliance Plan.
11
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 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 1998 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 1994 with a decision expected in early
1995.
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 September 1994 and
the final EIS in February 1995.
Environmental Expenditures: Expenditures related to compliance with air and
water quality standards, included in the gross additions to plant of the
System, during 1991, 1992 and 1993 and the current estimate for 1994 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.
1991 1992 1993 1994
ACTUAL ACTUAL ACTUAL ESTIMATE
-------- ------- ------- --------
(IN THOUSANDS)
AEGCo......................................... $ 0 $ 0 $ 0 $ 900
APCo (a)...................................... 7,100 11,200 16,800 22,100
CSPCo......................................... 7,100 6,500 15,800 23,900
I&M........................................... 100 0 0 3,700
KEPCo......................................... 200 100 1,000 9,000
OPCo (b)(c)................................... 56,700 61,600 31,600 24,500
------- ------- ------- -------
AEP System (a)(b)(c).......................... $71,200 $79,400 $65,200 $84,100
======= ======= ======= =======
12
- --------
(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
being constructed by a non-affiliate at the Gavin Plant which OPCo has
agreed, subject to PUCO approval, to lease upon completion of
construction. Actual expenditures for 1991, 1992 and 1993 and the current
estimate for 1994 are $18,683,000, $93,653,000, $256,673,000 and
$230,000,000, 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. Since 1985, however, AEP has sold no shares of Common Stock. If
necessary, AEP will issue 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 1991-1993, external funds from financings and capital
contributions by AEP amounted, with respect to APCo, CSPCo and KEPCo to
approximately 37%, 38% and 31%, 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, 1994, and the respective amounts
of short-term debt outstanding on that date, on a corporate basis, are shown
in the following tabulation:
TOTAL
SHORT-TERM DEBT AEP AEGCO APCO CSPCO I&M KEPCO OPCO AEP SYSTEM(A)
---------------- ---- ------ ----- ------ ---- ------ ----- --------------
(IN MILLIONS)
Amount authorized.... $150 $50 $215 $140 $127 $100 $222 $1,054
==== === ==== ==== ==== ==== ==== ======
Amount outstanding:
Notes payable...... $ -- $15 $ -- $ 12 $ -- $26 $ -- $ 63
Commercial paper... 65 -- 36 13 50 12 38 214
---- --- ---- ---- ---- ---- ---- ------
$ 65 $15 $ 36 $ 25 $ 50 $38 $ 38 $ 277
==== === ==== ==== ==== ==== ==== ======
- --------
(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
13
(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
classi-fied 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 in the amounts
considered to be desirable.
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:
DECEMBER 31,
--------------
1991 1992 1993
---- ---- ----
APCo
Debt coverage.................................................. 3.76 3.50 3.62
Preferred stock coverage....................................... 2.08 1.99 2.04
CSPCo
Mortgage coverage.............................................. 1.49 2.16 2.91
I&M
Debt coverage.................................................. 4.10 3.55 4.59
Preferred stock coverage....................................... 2.24 2.06 2.48
KEPCo
Mortgage coverage.............................................. 4.50 3.34 2.19
OPCo
Debt coverage.................................................. 3.95 3.36 4.65
Preferred stock coverage....................................... 2.24 2.22 2.88
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 depends upon the timely approval
of pending and future 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
14
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 is committed to integrated
resource planning and has in place a detailed analysis procedure in which
effective demand-side and supply-side options are both considered in order to
determine the least cost approach to provide reliable electric service for its
customers, taking into account environmental and other considerations. Recovery
of demand-side program expenditures through rates is being reviewed by AEP's
respective regulatory commissions as discussed below in Rates.
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 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.
FERC Regulatory Matters: On March 31, 1993, the FERC issued its final rules,
effective January 1, 1993, regarding accounting for allowances under the Clean
Air Act Amendments of 1990. The rules provide for the use of "fair value" in
the valuation of allowances traded between affiliates and establishment of FERC
accounts to record regulatory assets and liabilities. See Environmental and
Other Matters--Air Pollution Control.
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.
15
In June 1993, certain municipal customers filed an application with the FERC
for an order requiring the AEP System to provide transmission service for 50
megawatts (mw) of base load power purchased from an unaffiliated utility and
the reduction by 50 mw of the power these customers purchase from APCo under
existing 10-year Electric Service Agreements ("ESAs"). 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. The proposed 50 mw reduction would reduce net non-fuel
revenue by $16,900,000 over the period April 1994 through June 1997 (end of
ESAs). On February 10, 1994, the FERC issued orders (1) affirming, in part, the
administrative law judge's initial decision and (2) instituting a proceeding to
determine the appropriate rate and terms for the transmission of this power to
the municipal customers. On March 11, 1994, AEP System companies filed a
petition for rehearing of the FERC's order affirming the administrative law
judge's decision.
Virginia: On December 4, 1992, APCo filed with the Virginia SCC a request to
increase rates by approximately $31,377,000 annually. APCo's filing requests,
among other things, approval to establish a capacity charge tracking mechanism
to track changes in its capacity charges from the AEP System Power Pool,
increased West Virginia allocated business and occupation taxes discussed below
and increased SFAS 106 costs. On December 29, 1992, the Virginia SCC issued an
order suspending APCo's proposed rates until May 3, 1993. In June 1993, the
Virginia SCC staff recommended a $10,500,000 annual rate increase and, after
hearings in July 1993, the Hearing Examiner issued a report recommending a
$7,800,000 annual rate increase. A Virginia SCC order is pending.
On March 27, 1992, the Virginia SCC issued a final order regarding its
investigation of CLM programs of Virginia's utilities. The Virginia SCC adopted
rules regarding the rate recovery of promotional allowances designed to achieve
energy conservation, load reduction or improved energy efficiency. Rate
recovery for such promotions will be allowed only for cost-effective CLM
programs, and not for those designed primarily to increase load or market
share, unless a company proves that the program is cost-effective and serves
the overall public interest. The Virginia SCC also directed Virginia utilities
to submit their CLM programs for formal review and approval.
In accordance with the March 27, 1992 order of the Virginia SCC, in order to
promote the goals of cost-effective utility conservation, efficiency and load
management, on October 16, 1992, APCo filed an application with the Virginia
SCC for approval to implement six demand side management pilot programs in its
service territory, including a residential rate experiment. On March 4, 1993,
the Virginia SCC issued an order approving implementation of five of the six
programs. The storage water heater program was transferred to APCo's pending
Virginia retail rate case discussed above for adjudication. Rate recovery for
all of these programs is also being sought in the Virginia rate case.
The Virginia SCC, in its order of March 27, 1992, also directed its staff to
determine the appropriate methods for evaluating the cost-effectiveness of CLM
programs and to submit an interim report outlining the scope and procedure of
the investigation. The staff submitted its Report on the Cost/Benefit Analysis
of Demand Side Management Programs on February 9, 1993. Therein the staff
stated that a multi-perspective approach to determining the cost and benefits
of demand-side management programs is needed in order to evaluate the full
impact of programs on a utility and its customers. The staff stated that
programs should be evaluated from the perspective of the program participant,
the non-participant, the utility and all ratepayers.
On June 28, 1993, the Virginia SCC issued an order promulgating rules on the
proper cost/benefit tests to be conducted on proposed DSM programs. The rules
provide that utilities shall analyze a proposed DSM program from a multi-
perspective approach considering, at a minimum, the quantifiable benefits and
costs of a program to the participating customer, the cost of the DSM program
incurred by the utility, the difference between the change in total revenues
paid to the utility and the change in total costs to a utility resulting from
the DSM program, and the cost of a program as a resource option to the utility
and its ratepayers as a whole. The order specifies minimum guidelines to
provide direction to utilities in developing applications for
16
approval of DSM programs. Utilities must seek Virginia SCC approval of pilot or
experimental programs that involve rates or promotional allowances, but other
limited pilot or experimental programs may be conducted without prior approval.
West Virginia: In January 1992, APCo filed with the Supreme Court of Appeals
of West Virginia a petition for appeal which sought a review and reversal of
the West Virginia PSC's November 1, 1991 order which disallowed recovery of
$12,700,000 annually relating to the allocation treatment of business and
occupation taxes. In April 1992, the court issued an order denying APCo's
appeal. APCo has received recovery of the non-West Virginia jurisdictional
share of these taxes in its Virginia and FERC jurisdictions.
On February 22, 1993, the West Virginia PSC approved an increase in APCo's
Expanded Net Energy Cost (ENEC) rates of $24,400,000 annually. ENEC rates are
approved annually as part of the West Virginia PSC's review of APCo's power
supply costs which include fuel, purchased power and AEP System Power Pool
capacity charges and credits for APCo's share of Power Pool generation costs
and wholesale sales. In approving the new rates, the West Virginia PSC placed
APCo on notice that the annual review process, including the traditional fuel
elements of the review and deferred accounting with prospective actual cost
recoveries, would be closely examined at the next review.
On October 28, 1993, the West Virginia PSC approved, with certain
modifications, a settlement agreement among the parties to the ENEC proceeding.
The approved agreement temporarily suspended the annual ENEC recovery
proceedings, reduced ENEC rates by $8,000,000 annually effective November 1,
1993, and froze current base rates and the reduced ENEC rate for a three-year
period ending October 31, 1996. Deferral accounting will not be used for new
ENEC cost variances incurred from November 1993 through October 1996. The ENEC
actual underrecovery balance on October 31, 1993 of $13,300,000 will be
collected through a component of the revised ENEC rates over the three-year
period ending October 31, 1996. The agreement also provides for a net decrease
in West Virginia depreciation expense of $4,300,000 annually (with no change to
base rates) effective November 1, 1995. APCo also agreed to invest at least
$90,000,000 in distribution facilities in West Virginia between October 13,
1993 and October 31, 1996.
On November 5, 1992, APCo filed an application with the West Virginia PSC for
approval to implement seven demand-side management programs. On February 8,
1993, the West Virginia PSC issued an order approving the seven demand side
management programs, but limited availability of one program to only existing
electric water heating customers. On April 14, 1993, the West Virginia PSC by
order clarified the availability to customers with electric water heating and
new customers with all-electric homes.
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%) (collectively, the Owners).
Zimmer Plant--Rate Recovery: On April 2, 1991, CSPCo filed a request with the
PUCO to increase rates $202,500,000 on an annual basis principally to recover
its share of the costs of operation of the Zimmer Plant and a return on its
investment. On May 12, 1992, the PUCO issued an order on CSPCo's rate request.
The order provided for a phased-in rate increase of $123,000,000 to be
implemented in three steps over a two-year period and excluded from rate base
$165,000,000 of Zimmer Plant costs composed of an allowance for funds used
during construction accrued from February 1984 through February 1986, nuclear
wind-down costs and a loss on the sale of nuclear fuel. The order also provided
for the recovery of deferred post in-service operating expenses over 10 years.
CSPCo requested a rehearing with the PUCO which was denied except for rehearing
of certain minor rate design and accounting related issues. CSPCo and the PUCO
staff signed a stipulation agreement resolving the minor issues for which the
PUCO granted rehearing. On August 20, 1992, the PUCO approved the stipulation
which provided CSPCo with approximately $1,500,000 of additional revenues
annually.
17
CSPCo filed an appeal with the Ohio Supreme Court on September 1, 1992
regarding the $165,000,000 excluded from rate base and challenging the PUCO's
authority to order a phased-in rate plan. CSPCo's appeal stated (1) that the
PUCO failed to abide by the terms of a PUCO-approved 1985 stipulation agreement
regarding CSPCo's investment in the Zimmer Plant and (2) that the PUCO did not
have authority to order phased-in rates.
In November 1993, the Supreme Court issued a decision on CSPCo's appeal
affirming the disallowance and finding that the PUCO did not have statutory
authority to order phased-in rates. The court instructed the PUCO to fix rates
to provide gross annual revenues in accordance with the law and to provide a
mechanism to recover the revenues deferred under the phase-in order which
through December 31, 1993 totaled $93,900,000.
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 for a period of less than four and one-half years. The recovery of deferrals
and the increase in rates to the full rate level will not affect net income.
Other Ohio Regulatory Matters: On April 30, 1992, CSPCo and OPCo filed their
individual 1992 long-term forecast reports and integrated resource plans. On
September 23, 1993, the PUCO issued its opinion and order approving CSPCo's and
OPCo's long-term forecast reports. The PUCO order directs CSPCo and OPCo to
proceed with a number of specific demand-side management programs and any other
programs determined to be cost-effective.
Reference is made to Environmental and Other Matters--Clean Air Act
Amendments of 1990 for a discussion of emission allowances. On January 9, 1992,
the PUCO issued an entry opening a generic docket to investigate trading and
usage of, and accounting treatment for, emission allowances by electric
utilities in Ohio. On January 20, 1993 the PUCO issued proposed guidelines
concerning emission allowances, including the guideline that gains or losses on
transactions involving emission allowances created by rate base assets should
generally flow through to ratepayers. On March 25, 1993, the PUCO issued its
final guidelines concerning emission allowances. The final guidelines state
that the PUCO expects 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.
On September 17, 1993, CSPCo and OPCo filed an Application for
Conservation/Renewable Reserve Allowances. The application requested an award
of 18 allowances and was certified by the PUCO on September 3, 1993. On January
27, 1994, Federal EPA notified AEP that it would defer awarding allowances to
CSPCo and OPCo pending further documentation from the PUCO of CSPCo's and
OPCo's compliance with appropriate eligibility requirements.
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.
In October 1991, the PUCO announced that the Governor of Ohio and the Ohio
General Assembly directed the PUCO to develop a long-term energy strategy for
the State of Ohio. On December 4, 1992, the PUCO, on behalf of the Interagency
Ohio Energy Strategy (OES) Task Force, released its interim report. CSPCo and
OPCo jointly filed comments on February 15, 1993.
18
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 June 1990 an initial decision was issued by a FERC administrative
law judge regarding a complaint filed by a wholesale customer concerning the
reasonableness of I&M's coal costs from an unaffiliated supplier who leased a
Utah mining operation from I&M in 1986 and the coal transportation charges of
affiliates. In February 1993 the FERC reversed the decision of the
administrative law judge and dismissed the complaint. In December 1993 the
wholesale customer appealed the FERC order to the U.S. Court of Appeals,
District of Columbia Circuit.
Indiana: In April 1992 I&M filed testimony and exhibits with the IURC seeking
a $44,800,000 increase in annual rates to recover, among other things,
increased operating costs including expenses associated with nuclear operation
and maintenance, an increase in the provision for the cost of decommissioning
the Cook Plant, increased accruals for the cost of postretirement benefits
other than pensions as mandated by SFAS 106 and revised depreciation accrual
rates. On November 12, 1993, the IURC issued an order granting a $34,700,000
annual rate increase. The IURC approved substantially all of I&M's proposals
including, among other things, increased operation and maintenance expenses
associated with the Cook Plant with an increase in the provision for nuclear
decommissioning costs, increased accruals for the cost of postretirement
benefits other than pensions and an increase in depreciation expense based on
revised accrual rates (including costs for the demolition of I&M's fossil-fired
generating stations at the end of their useful lives).
In June 1993 the IURC issued a notice of proposed rulemaking for integrated
resource planning (IRP) guidelines, including consideration of demand-side
management, resource bidding and independent power producers. In October 1993,
the Indiana Electric Association filed the joint comments of some of its
members, including I&M, indicating their support for the IURC's efforts to
develop new guidelines relating to IRP.
Michigan: On February 21, 1992, I&M submitted to the MPSC Staff its three-
year conservation plan. After settlement discussions, I&M submitted to Staff a
revised three-year conservation plan that reflects demand-side management
program costs and an incentive package and that establishes I&M's next Michigan
retail rate case as the forum to consider recovery of lost revenues. The MPSC
approved a settlement agreement in September 1993 which established recovery of
DSM program expenses and an incentive plan.
In October 1993, the MPSC approved a settlement agreement authorizing I&M to
increase its annual provision for the cost to decommission the Cook Plant from
approximately $2,800,000 to a level of $4,000,000, effective November 1, 1993,
with further increases to annual levels of $5,100,000 and $6,000,000, six and
twelve months later, respectively.
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 August 15, 1991, the KPSC issued an order which initiated its
investigation of the compliance strategies of electric utilities related to the
Clean Air Act Amendments of 1990. On September 4, 1991, KEPCo filed its
preliminary plan for compliance which is the same systemwide compliance report
filed with the PUCO discussed under the caption CAAA-AEP System Compliance
Plan. KEPCo's Big Sandy Plant is not subject to Phase I emission requirements;
however, KEPCo may incur a portion of the costs of Phase I compliance for the
AEP System through the AEP System Power Pool. On March 30, 1992, the KPSC
issued an order requiring all electric utilities with Phase I affected units to
file their complete acid rain permit applications filed with Federal EPA or
explain why such permit applications are not being filed. On April 6, 1993,
KEPCo responded by letter that KEPCo has no generating units which are Phase I-
affected; however,
19
AEP's Phase I permit applications were provided. On August 18, 1993, the KPSC
issued an order which indicated utilities should be prepared to explain their
actions regarding extension and bonus allowances. For unreasonable activities,
cost disallowances would occur. Appropriate ratemaking treatment of allowance
trading and use will be determined on a case-by-case basis.
On July 24, 1992, the KPSC began an investigation into the feasibility of
implementing demand-side management cost recovery and incentive mechanisms.
OPCo
Reference is made to Rates--CSPCo regarding generic proceedings by the PUCO
relating to demand-side management programs, emission allowance trading, the
review of OPCo's long-term forecast report, the Ohio Energy Strategy Task Force
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, FERC issued an order dismissing the
complaint and, in September 1993, the wholesale customers appealed the FERC
order to the U.S. Court of Appeals for the Sixth Circuit.
On November 25, 1992, the PUCO issued an order approving a stipulation
agreement with OPCo, the staff of the PUCO and the Ohio Consumers' Counsel. The
agreement provided for, among other things, a predetermined price of $1.64 per
million Btus for coal consumed by OPCo at four of its generating stations for
the three-year period ended November 30, 1994; a subsequent 15-year
predetermined price of $1.575 per million Btus for coal consumed at the Gavin
Plant with quarterly price adjustments; and a limit on the recoverable cost for
the Gavin scrubbers which is discussed under Environmental and Other Matters-
Clean Air Act Amendments of 1990-AEP System Compliance Plan. After November 30,
2009, the price that OPCo can recover for coal from its affiliated Meigs mine
will be limited to the lower of cost or the then-current market price. The
predetermined prices will provide OPCo with an opportunity to accelerate
recovery of its investment in and the liabilities of its Meigs mining operation
attributable to its Ohio jurisdiction to the extent the actual cost of coal
burned at the four plants is below the predetermined prices. In March 1993, the
Industrial Energy Consumers of OPCo and The Sierra Club appealed the PUCO order
to the Supreme Court of Ohio. OPCo has participated in these proceedings.
OPCo has restructured its Meigs mining operation to operate at a reduced
level of production. As a result, OPCo will purchase replacement coal under
long-term contracts and on the spot market. It is expected that the replacement
coal will be at prices below the Meigs production costs. Management reviewed
the potential impact of the stipulation and restructuring to determine OPCo's
ability to recover the cost of its Meigs mining operation. Based on the
estimated future cost of coal for the Gavin Plant, management believes that
OPCo should be able to recover the Ohio jurisdictional cost of its Meigs mining
operation under the terms of the stipulation agreement.
In November 1992, the municipal wholesale customers of OPCo filed two
complaints. One complaint was filed with the FERC requesting an investigation
of OPCo's July 1992 sale of the Martinka mining operation to an unaffiliated
company. The FERC dismissed this complaint in June 1993. The other complaint
was filed with the SEC requesting an investigation of the Martinka sale 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.
The PUCO is reviewing the Martinka sale and related unaffiliated fuel contracts
in OPCo's current fuel clause proceedings.
If additional regulatory actions further limit recovery of affiliated coal
costs, results of operations could continue to be adversely impacted and the
continued operation of some or all of OPCo's affiliated coal mines could be
adversely impacted. The inability to recover affiliated coal costs and, if
necessary, any future cost of
20
mine closure, including the investment in and cost to maintain the facilities
shutdown, leased asset buy-outs, employee benefit costs and required
reclamation costs, through the rate-making process or through the disposition
of assets could have a material adverse effect on results of operations and
financial condition.
Reference is made to Construction and Financing Program-PFBC Projects-Tidd
Plant for information concerning the recovery through rates of certain Tidd
Plant project costs.
Reference is made to the caption Environmental and Other Matters--CAAA-AEP
System Compliance Plan for information regarding the AEP System's plan to
comply with the Clean Air Act Amendments of 1990.
FUEL SUPPLY
The following table shows the sources of power generated by the AEP System:
1990 1991 1992 1993
---- ---- ---- ----
Coal................................................... 90% 86% 93% 86%
Nuclear................................................ 9% 13% 6% 13%
Hydroelectric and other................................ 1% 1% 1% 1%
Variations in the generation of nuclear power are primarily related to
refueling outages and, in 1992, a forced outage at Cook Plant Unit 2. See Cook
Nuclear Plant.
Coal
The Clean Air Act Amendments of 1990 provide for the issuance of annual
allowance allocations covering sulfur dioxide emissions at levels below
historic emission levels for many coal-fired generating units of the AEP
System. Phase I of this program must be met by 1995 and Phase II must be met by
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. What regulatory actions, if any, may result
from the foregoing, or from further legislative actions relating to a national
energy crisis cannot be predicted, but such actions could adversely affect the
revenues, operations and properties of AEP.
21
System companies have developed programs to conserve coal supplies at System
plants which involve, on a progressive basis, limitations on sales of power and
energy to neighboring utilities, appeals to customers for voluntary limitations
of electric usage to essential needs, curtailment of sales to certain
industrial customers, voltage reductions and, finally, mandatory reductions in
cases where current coal supplies fall below minimum levels. Such programs have
been filed and reviewed with officials of Federal and state agencies and, in
some cases, the state regulatory agency has prescribed actions to be taken
under specified circumstances by System companies, subject to the jurisdiction
of such agencies.
The mining of coal reserves is subject to Federal requirements with respect
to the development and operation of coal mines, and to state and Federal
regulations relating to land reclamation and environmental protection,
including Federal strip mining legislation enacted in August 1977. Continual
evaluation and study is given to possible closure of existing coal mines and
divestiture or acquisition of coal properties in light of Federal and state
environmental and mining laws and regulations which may affect the System's
need for or ability to mine such coal.
Western coal purchased by System companies is transported by rail to a
terminal on the Ohio River for transloading to barges for delivery to
generating stations on the river. Subsidiaries of AEP lease approximately 3,200
coal hopper cars to be used in unit train movements, as well as 17 towboats,
295 jumbo barges and 198 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:
1989 1990 1991 1992 1993
------ ------ ------ ------ ------
Total coal delivered to
AEP operated plants (thousands of
tons)............................... 45,025 52,087 45,232 44,738 40,561
Sources (percentage):
Subsidiaries........................ 25% 25% 28% 25% 20%
Long-term contracts.................. 56% 58% 62% 65% 66%
Spot or short-term purchases......... 19% 17% 10% 10% 14%
Average price per ton of spot-purchased
coal.................................. $25.17 $26.75 $25.40 $23.88 $23.55
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:
1989 1990 1991 1992 1993
------ ------ ------ ------ ------
DOLLARS PER TON
AEP System Companies......................... $37.05 $35.23 $35.16 $34.31 $33.57
AEGCo........................................ 24.33 21.05 20.65 20.11 17.74
APCo......................................... 39.52 39.77 41.99 43.00 42.65
CSPCo........................................ 35.50 37.01 35.18 33.87 33.87
I&M.......................................... 32.14 27.18 25.57 24.23 23.80
KEPCo........................................ 29.03 30.71 31.38 30.24 27.08
OPCo......................................... 40.04 40.13 40.18 38.36 38.12
22
1989 1990 1991 1992 1993
------ ------ ------ ------ ------
CENTS PER MILLION BTU'S
AEP System Companies.................... 162.44c 158.10c 158.88c 154.41c 150.89c
AEGCo................................... 149.75 126.21 123.33 120.90 107.71
APCo.................................... 160.27 160.94 169.48 173.05 173.32
CSPCo................................... 153.77 159.83 152.55 143.94 143.66
I&M..................................... 162.67 143.43 139.16 135.11 129.39
KEPCo................................... 122.92 129.72 132.25 126.92 113.90
OPCo.................................... 172.25 171.10 171.65 163.89 161.25
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, 1993, the
System's coal inventory was approximately 58 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 1993 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 1993 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.
AVERAGE SULFUR CONTENT
ESTIMATED REQUIREMENTS OF DELIVERED COAL
TOTAL CONSUMPTION FOR REMAINDER OF -----------------------------
DURING 1993 USEFUL LIVES POUNDS OF SO/2/
(IN THOUSANDS OF TONS) (IN MILLIONS OF TONS)(A) BY WEIGHT PER MILLION BTU'S
------------------------ -------------------------- ---------- ------------------
AEGCo (b)............... 5,077 220 0.3% 0.7
APCo.................... 8,339 321 0.7% 1.1
CSPCo (c)............... 5,406 182 3.2% 5.4
I&M (d)................. 6,572 255 0.7% 1.6
KEPCo................... 2,292 73 1.1% 1.9
OPCo.................... 17,419 538 2.8% 4.8
- --------
(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.
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 1993, 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
23
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 entered into a coal supply agreement with an unaffiliated supplier
for the delivery of 1,600,000 tons of coal per year from 1992 through March
2011. Such coal contains approximately 5% sulfur by weight and is washed to
improve its quality and consistency for use principally at Units 1 through 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.
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, approximately
175,000,000 tons of coal with an average sulfur content not exceeding 1.2
pounds of sulfur dioxide per million Btu's of heat input. A contract for
100,000,000 tons expires on December 31, 2014 and a contract for 75,000,000
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 2,211,000 tons of
coal in 1994. 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 234,000,000 tons of
clean recoverable coal, which ranges in sulfur content
24
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 108,000,000
tons of clean recoverable coal ranging in sulfur content between 1.4% and 3.3%
sulfur by weight (weighted average, 2.1%) of which approximately 31,000,000
tons can be recovered based upon existing mining plans and projections and
employing current mining practices and techniques.
On July 1, 1992, a coal-mining subsidiary of OPCo sold its Martinka mining
operations and most of its related coal reserves to an unaffiliated company for
approximately $139,000,000 and the assumption of certain future liabilities.
Concurrently OPCo entered into a 20-year agreement with an affiliate of the
buyer of the Martinka mine to purchase up to 2,500,000 tons of low sulfur coal
annually, including coal that will enable OPCo to comply with the Clean Air Act
Amendments. The Martinka sale did not have a significant impact on results of
operations and financial condition. The Martinka mining operation represented
approximately 20% of affiliated coal deliveries to OPCo.
Nuclear
I&M has made commitments to meet certain of the nuclear fuel requirements of
the Cook Plant. The nuclear fuel cycle consists of the mining and milling of
uranium ore to uranium concentrates; the conversion of uranium concentrates to
uranium hexafluoride; the enrichment of uranium hexafluoride; the fabrication
of fuel assemblies; the utilization of nuclear fuel in the reactor; and the
reprocessing or other disposition of spent fuel. Steps currently are being
taken, based upon the planned fuel cycles for the Cook Plant, to review and
evaluate I&M's requirements for the supply of nuclear fuel beyond the existing
contractual commitments shown in the following table. I&M has made and will
make purchases of uranium in various forms in the spot 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.
URANIUM
CONCENTRATES CONVERSION ENRICHMENT (1) FABRICATION REPROCESSING (2)
-------------- ----------- --------------- ------------ ----------------
Unit 1.................. -- -- 2000 1998 --
Unit 2.................. -- -- 2000 1998 --
- --------
(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
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
25
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 $75,845,000 at December 31, 1993. I&M
deferred this amount plus accrued interest on its balance sheet pending
recovery through the rate-making process. I&M has received regulatory approval
for the recovery of this amount and is reducing the amount deferred as it is
being recovered. Because of the current uncertainties surrounding DOE's program
to provide for permanent disposal of spent nuclear fuel, I&M has not yet
commenced paying this fee. At December 31, 1993, funds collected from customers
to dispose of spent nuclear fuel and related earnings totaled $133,000,000.
I&M has received regulatory approval from all of its jurisdictions to recover
an approved level of decommissioning costs in revenues which amounted to
$13,000,000 in 1993, $12,000,000 in 1992 and $11,000,000 in 1991. An aggregate
amount of $170,000,000 had been set aside by I&M for nuclear decommissioning at
December 31, 1993. The recoveries were approved by I&M's state regulatory
commissions after the commissions reviewed studies by an independent consulting
firm employed by I&M (FERC recovery is based on an earlier study). The most
recent study estimates, based on changed conditions (related to delays in DOE's
program for disposal of spent nuclear fuel and other factors), that the cost of
post-shutdown fuel storage and decommissioning at the Cook Plant is in the
range of $588,000,000 to $1.102 billion in 1991 dollars for the cases studied.
The substantial increase is primarily due to the possible need to store spent
nuclear fuel at the plant site for an extended time after the plant ceases
operation, delaying the commencement of dismantling activities. Variables in
the length of time spent nuclear fuel must be stored at the plant subsequent to
ceasing operations, which is dependent on future developments in DOE's program
for disposal of spent nuclear fuel, have widened the range of the estimate. 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.
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 recent years, costs associated with nuclear plants have increased and
become less predictable, in large part due to changing regulatory requirements.
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, has become more uncertain.
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
26
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 in conjunction with approval of seven regional compacts,
including the Midwest Compact which governed the region in which the Cook Plant
is located.
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 completed construction of 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 about 7,000 cubic feet of low-level waste annually.
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
assessment is estimated to be approximately $58,320,000 subject to inflation
adjustments and is payable in annual assessments over 15 years commencing in
1993. I&M recorded a provision as a regulatory asset concurrent with the
recording of the liability. The first year estimated assessment has been
recorded as fuel expense and, under the provisions of the Energy Act, the
expense is being recovered in I&M's fuel rate adjustment proceedings.
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 expected to require substantial
expenditures for which management intends to seek recovery through increases in
the rates of AEP's operating subsidiaries. OPCo is expected to incur 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.
27
The CAAA creates 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 MW. 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 establishes sulfur dioxide
allowance limitations (caps or ceilings on emissions) premised upon sulfur
dioxide emissions at a rate of 2.5 pounds as of the Phase I deadline of January
1, 1995. The following AEP System plants 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; OPCo's Gavin Units 1-2, Muskingum River Units 1-5,
Cardinal Unit 1, Mitchell Units 1-2 and Kammer Units 1-3.
In the aggregate, these Phase I-affected units must annually limit emissions to
no more than Phase I allowances held beginning in 1995. Phase I-affected units
which are retrofitted with flue-gas desulfurization equipment (scrubbers) with
a removal efficiency of 90% or greater prior to January 1, 1997 may be
allocated a sufficient number of reserve allowances to provide a two-year
extension to comply with Phase I allowance limitations.
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 United States Court of Appeals for the District of Columbia
Circuit seeking a review of the regulations. Oral argument has been scheduled.
Phase I permit applications and compliance plans were filed for all Phase I-
affected units in the AEP System and Phase I permits have been issued for
Gavin, Muskingum River, Kammer and Breed plants. Proposed permits were issued
for Cardinal, Tidd, Mitchell, Conesville and Picway plants and for Amos Units 1
and 2, Big Sandy Unit 2, Glen Lyn Unit 6, Rockport Unit 1 and Tanners Creek
Unit 4. Pursuant to regulations promulgated by Federal EPA under Title IV of
the CAAA, Phase II affected units may be designated as substitution units in
Acid Rain Permit compliance plans. A Phase II substitution unit achieving the
applicable Phase I NOx emission limit in 1995 is exempt from any more stringent
Phase II NOx emission limits. Phase II units designated as substitution units
in AEP system compliance plans included Amos Units 1 and 2, Glen Lyn Unit 6,
Rockport Unit 1, Big Sandy Unit 2 and Tidd. Federal EPA is proposing to approve
substitution plans for certain of these units for the year 1995 only. For the
years 1996-1999, action would be taken based upon regulations then in effect.
On September 10, 1993, APCo, CSPCo, I&M, KEPCo and OPCo and a group of
unaffiliated utilities filed a petition in the U.S. Court of Appeals for the
District of Columbia Circuit seeking a review of the determination by Federal
EPA that it had authority to defer action on acid rain compliance plans.
Federal EPA has filed a motion to dismiss the appeal. On November 18, 1993,
Federal EPA published proposed rule revisions governing substitution and
reduced utilization plans which are generally more restrictive than those
currently in effect and would apply to Phase I substitution and compensating
unit plans for the years 1996-1999.
OPCo has filed an Early Ranking Application with Federal EPA for Gavin Units
1 and 2 seeking issuance of extension reserve allowances for both units based
on installation of scrubbers. Because of expected oversubscription of these
allowances, OPCo and other unaffiliated utilities formed an emission allowance
pool
28
to assure receipt of a portion of the allowances. In March 1993, Federal EPA
conducted a lottery to determine order of receipt of the allowances. OPCo's
application for Gavin Plant received a full allotment of the requested
allowances. Based on participation in the emission allowance pool, OPCo will
receive approximately 88% of the total allowances it requested.
All fossil fuel-fired generating units with capacity greater than 25 MW 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 no
later than 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 CAAA contemplates 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 reflect, to some extent, each method of compliance.
The acid rain title also contains provisions concerning nitrogen oxides
emissions. On March 1, 1994, the Federal EPA Administrator signed final
regulations governing nitrogen oxides emissions from tangentially fired and
dry bottom wall-fired boilers at Phase I units. For tangentially fired boilers
and dry bottom wall-fired boilers (other than units applying cell burner
technology), the proposed emission limitations are 0.45 pounds nitrogen oxides
per million Btu heat input and 0.50 pounds nitrogen oxides per million Btu
heat input, respectively, and must be achieved no later than January 1, 1995.
The five AEP System units which are subject to the January 1, 1995 Phase I
deadline are OPCo's Mitchell Units 1-2 and CSPCo's Conesville Units 3 and 4
and Picway Unit 5. With the exception of Conesville Unit 4 for which no
retrofit controls are deemed necessary to achieve Phase I NOx emission
limitations, the above units will be retrofitted to achieve these limits.
Capital expenditures for these activities are included as a component of the
cost of compliance with all Phase I requirements applicable to these units.
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 contains 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 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. 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 Department 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.
29
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 emission 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 has informed Congress that completion of this study will be delayed
significantly beyond the November 1993 deadline. 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 expands the enforcement authority of the Federal government by
increasing the range of civil and criminal penalties for violations of the
Clean Air Act and enhancing administrative civil provisions, adding a 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: Management reviewed the provisions of the
CAAA and evaluated various compliance strategies on a systemwide basis. The
selection of any compliance alternatives for the AEP System's generating plants
was dependent on the method of compliance selected for OPCo's Gavin Plant, one
of the AEP System's largest plants (2,600 mw) which emits about 25 percent of
the System's total sulfur dioxide emissions and about 44 percent of emissions
from OPCo's plants in Ohio. Alternatives considered for the Gavin Plant were
switching to low-sulfur coal which would come from mines outside Ohio or
installation of scrubbers which would allow the continued burning of high-
sulfur coal.
A systemwide Phase I CAAA compliance report was filed with the PUCO in 1991
comparing preliminary estimates of revenue requirements for the two compliance
alternatives at Gavin. Although the preliminary compliance report showed lower
projected AEP System revenue requirements for fuel switching rather than
installing OPCo-owned scrubbers, the PUCO issued an order which strongly
encouraged OPCo to keep both the fuel switching and scrubbing options open.
OPCo continued to study the alternatives and in April 1992 filed a Phase I CAAA
compliance plan.
OPCo's compliance plan filing was made under an Ohio law enacted in 1991 that
provides utilities with an opportunity to obtain advance PUCO approval of a
compliance plan provided that, among other things, the PUCO determines that it
represents a least-cost approach. Once approved by the PUCO, such plans are
deemed prudent for subsequent PUCO rate proceedings. On November 25, 1992, the
PUCO issued orders approving (i) OPCo's stipulation agreement with the PUCO
staff and the Ohio Consumers' Counsel regarding the predetermined price of coal
discussed below and in Rates and (ii) OPCo's compliance plan. The actual rate
treatment of costs associated with the compliance plan will be determined in a
future rate case. In March 1993, the Industrial Energy Consumers of OPCo (IEC)
and The Sierra Club each appealed the PUCO orders regarding the stipulation
agreement and compliance plan to the Supreme Court of Ohio. The IEC and Sierra
Club seek to overturn the PUCO decisions. OPCo has participated in these
proceedings.
The compliance plan sets forth, as part of an AEP System least-cost strategy,
compliance measures for the AEP System's affected generating units including
the installation of scrubbers at the Gavin Plant. In order to lower the cost of
compliance, the plan proposed to lease the scrubbers which are to be installed
at the Gavin Plant early in 1995. The plan also provides for Gavin to burn Ohio
high-sulfur coal supplied, in part, by OPCo's affiliated Meigs mine which will
operate at reduced capacity and in part by new long-term contracts with
unaffiliated sources and spot market purchases.
30
Under the terms of the compliance plan, OPCo's Muskingum River Unit 5 will
switch to low-sulfur coal by 1995 and Kammer Units 1-3 will switch to moderate
sulfur coal. The PUCO also indicated that management should take steps to have
Cardinal Unit 1 available for fuel switching for Phase I compliance. The PUCO
is examining in OPCo's current fuel clause proceeding whether it would be a
lower-cost alternative to fuel-switch Cardinal Unit 1 in Phase I rather than
Phase II as specified in AEP's compliance plan. CSPCo's Conesville Units 1-3
will be 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) will switch to moderate sulfur coal. Current plans
call for I&M's Tanners Creek Unit 4 to switch to moderate sulfur coal and for
retirement of I&M's Breed Plant in 1994. Eight additional units are subject to
Phase I rules, but no operating or fuel changes are planned, because they will
hold allowances sufficient for compliance.
Since the approved plan reflects fuel switching to comply at OPCo's
Muskingum River Plant and Cardinal Unit 1, mining operations at OPCo's other
wholly-owned coal-mining subsidiaries, Central Ohio Coal Company and Windsor
Coal Company, could be shut down. Central Ohio Coal Company and Windsor Coal
Company supply coal to Muskingum River Plant and Cardinal Plant, respectively.
The current plan for Central Ohio Coal Company provides for continuing at the
current operating level until mid-1994, and then reducing to approximately a
50% operating level until 1999. The cost of affiliated mine shutdowns would be
substantial. Shutdown costs for Central Ohio Coal Company and Windsor Coal
Company include investments in the mines, leased asset buy-outs, reclamation
and employee benefits and were estimated to be approximately $250,000,000 at
December 31, 1993. Management expects to recover costs of compliance with the
CAAA from ratepayers. Lack of recovery of the cost of CAAA compliance,
including the lease cost of the Gavin scrubbers and the investment in and cost
of closing affected affiliated mining operations, could materially adversely
affect AEP's and OPCo's results of operations and financial condition.
In August 1992 OPCo signed a stipulation agreement with the PUCO staff and
the Ohio Consumers' Counsel which provides that, among other things, the
recoverable cost of the Gavin scrubbers is not to exceed $815,000,000. The
scrubbers are currently under construction. See Construction and Financing
Program. Management expects that the cost of the scrubbers will be at least
10% less than this amount.
In September 1992 OPCo entered into an agreement for the lease of scrubbers
at the Gavin Plant with JMG Funding, Limited Partnership, an unaffiliated
entity. Under the terms of the agreement for lease, OPCo, as agent for JMG,
will build the scrubbers and upon completion, subject to certain conditions,
will lease the scrubbers from JMG. The agreement for lease provides for JMG to
pay the cost of construction. The lease will be accounted for as an operating
lease. On December 9, 1993, the PUCO approved the terms of the lease
agreement.
With respect to the construction of the scrubbers at the Gavin Plant, OPCo
has received a permit from the U.S. Army Corps of Engineers to conduct certain
activities in the navigable waters and affecting wetlands. Other
environmentally related permits have been received from state agencies or are
being sought.
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.
31
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 goes 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 President unveiled the Administration's Climate Change Action
Plan for meeting his 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 the U.S. Department of Energy. Known
as the Utility Climate Challenge, this initiative is intended to identify
voluntary, cost-effective measures to limit or offset future greenhouse gas
emissions. Although AEP is participating in this effort, such actions will not
be undertaken if they threaten the AEP System's economic competitiveness or if
they are unacceptable to its regulators.
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 controls on carbon dioxide emissions if the compliance costs
incurred are not fully recovered from ratepayers. In addition, any program to
stabilize or reduce carbon dioxide emissions is expected to impose substantial
costs on industry and society, and could 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.
On March 9, 1993, Federal EPA, Region V, issued a notice of violation
alleging that Stuart Station (owned by CSPCo, CG&E and DP&L) was in violation
of Ohio's State Implementation Plan rules relating to opacity. This notice of
violation has been resolved without penalty.
West Virginia: The West Virginia Air Pollution Control Commission
promulgated sulfur dioxide limitations effective February 1978. Federal EPA
has approved these regulations as they apply to APCo's and OPCo's plants,
except for OPCo's Mitchell and Kammer Plants. 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 of the lengthy time and uncertainty associated
with the stack height rulemaking and litigation discussed in detail below, it
is not certain when Federal EPA will take dispositive action regarding the
Mitchell and Kammer Plants.
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. OPCo
32
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. Federal EPA has yet to commence
administrative proceedings to incorporate changes in the 1985 stack height
rules as mandated by the January 1988 court decision.
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.
Administrative Developments Regarding Sulfur Dioxide: Federal EPA, in the
Federal Register dated April 26, 1988, issued a "provisional" decision that
proposed to retain present national ambient air quality standards for sulfur
dioxide and did not propose adoption of a new, more restrictive, short-term
primary (health-related) standard. Federal EPA is expected to issue a final
rule after its review of public comments filed in response to the proposed
rule. In the context of this sulfur dioxide standard rulemaking, Federal EPA is
considering a number of significant policy changes in the rules governing
sulfur dioxide emissions. Principal among these possible regulatory changes is
the adoption of a new, short-term primary national ambient air quality standard
for sulfur dioxide. Adoption of any of these changes could require substantial
reductions in sulfur dioxide emissions from the System's coal-fired generating
plants which would entail substantial capital and operating costs.
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.
33
All System Plants are operating with NPDES permits. These will expire during
the time period 1994-96, except for Breed Plant's permit which has expired, but
for which a timely renewal application was filed. 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 1994.
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, except for Conesville and Muskingum River Plants for which
thermal variances expired on May 1, 1993. Requests for revised thermal
variances for these two plants have been made but the permitting agency has not
made a final determination on the requests. If thermal variances for these
plants are not renewed, the plants could be required to reduce generation,
particularly in late summer months.
Certain mining operations conducted by System companies as discussed under
Fuel Supply are also subject to Federal and state water pollution control
requirements, which may entail substantial expenditures for control facilities,
not included at present in the System's construction cost estimates set forth
herein. See Item 3. Legal Proceedings--Meigs Mine with respect to litigation
regarding certain discharges from OPCo's Meigs Mines.
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.
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 nine federal sites, including I&M at five 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.
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. 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.
34
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.
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 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. On March 22, 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 would
have to provide estimates of EMF from transmission lines under a
35
variety of conditions. In addition, applicants would be required to address
possible health effects and discuss the consideration of design alternatives
with respect to EMF.
In April 1993, the State of Indiana enacted a law which provides that the
IURC shall determine, based on the preponderance of evidence in the scientific
literature, whether rules are necessary to protect the public health from EMF.
If the IURC determines that such rules are necessary, the IURC is required to
adopt rules that reasonably protect the public health from EMF.
Management cannot predict the ultimate impact of the question of EMF exposure
and adverse health effects. If further research shows that EMF exposure
contributes to increased risk of cancer or other health problems, or if the
courts conclude that EMF exposure harms individuals and that utilities are
liable for damages, or if states limit the strength of magnetic fields to such
a level that the current electricity delivery system must be significantly
changed, then the results of 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 towards developing more efficient methods of burning coal,
reducing the contaminants resulting from combustion of coal, and improving the
efficiency and reliability of power transmission and distribution, 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 over four years. AEP's operating companies intend to seek 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 $13,700,000 for the year ended December 31, 1993, $14,200,000 for
the year ended December 31, 1992 and $15,100,000 for the year ended December
31, 1991 including $10,900,000, $11,700,000 and $11,900,000, respectively, for
Tidd Plant and related PFBC costs.
36
Item 2.PROPERTIES
- --------------------------------------------------------------------------------
At December 31, 1993, subsidiaries of AEP owned (or leased where indicated)
generating plants with the net power capabilities (winter rating) shown in the
following table:
NET
OWNER, KILOWATT
PLANT TYPE AND NAME LOCATION (NEAR) CAPABILITY
--------------------- ---------------- -----------
AEP Generating Company:
Steam -- Coal-Fired:
Rockport Plant (AEGCo share) Rockport, Indiana 1,300,000(a)
----------
Appalachian Power Company:
Steam -- Coal-Fired:
John E. Amos, Units 1 & 2 St. Albans, West Virginia 1,600,000
John E. Amos, Unit 3 (APCo share) St. Albans, West Virginia 433,000(b)
Clinch River Carbo, Virginia 705,000
Glen Lyn Glen Lyn, Virginia 335,000
Kanawha River Glasgow, West Virginia 400,000
Mountaineer New Haven, West Virginia 1,300,000
Philip Sporn, Units 1 & 3 New Haven, West Virginia 308,000
Hydroelectric -- Conventional:
Buck Ivanhoe, Virginia 10,000
Byllesby Byllesby, Virginia 20,000
Claytor Radford, Virginia 76,000
Leesville Leesville, Virginia 40,000
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
----------
37
NET
OWNER, KILOWATT
PLANT TYPE AND NAME LOCATION (NEAR) CAPABILITY
--------------------- ---------------- -----------
Indiana Michigan Power Company:
Steam -- Coal-Fired:
Breed Sullivan, Indiana 325,000(d)
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(e)
Hydroelectric -- Conventional:
Berrien Springs Berien 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
----------
4,759,000
----------
Kanawha Valley Power Company:
Hydroelectric -- Conventional:
London Montgomery, West Virginia 16,000
Marmet Marmet, West Virginia 16,000
Winfield Winfield, West Virginia 19,000
----------
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
Kammer Captina, West Virginia 630,000
Mitchell Captina, West Virginia 1,600,000
Muskingum River Beverly, Ohio 1,425,000
Philip Sporn, Units 2, 4 & 5 New Haven, West Virginia 742,000
Hydroelectric -- Conventional:
Racine Racine, Ohio 48,000
----------
8,512,000
----------
Total Generating
Capability............. 24,084,000
==========
38
NET
OWNER, KILOWATT
PLANT TYPE AND NAME LOCATION (NEAR) CAPABILITY
- --------------------- ---------------- -----------
Summary:
Total Steam --
Coal-Fired..................................................... 21,120,000
Nuclear........................................................ 2,110,000
Total Hydroelectric --
Conventional................................................... 271,000
Pumped Storage................................................. 565,000
Other........................................................... 18,000
----------
Total Generating Capability..................... 24,084,000
==========
- --------
(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) I&M plans to close the Breed Plant on March 31, 1994.
(e) 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.
See Item 1 under Fuel Supply, for information concerning coal reserves owned
or controlled by subsidiaries of AEP.
The following table sets forth the total circuit miles of transmission and
distribution lines of the AEP System, APCo, CSPCo, I&M, KEPCo and OPCo and that
portion of the total representing 765,000-volt lines:
TOTAL CIRCUIT MILES
OF TRANSMISSION AND CIRCUIT MILES OF
DISTRIBUTION LINES 765,000-VOLT LINES
-------------------- -------------------
AEP System (a) 123,357(b) 2,022
APCo 48,190 641
CSPCo (a) 13,937 --
I&M 20,634 614
KEPCo 9,735 258
OPCo 27,941 509
- --------
(a)Includes 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.
39
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
1993 one-hour peak demands were 25,174,000 and 22,142,000 kilowatts,
respectively, (including 6,459,000 and 4,043,000 kilowatts, respectively, of
scheduled deliveries to unaffiliated systems which the System might, on
appropriate notice, have elected not to schedule for delivery) and occurred on
January 18, 1994 and July 26, 1993, respectively. The net dependable capacity
to serve the System load on such dates, including power available under
contractual obligations, was 24,202,000 and 23,896,000 kilowatts, respectively.
The all-time and 1993 one-hour internal peak demands were 19,236,000 and
18,085,000 kilowatts, respectively, and occurred on January 19, 1994 and July
28, 1993, respectively. The net dependable capacity to serve the System load on
such dates, including power available under contractual arrangements, was
24,202,000 and 23,896,000 kilowatts, respectively. The all-time one-hour
integrated and internal net system peak demands and 1993 peak demands for AEP's
generating subsidiaries are shown in the following tabulation:
ALL-TIME ONE-HOUR INTEGRATED 1993 ONE-HOUR INTEGRATED
NET SYSTEM PEAK DEMAND NET SYSTEM PEAK DEMAND
----------------------------- -----------------------------
(IN THOUSANDS)
NUMBER OF NUMBER OF
KILOWATTS DATE KILOWATTS DATE
----------- ----- ----------- ----
APCo 8,203 January 19, 1994 6,472 July 7, 1993
CSPCo 3,778 January 18, 1994 3,740 July 9, 1993
I&M 4,700 February 12, 1986 4,312 August 26, 1993
KEPCo 1,575 January 19, 1994 1,340 July 26, 1993
OPCo 7,034 January 18, 1994 6,271 July 26, 1993
ALL-TIME ONE-HOUR INTEGRATED 1993 ONE-HOUR INTEGRATED
NET INTERNAL PEAK DEMAND NET INTERNAL PEAK DEMAND
----------------------------- -----------------------------
(IN THOUSANDS)
NUMBER OF NUMBER OF
KILOWATTS DATE KILOWATTS DATE
----------- ----- ----------- ----
APCo 6,887 January 19, 1994 5,906 February 19, 1993
CSPCo 3,167 August 30, 1993 3,167 August 30, 1993
I&M 3,513 August 17, 1988 3,468 August 27, 1993
KEPCo 1,309 January 19, 1994 1,218 February 19, 1993
OPCo 5,436 January 21, 1994 5,302 August 27, 1993
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. One new license was issued in March 1994.
40
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 100% during 1993 and 64.8% during 1992. 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 96.6% during 1993 and 19.5% during 1992. The availability of Units 1 and 2
was affected in 1992 by outages to refuel and Unit 2 main turbine/generator
vibrational problems.
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.
NUCLEAR INSURANCE
The Price-Anderson Act limits public liability for a nuclear incident at any
nuclear plant in the United States to $9.4 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 $9.4 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
$2.75 billion. Nuclear insurance pools provide $1.265 billion of coverage and
Nuclear Electric Insurance Limited (NEIL) and Energy Insurance Bermuda (EIB)
provide the remainder. If NEIL's and EIB's losses exceed their available
resources, I&M would be subject to a total retrospective premium assessment of
up to $15,327,023. 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 $2.5 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 $2.5 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, $2,350,000 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 $8,929,456.
POTENTIAL UNINSURED LOSSES
Some potential losses or liabilities may not be insurable or the amount of
insurance carried may not be sufficient to meet potential losses and
liabilities, including liabilities relating to damage to the Cook Plant and
costs of replacement power in the event of a nuclear incident at the Cook
Plant. Future losses or liabilities which are not completely insured, unless
allowed to be recovered through rates, could have a material adverse effect on
results of operation and the financial condition of AEP, I&M and other AEP
System companies.
41
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 begun an appeal 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. The administrative
law judge has set for trial the case of an unaffiliated mine to determine if
there was an intentional alteration of the dust sampling filter. All remaining
cases, including the citations involving OPCo's mines, have been stayed.
On September 21, 1993, CSPCo was served with a complaint issued by Region V,
Federal EPA which alleged violations by Conesville Plant of the Toxic
Substances Control Act and proposed a penalty of $41,000. 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. On October 4, 1993, OPCo was served with a complaint issued by Region
V, Federal EPA which alleged violations by OPCo's General Service Center
(Canton, Ohio) of the Toxic Substances Control Act and proposed a penalty of
$24,000. Settlement discussions have been held in each of these cases and it is
expected that these matters will be resolved shortly.
On June 18, 1993, OPCo was served with a complaint issued by Region V,
Federal EPA which alleged violations by Muskingum River Plant of the Toxic
Substances Control Act and proposed a penalty of $87,000. In February 1994,
OPCo paid a penalty of $12,185 and agreed to undertake supplemental
environmental projects in 1994 valued at $61,547.
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
42
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. 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.
Since September 16, 1993, SOCCo has processed all water removed from the mine
through its expanded treatment system and is in compliance with the effluent
limitations in its water discharge permit. Pumping has removed most of the
water that entered the mine on July 11 and the mine was returned to service in
February 1994.
On July 26, 1993, the Ohio Department of Natural Resources Division of
Reclamation issued an administrative order directing SOCCo to cease pumping due
to that agency's concern over possible environmental harm. On July 26, 1993,
following SOCCo's appeal of the cessation order, the chairman of the
Reclamation Board of Review issued a temporary stay pending a hearing by the
full Reclamation Board. On January 14, 1994, the administrative proceeding was
settled on the basis of agreements by the Division of Reclamation to dismiss
the administrative order and by SOCCo to treat all water removed from the mine
in accordance with its discharge permit and to pay certain expenses of the
Division of Reclamation.
On August 19, 1993, the U.S. District Court for the Southern District of Ohio
granted SOCCo's motion for a preliminary injunction against the Federal Office
of Surface Mining Reclamation and Enforcement ("OSM") and Federal EPA
preventing them from exercising jurisdiction to issue orders to cease pumping.
On August 30, 1993, the U.S. Court of Appeals for the Sixth Circuit denied
OSM's motion for a stay of the District Court's preliminary injunction but
granted Federal EPA's motion for a stay in part which allowed Federal EPA to
investigate and make findings with respect to alleged violations of the Clean
Water Act and thereafter to exercise its enforcement authority under the Clean
Water Act if a violation was identified. On September 2, 1993, Federal EPA
issued an administrative order requiring a partial cessation of pumping, the
effect of which was delayed by Federal EPA until September 8, 1993. On
September 8, 1993, the District Court granted SOCCo's motion requesting that
enforcement of the Federal EPA order be stayed. On September 23, 1993, the
Court of Appeals ruled that the District Court could not review the Federal EPA
order in the absence of a civil enforcement action and lifted the stay. A
further decision of the Court of Appeals with respect to the appeal of the
preliminary injunction is pending.
On January 3, 1994, the District Court held that the complaint filed by SOCCo
should not be dismissed and concluded that sufficient legal and factual grounds
existed for the court to consider SOCCo's claim that Federal EPA could not
override Ohio EPA's authorization for SOCCo to bypass its water treatment
system on an emergency basis during pumping activities. In a separate opinion,
the District Court denied Federal EPA's request that the District Court defer
consideration of SOCCo's motion involving a request for a Declaration of Rights
with respect to the mine water releases into area streams.
The West Virginia Division of Environmental Protection ("West Virginia DEP")
has 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. SOCCo is meeting with the West
Virginia DEP in an attempt to resolve this matter.
Although management is unable to predict what enforcement action Federal EPA
or OSM may take, the resolution of the aforementioned litigation, environmental
mitigation costs and mine restoration costs are not expected to have a material
adverse impact on results of operations or financial condition.
43
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, 1994.
NAME AGE OFFICE (A)
---- --- ----------
E. Linn Draper, Jr... 52 Chairman of the Board, President and Chief
Executive Officer of AEP and of the Service
Corporation
Peter J. DeMaria..... 59 Treasurer of AEP; Executive Vice President-
Administration and Chief Accounting Officer of the
Service Corporation
William J. Lhota..... 54 Executive Vice President of the Service Corporation
A. Joseph Dowd....... 64 Secretary of AEP; Senior Vice President, General
Counsel and Assistant Secretary of the Service
Corporation
Charles A. Ebetino, Senior Vice President-Fuel Supply of the Service
Jr.................. 41 Corporation
Gerald P. Maloney.... 61 Vice President of AEP; Executive Vice President-
Chief Financial Officer of the Service Corporation
James J. Markowsky... 49 Executive Vice President--Engineering &
Construction of the Service Corporation
- --------
(a) All of the executive officers listed above have been employed by the
Service Corporation or System companies in various capacities (AEP, as
such, has no employees) during the past five years, except E. Linn Draper,
Jr. who was Chairman of the Board, President and Chief Executive Officer of
Gulf States Utilities Company from 1987 until 1992 when he joined AEP and
the Service Corporation. All of the above officers are appointed annually
for a one-year term by the board of directors of AEP, the board of
directors of the Service Corporation, or both, as the case may be.
APCO
The names of the executive officers of APCo, the positions they hold with
APCo, their ages as of March 15, 1994, 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.
NAME AGE POSITION (A) PERIOD
---- --- ------------ ------
E. Linn Draper, Jr... 52 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.. 53 Director 1985-Present
President and Chief Operating
Officer 1990-Present
Executive Vice President 1989-1990
Vice President 1985-1989
Executive Vice President-Operations
of the Service Corporation 1984-1989
44
NAME AGE POSITION (A) PERIOD
---- --- ------------ ------
Peter J. DeMaria......... 59 Director 1988-Present
Vice President 1991-Present
Treasurer 1978-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
A. Joseph Dowd........... 64 Director and Vice President 1977-Present
Secretary of AEP 1974-Present
Senior Vice President and General
Counsel of the Service
Corporation 1975-Present
Assistant Secretary of the
Service Corporation 1969-Present
William J. Lhota......... 54 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
President and Chief Operating
Officer of CSPCo 1987-1989
Gerald P. Maloney........ 61 Director and Vice President 1970-Present
Vice President of AEP 1974-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....... 49 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
Senior Vice President-Fuel Supply
Charles A. Ebetino, Jr. . 41 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
- --------
(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, 1994, 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.
NAME AGE POSITION (A) PERIOD
---- --- ------------ ------
E. Linn Draper, Jr. . 52 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
Director, President and Chief
Carl A. Erikson...... 43 Operating Officer 1993-Present
Vice President 1990-1992
Vice President of the Service
Corporation and Executive Assistant
to E. Linn Draper, Jr. 1992-Present
Assistant to Executive Vice
President-Operations of the Service
Corporation 1989-1990
Peter J. DeMaria..... 59 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
45
NAME AGE POSITION (A) PERIOD
---- --- ------------ ------
A. Joseph Dowd....... 64 Director and Vice President 1977-Present
Secretary of AEP 1974-Present
Senior Vice President and General
Counsel of the Service Corporation 1975-Present
Assistant Secretary of the Service
Corporation 1969-Present
William J. Lhota..... 54 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
President and Chief Operating
Officer of CSPCo 1987-1989
Gerald P. Maloney.... 61 Director 1973-Present
Vice President 1970-Present
Vice President of AEP 1974-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.... 49 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. Ebertino, Senior Vice President-Fuel Supply of
Jr.................. 41 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
- --------
(a)Positions are with OPCo unless otherwise indicated.
46
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.
PER SHARE
---------------
QUARTER ENDED MARKET PRICE
- ------------- ---------------
HIGH LOW DIVIDEND(1)
------- ------- -----------
March 1992.......................................... $34 1/4 $30 3/8 $.60
June 1992........................................... 32 5/8 30 3/8 .60
September 1992...................................... 35 1/4 31 3/4 .60
December 1992....................................... 33 3/8 30 3/4 .60
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
- --------
(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, 1993, AEP had approximately 194,000 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
1993 Annual Report (for the fiscal year ended December 31, 1993).
APCO. The information required by this item is incorporated herein by
reference to the material under Selected Consolidated Financial Data in the
APCo 1993 Annual Report (for the fiscal year ended December 31, 1993).
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
1993 Annual Report (for the fiscal year ended December 31, 1993).
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 1993 Annual Report (for the fiscal year ended December 31, 1993).
47
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 1993
Annual Report (for the fiscal year ended December 31, 1993).
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 1993 Annual Report (for the
fiscal year ended December 31, 1993).
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 1993 Annual Report (for the
fiscal year ended December 31, 1993).
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 1993
Annual Report (for the fiscal year ended December 31, 1993).
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 1993 Annual Report (for the
fiscal year ended December 31, 1993).
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 1993
Annual Report (for the fiscal year ended December 31, 1993).
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 1993 Annual Report (for the
fiscal year ended December 31, 1993).
Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- --------------------------------------------------------------------------------
AEGCO. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
AEP. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
APCO. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
CSPCO. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
I&M. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
48
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.
49
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 10, 1994, for the 1994 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 1994 annual meeting of stockholders, to
be filed within 120 days after December 31, 1993. 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, 1994, 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.
NAME AGE POSITION (A)(B)(C) PERIOD
---- --- ------------------ ------
E. Linn Draper, Jr. . 52 Director 1992-Present
Chairman of the Board and Chief 1993-Present
Executive Officer
Vice President 1992-1993
Chairman of the Board, President and 1993-Present
Chief Executive Officer of AEP
and of the Service Corporation
President of AEP 1992-1993
President and Chief Operating 1992-1993
Officer of the Service Corporation
Chairman of the Board, President and 1987-1992
Chief Executive Officer of Gulf
States Utilities Company
Richard C. Menge..... 58 Director 1976-Present
President and Chief Operating 1989-Present
Officer
Mark A. Bailey....... 41 Director and Vice President 1989-Present
Peter J. DeMaria..... 59 Director 1992-Present
Vice President 1991-Present
Treasurer 1978-Present
Treasurer of AEP 1978-Present
Executive Vice President- 1984-Present
Administration and Chief Accounting
Officer of the Service Corporation
Treasurer of the Service Corporation 1989-1990
William N. D'Onofrio. 45 Director and Vice President 1984-Present
A. Joseph Dowd....... 64 Director 1993-Present
Vice President 1977-Present
Secretary of AEP 1974-Present
Senior Vice President and General 1975-Present
Counsel of the Service Corporation
Assistant Secretary of the Service 1969-Present
Corporation
50
NAME AGE POSITION (A)(B)(C) PERIOD
---- --- ------------------ ------
William J. Lhota..... 54 Director and Vice President 1989-Present
Executive Vice President of the 1993-Present
Service Corporation
Executive Vice President-Operations 1989-1993
of the Service Corporation
Gerald P. Maloney.... 61 Director 1978-Present
Vice President 1970-Present
Vice President of AEP 1974-Present
Executive Vice President-Chief 1991-Present
Financial Officer of the Service
Corporation
Senior Vice President-Finance of the 1974-1990
Service Corporation
R. E. Prater......... 43 Director 1993-Present
Division Manager 1989-Present
D. B. Synowiec....... 50 Director 1993-Present
Plant Manager 1990-1993
Assistant Plant Manager 1983-1990
W. E. Walters........ 46 Director 1991-Present
Executive Assistant to President 1987-Present
Charles A. Ebetino, Senior Vice President-Fuel Supply of 1993-Present
Jr. ................. 41 the Service Corporation
Vice President-Fuel Procurement & 1990-1993
Transportation of the Service
Corporation
Managing Director-Coal Procurement 1986-1990
of the Service Corporation
Vice President 1993-Present
James J. Markowsky... 49 Executive Vice President-Engineering 1993-Present
& Construction of the Service
Corporation
Senior Vice President and Chief 1988-1993
Engineer of the Service Corporation
- --------
(a)Positions are with I&M unless otherwise indicated.
(b)Dr. Draper is a director of Pacific Nuclear Systems, Inc. and Mr. Lhota is
a director of Huntington Bancshares Incorporated.
(c)Messrs. DeMaria, Dowd, Draper, Lhota and Maloney are directors of AEGCo,
APCo, CSPCo, KEPCo and OPCo. Messrs. DeMaria, Dowd, Draper 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 1994 annual meeting of
shareholders, to be filed within 120 days after December 31, 1993. Reference
also is made to the information under the caption Executive Officers of the
Registrants in Part I of this report.
Item 11.EXECUTIVE COMPENSATION
- -------------------------------------------------------------------------------
AEGCO. Omitted pursuant to Instruction J(2)(c).
AEP. The information required by this item is incorporated herein by
reference to the material under Compensation of Directors, Executive
Compensation and the performance graph of the definitive proxy statement of
AEP, dated March 10, 1994, for the 1994 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 1994 annual meeting of stockholders, to
be filed within 120 days after December 31, 1993.
CSPCO. Omitted pursuant to Instruction J(2)(c).
KEPCO. Omitted pursuant to Instruction J(2)(c).
51
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 1994 annual meeting of shareholders, to
be filed within 120 days after December 31, 1993.
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 1993, 1992 and 1991 the compensation earned
from all AEP System companies by (i) 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, 1993 and (ii) a chief executive officer and
executive officer, both of whom retired in 1993.
Summary Compensation Table
ANNUAL COMPENSATION
---------------------------------
ALL OTHER
SALARY BONUS COMPENSATION
NAME AND PRINCIPAL POSITION YEAR ($) ($)(1) ($)(2)
--------------------------- ---- ------- ------- ------------
E. LINN DRAPER, JR.--Chairman of the board 1993 538,333 148,742 18,180
and chief executive officer of I&M; chairman 1992 395,833 8,730 63,700
of the board, president and chief executive
officer of AEP and the Service Corporation;
chairman of the board and chief executive
officer of other AEP System companies (3)
RICHARD E. DISBROW--Chairman of the board and 1993 200,000 55,260 102,753
chief executive officer of I&M, AEP, the 1992 600,000 13,234 17,676
Service Corporation and other AEP System 1991 540,000 86,994 17,272
companies (3)
PETER J. DEMARIA--Vice president, treasurer 1993 280,000 77,364 17,811
and director of I&M; treasurer and director 1992 273,000 6,021 15,576
of AEP; executive vice president- 1991 258,000 41,564 14,987
administration and chief accounting officer
and director of the Service Corporation;
vice president, treasurer and director of
other AEP System companies
JOHN E. KATLIC--Senior vice president-fuel 1993 279,167 74,677 45,452
supply and director of the Service 1992 325,000 6,400 9,396
Corporation; president, chief operating 1991 300,000 38,419 9,402
officer and director of coal mining
subsidiaries (retired October 31, 1993)
G. P. MALONEY--Vice president and director of 1993 269,000 74,325 18,000
I&M; vice president of AEP; executive vice 1992 261,000 5,757 17,036
president-chief financial officer and 1991 246,000 39,631 16,662
director of the Service Corporation; vice
president and director of other AEP System
companies
A. JOSEPH DOWD--Vice president and director 1993 268,000 61,707 15,760
of I&M; secretary and director of AEP; 1992 260,000 4,779 13,876
senior vice president, general counsel, 1991 245,000 32,891 14,002
assistant secretary and director of the
Service Corporation; vice president and
director of other AEP System companies
WILLIAM J. LHOTA--Vice president and director 1993 249,000 68,799 17,160
of I&M; executive vice president and 1992 230,000 5,073 15,116
director of the Service Corporation; vice 1991 210,000 33,831 14,385
president and director of other AEP System
companies
- --------
(1) Reflects payments under the AEP Management Incentive Compensation Plan
("MICP") in which individuals in key management positions with AEP System
companies participate. Amounts for 1993 are estimates but should not
change significantly. For 1991 and 1993, these amounts included 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 during the three-
year period. At December 31, 1993, Dr. Draper and Messrs. DeMaria,
Maloney, Dowd and Lhota held 813, 746, 715, 593 and 639 units having a
value of $30,177, $27,701, $26,526, $22,020 and $23,730, respectively,
based upon a $37 1/8 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.
52
(2) Includes amounts contributed by AEP System companies under the American
Electric Power System Employees Savings Plan on behalf of their employee
participants. For 1993 this amount was $7,075 for Dr. Draper and Messrs.
Katlic, Maloney, Dowd and Lhota and $6,000 for Mr. Disbrow and $7,006 for
Mr. DeMaria. The AEP System Savings Plan is available to all employees of
AEP System companies (except for employees covered by certain collective
bargaining agreements) who have met minimum service requirements.
Includes director's fees for AEP System companies. For 1993 these fees were:
Dr. Draper, $11,105; Mr. Disbrow, $3,580; Mr. DeMaria, $10,805; Mr. Katlic,
$2,300; Mr. Maloney, $10,925; Mr. Dowd, $8,685; and Mr. Lhota, $10,085.
Includes payments of $93,173 and $36,077 for unused accrued vacation which
Messrs. Disbrow and Katlic, respectively, received upon their retirement.
(3) Dr. Draper was elected chairman of the board and chief executive officer
of I&M and other AEP System companies and chairman of the board, president
and chief executive officer of AEP and the Service Corporation, succeeding
Mr. Disbrow, who retired, effective April 28, 1993.
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
YEARS OF ACCREDITED SERVICE
-----------------------------------------------------
HIGHEST AVERAGE
ANNUAL EARNINGS 15 20 25 30 35 40
- --------------- -------- -------- -------- -------- -------- --------
$250,000................. $ 58,155 $ 77,540 $ 96,925 $116,310 $135,695 $152,230
350,000................. 82,155 109,540 136,925 164,310 191,695 214,970
450,000................. 106,155 141,540 176,925 212,310 247,695 277,620
550,000................. 130,155 173,540 216,925 260,310 303,695 340,270
700,000................. 166,155 221,540 276,925 332,310 387,695 434,245
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. With respect to Messrs. Disbrow and Katlic, since they
retired in 1993, the amounts of $600,000 and $316,944, respectively, are the
actual salaries upon which their retirement benefits are based. Mr. Disbrow's
retirement benefit was enhanced by computing his benefit based on his 1992
base salary. As of December 31, 1993, the number of full years of service
credited under the Retirement Plan to each of the executive officers of I&M
named in the Summary Compensation Table were as follows: Dr. Draper, 1 year;
Mr. Disbrow, 39 years; Mr. DeMaria, 34 years; Mr. Katlic, 10 years; Mr.
Maloney, 38 years; Mr. Dowd, 31 years; and Mr. Lhota, 29 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.
53
Mr. Katlic has a contract with the Service Corporation under which the
Service Corporation agrees to provide him with a supplemental retirement
annuity equal to the annual pension that Mr. Katlic would have received with
service of 30 years under the AEP System Retirement Plan as then in effect,
less his actual annual pension entitlement under the Retirement Plan. Mr.
Katlic commenced receiving his supplemental annuity upon his retirement
effective October 31, 1993.
AEP has determined to pay supplemental retirement benefits to 23 AEP System
employees (including Messrs. Disbrow, DeMaria, Maloney and Lhota) 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. Upon his retirement on
April 28, 1993, Mr. Disbrow began receiving an annual supplemental benefit of
$2,642. Assuming retirement of the remaining eligible employees in 1994, 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.
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)
- ---- -------- ---------------- -------- ----------------
Mr. Disbrow................. $15,000 $54,375 -- --
Mr. DeMaria................. 10,000 52,000 $13,000 $53,300
Mr. Katlic.................. 15,000 24,500 -- --
Mr. Maloney................. 15,000 67,500 16,000 56,400
Mr. Dowd.................... 10,000 34,000 10,000 25,500
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.
54
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 10, 1994, for
the 1994 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 1994 annual
meeting of stockholders, to be filed within 120 days after December 31, 1993.
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 that were
beneficially owned, directly or indirectly, as of December 31, 1993, 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.
AMOUNT AND NATURE OF
BENEFICIAL OWNERSHIP (A)
------------------------
Mark A. Bailey................................. 594
Peter J. DeMaria............................... 5,789(b)(c)
Richard E. Disbrow............................. 9,822(b)
William N. D'Onofrio........................... 2,948
A. J. Dowd..................................... 4,707
E. Linn Draper, Jr............................. 951(b)
J. E. Katlic................................... 2,290
William J. Lhota............................... 6,673(b)(c)
Gerald P. Maloney.............................. 4,227(b)(c)
Richard C. Menge............................... 2,652(b)
R. E. Prater................................... 1,609
D. B. Synowiec................................. 1,808
W. E. Walters.................................. 3,729
All directors and executive officers as a group
(13 persons).................................. 125,076(c)(d)
- --------
(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, 550 shares; Mr. DeMaria, 2,081
shares; Mr. Disbrow, 4,027 shares; Mr. D'Onofrio, 2,889 shares; Mr.
Katlic, 2,230 shares; Mr. Lhota, 5,245 shares; Mr. Maloney, 2,142 shares;
Mr. Menge, 2,566 shares; Mr. Prater, 1,561 shares; Mr. Synowiec, 1,754
shares; Mr. Walters, 3,685 shares; and all directors and executive
officers as a group, 33,806 shares. Messrs. Disbrow's, Dowd's and
Maloney's holdings include 85 shares each; Messrs. Bailey's, DeMaria's,
D'Onofrio's, Katlic's, Lhota's, Menge's, Prater's, Synowiec's, and
Walter's holdings include 44, 83, 59, 60, 60, 62, 48, 53 and 45 shares,
respectively; and the holdings of all directors and executive officers as
a group include 738 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.
55
(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. Disbrow, 283 shares; Mr. Draper, 115 shares;
Mr. Lhota, 1,368 shares; Mr. Maloney, 2,000 shares; Mr. Menge, 24 shares;
and all directors and executive officers as a group, 7,883 shares. Mr.
DeMaria disclaims beneficial ownership of 807 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 (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, 1993.
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 1994 annual
meeting of shareholders, to be filed within 120 days after December 31, 1993.
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 10, 1994, for the 1994 annual meeting of
shareholders.
APCO, I&M AND OPCO. None.
AEGCO, CSPCO, AND KEPCO. Omitted pursuant to Instruction J(2)(c).
56
PART IV -------------------------------------------------------------------
Item 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
- --------------------------------------------------------------------------------
(a) The following documents are filed as a part of this report:
1. Financial Statements: 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, 1993, 1992 and 1991; Statements of Retained Earnings for
the years ended December 31, 1993, 1992 and 1991; Balance Sheets as
of December 31, 1993 and 1992; Statements of Cash Flows for the years
ended December 31, 1993, 1992 and 1991; Notes to Financial
Statements.
AEP and its subsidiaries consolidated:
Consolidated Statements of Income for the years ended December 31,
1993, 1992 and 1991; Consolidated Statements of Retained Earnings for
the years ended December 31, 1993, 1992 and 1991; Consolidated
Statements of Cash Flows for the years ended December 31, 1993, 1992
and 1991; Consolidated Balance Sheets as of December 31, 1993 and
1992; Notes to Consolidated Financial Statements; Schedule of
Cumulative Preferred Stocks of Subsidiaries at December 31, 1993 and
1992; Schedule of Consolidated Long-term Debt Outstanding at December
31, 1993 and 1992; Independent Auditors' Report.
APCo:
Independent Auditors' Report; Consolidated Statements of Income for the
years ended December 31, 1993, 1992 and 1991; Consolidated Balance
Sheets as of December 31, 1993 and 1992; Consolidated Statements of
Cash Flows for the years ended December 31, 1993, 1992 and 1991;
Consolidated Statements of Retained Earnings for the years ended
December 31, 1993, 1992 and 1991; Notes to Consolidated Financial
Statements.
CSPCo:
Independent Auditors' Report; Consolidated Statements of Income for the
years ended December 31, 1993, 1992 and 1991; Consolidated Balance
Sheets as of December 31, 1993 and 1992; Consolidated Statements of
Cash Flows for the years ended December 31, 1993, 1992 and 1991;
Consolidated Statements of Retained Earnings for the years ended
December 31, 1993, 1992 and 1991; Notes to Consolidated Financial
Statements.
I&M:
Independent Auditors' Report; Consolidated Statements of Income for the
years ended December 31, 1993, 1992 and 1991; Consolidated Balance
Sheets as of December 31, 1993 and 1992; Consolidated Statements of
Cash Flows for the years ended December 31, 1993, 1992 and 1991;
Consolidated Statements of Retained Earnings for the years ended
December 31, 1993, 1992 and 1991; Notes to Consolidated Financial
Statements.
KEPCo:
Independent Auditors' Report; Statements of Income for the years ended
December 31, 1993, 1992 and 1991; Statements of Retained Earnings for
the years ended December 31, 1993, 1992 and 1991; Statements of Cash
Flows for the years ended December 31, 1993, 1992 and 1991; Balance
Sheets as of December 31, 1993 and 1992; Notes to Financial
Statements.
57
PAGE
----
OPCo:
Independent Auditors' Report; Consolidated Statements of Income for the
years ended December 31, 1993, 1992 and 1991; Consolidated Balance
Sheets as of December 31, 1993 and 1992; Consolidated Statements of
Cash Flows for the years ended December 31, 1993, 1992 and 1991;
Consolidated Statements of Retained Earnings for the years ended
December 31, 1993, 1992 and 1991; Notes to Consolidated Financial
Statements.
2. Financial Statement Schedules:
Financial Statement Schedules are listed in the Index to Financial
Statement Schedules (Certain schedules have been omitted because the
required information is contained in the notes to financial statements
or because such schedules are not required or are not applicable.)...... S-1
Independent Auditors' Report............................................. S-2
3. Exhibits:
Exhibits for AEGCo, AEP, APCo, CSPCo, I&M, KEPCo and OPCo are listed in
the Exhibit Index and are incorporated herein by reference.............. E-1
(b) No Reports on Form 8-K were filed during the quarter ended December 31,
1993.
58
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, 1994
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 and March 23, 1994
- ------------------------------------- Director
(G. P. MALONEY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ P. J. DeMaria Vice President, March 23, 1994
- ------------------------------------- Treasurer and
(P. J. DEMARIA) Director
(IV) A MAJORITY OF THE DIRECTORS:
*A. Joseph Dowd
*Henry Fayne
*John R. Jones, III
*Wm. J. Lhota
*James J. Markowsky
/s/ G. P. Maloney
*By:
---------------------------------- March 23, 1994
(G. P. MALONEY, ATTORNEY-IN-FACT)
59
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, 1994
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 and March 23, 1994
- ------------------------------------- Director
(G. P. MALONEY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ P. J. DeMaria Treasurer and March 23, 1994
- ------------------------------------- Director
(P. J. DEMARIA)
(IV) A MAJORITY OF THE DIRECTORS:
*A. Joseph Dowd
*Robert M. Duncan
*Arthur G. Hansen
*Lester A. Hudson, Jr.
*Angus E. Peyton
*Toy F. Reid
*W. Ann Reynolds
*Linda Gillespie Stuntz
*Morris Tanenbaum
*Ann Haymond Zwinger
*By: /s/ G. P. Maloney
---------------------------------- March 23, 1994
(G. P. MALONEY, ATTORNEY-IN-FACT)
60
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, 1994
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 and March 23, 1994
- ------------------------------------- Director
(G. P. MALONEY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ P. J. DeMaria Vice President, March 23, 1994
- ------------------------------------- Treasurer and
(P. J. DEMARIA) Director
(IV) A MAJORITY OF THE DIRECTORS:
*A. Joseph Dowd
*Luke M. Feck
*Wm. J. Lhota
*James J. Markowsky
*J. H. Vipperman
*By: /s/ G. P. Maloney
---------------------------------- March 23, 1994
(G. P. MALONEY, ATTORNEY-IN-FACT)
61
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, 1994
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 and March 23, 1994
- ------------------------------------- Director
(G. P. MALONEY)
(III) PRINCIPAL ACCOUNTING OFFICER:
Vice President, March 23, 1994
/s/ P. J. DeMaria Treasurer and
- ------------------------------------- Director
(P. J. DEMARIA)
(IV) A MAJORITY OF THE DIRECTORS:
*A. Joseph Dowd
*C. A. Erikson
*Henry Fayne
*Wm. J. Lhota
*James J. Markowsky
*By: /s/ G. P. Maloney
---------------------------------- March 23, 1994
(G. P. MALONEY, ATTORNEY-IN-FACT)
62
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, 1994
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 and March 23, 1994
- ------------------------------------- Director
(G. P. MALONEY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ P. J. DeMaria Vice President, March 23, 1994
- ------------------------------------- Treasurer and
(P. J. DEMARIA) Director
(IV) A MAJORITY OF THE DIRECTORS:
*Mark A. Bailey
*W. N. D'Onofrio
*A. Joseph Dowd
*Wm. J. Lhota
*Richard C. Menge
*R. E. Prater
*D. B. Synowiec
*W. E. Walters
*By: /s/ G. P. Maloney March 23, 1994
----------------------------------
(G. P. MALONEY, ATTORNEY-IN-FACT)
63
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, 1994
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 and March 23, 1994
- ------------------------------------- Director
(G. P. MALONEY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ P. J. DeMaria Vice President, March 23, 1994
- ------------------------------------- Treasurer and
(P. J. DEMARIA) Director
(IV) A MAJORITY OF THE DIRECTORS:
*C. R. Boyle, III
*A. Joseph Dowd
*Wm. J. Lhota
*Ronald A. Petti
*By: /s/ G. P. Maloney
--------------------------------- March 23, 1994
(G. P. MALONEY, ATTORNEY-IN-FACT)
64
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, 1994
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.
SIGNATURES 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 and March 23, 1994
- ------------------------------------- Director
(G. P. MALONEY)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ P. J. DeMaria Vice President, March 23, 1994
- ------------------------------------- Treasurer and
(P. J. DEMARIA) Director
(IV) A MAJORITY OF THE DIRECTORS:
*A. Joseph Dowd
*C. A. Erikson
*Henry Fayne
*Wm. J. Lhota
*James J. Markowsky
*By: /s/ G. P. Maloney March 23, 1994
----------------------------------
(G. P. MALONEY, ATTORNEY-IN-FACT)
65
INDEX TO FINANCIAL STATEMENT SCHEDULES
PAGE
----
INDEPENDENT AUDITORS' REPORT.............................................. S-2
The following financial statement schedules for the years ended December
31, 1993, 1992 and
1991 are included in this report on the pages indicated.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule V -- Property, Plant and Equipment........................ S-3
Schedule VI -- Accumulated Depreciation and Amortization
of Property, Plant and Equipment..................... S-4
Schedule VIII -- Valuation and Qualifying Accounts and Reserves....... S-5
Schedule IX -- Short-term Borrowings................................ S-6
AEP GENERATING COMPANY
Schedule V -- Property, Plant and Equipment........................ S-7
Schedule VI -- Accumulated Depreciation
of Property, Plant and Equipment..................... S-8
Schedule IX -- Short-term Borrowings................................ S-9
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Schedule V -- Property, Plant and Equipment........................ S-10
Schedule VI -- Accumulated Depreciation and Amortization
of Property, Plant and Equipment..................... S-11
Schedule VIII -- Valuation and Qualifying Accounts and Reserves....... S-12
Schedule IX -- Short-term Borrowings................................ S-13
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Schedule V -- Property, Plant and Equipment........................ S-14
Schedule VI -- Accumulated Depreciation
of Property, Plant and Equipment..................... S-15
Schedule VIII -- Valuation and Qualifying Accounts and Reserves....... S-16
Schedule IX -- Short-term Borrowings................................ S-17
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Schedule V -- Property, Plant and Equipment........................ S-18
Schedule VI -- Accumulated Depreciation and Amortization
of Property, Plant and Equipment..................... S-19
Schedule VIII -- Valuation and Qualifying Accounts and Reserves....... S-20
Schedule IX -- Short-term Borrowings................................ S-21
KENTUCKY POWER COMPANY
Schedule V -- Property, Plant and Equipment........................ S-22
Schedule VI -- Accumulated Depreciation and Amortization
of Property, Plant and Equipment..................... S-23
Schedule VIII -- Valuation and Qualifying Accounts and Reserves....... S-24
Schedule IX -- Short-term Borrowings................................ S-25
OHIO POWER COMPANY AND SUBSIDIARIES
Schedule V -- Property, Plant and Equipment........................ S-26
Schedule VI -- Accumulated Depreciation and Amortization
of Property, Plant and Equipment..................... S-27
Schedule VIII -- Valuation and Qualifying Accounts and Reserves....... S-28
Schedule IX -- Short-term Borrowings................................ S-29
S-1
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, 1993
and 1992, and for each of the three years in the period ended December 31,
1993, and have issued our reports thereon dated February 22, 1994; such
financial statements and reports are included in your respective 1993 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.
Deloitte & Touche
Columbus, Ohio
February 22, 1994
S-2
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE V --
PROPERTY, PLANT AND EQUIPMENT
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN F COLUMN F COLUMN F COLUMN F
- --------------------------------------------------------------------------------
1993 1992 1991 1990
----------- ----------- ----------- -----------
BALANCE AT BALANCE AT BALANCE AT BALANCE AT
END OF END OF END OF END OF
CLASSIFICATION PERIOD PERIOD PERIOD PERIOD
- --------------------------------------------------------------------------------
(IN THOUSANDS)
ELECTRIC UTILITY PLANT:
Production:
Steam -- Fossil-fired....... $ 7,595,258 $ 7,663,103 $ 7,562,339 $ 6,598,477
Steam -- Nuclear............ 1,483,872 1,454,541 1,442,892 1,401,648
Transmission................. 3,169,347 3,108,787 3,001,159 2,898,426
Distribution................. 3,743,047 3,549,332 3,362,168 3,196,734
General (including mining as-
sets and nuclear fuel)...... 1,406,159 1,443,436 1,485,322 1,429,040
Construction Work in Pro-
gress....................... 314,489 290,547 294,258 1,128,399
----------- ----------- ----------- -----------
Total Electric Utility
Plant...................... 17,712,172 17,509,746 17,148,138 16,652,724
NONUTILITY PROPERTY AND OTHER
PROPERTY INVESTMENTS.......... 399,182 392,348 357,543 361,593
----------- ----------- ----------- -----------
Total....................... $18,111,354 $17,902,094 $17,505,681 $17,014,317
=========== =========== =========== ===========
Total additions of $676,404,000 in 1993, $718,154,000 in 1992 and
$733,909,000 in 1991 were less than 10% of the total as of the respective year-
ends. Retirements or sales of $278,435,000 in 1993, $297,460,000 in 1992 and
$198,352,000 in 1991 were less than 10% of the total as of the respective year-
ends. There were no additions to individual accounts in excess of two percent
of total assets other than transfers from Construction Work in Progress.
Amortization of nuclear fuel of $41,325,000 in 1993, $19,343,000 in 1992 and
$50,124,000 in 1991 was credited directly to the property account and charged
to fuel expense. In 1993 other charges include a reduction of $157,535,000 to
reflect the PUCO disallowance of a portion of the Zimmer Plant investment as
discussed in Note 3 of the Notes to Consolidated Financial Statements.
The methods used to compute the annual provisions for depreciation are
described in Note 1 of the Notes to Consolidated Financial Statements. The
current provisions were determined using the following composite rates for
functional classes of property:
FUNCTIONAL CLASS OF PROPERTY COMPOSITE ANNUAL RATE
- --------------------------------------------------------------------------------
Production:
Steam -- Fossil-fired................................. 3.2% to 4.6%
Steam -- Nuclear...................................... 3.4%
Transmission........................................... 1.7% to 2.7%
Distribution........................................... 3.4% to 4.2%
General................................................ 1.7% to 3.8%
S-3
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE VI --
ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- --------------------------------------------------------------------------------
ADDITIONS OTHER
BALANCE AT CHARGED TO CHANGES -- BALANCE AT
BEGINNING COSTS AND RETIREMENTS ADD END OF
DESCRIPTION OF PERIOD EXPENSES OR SALES (DEDUCT) PERIOD
- --------------------------------------------------------------------------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993
ACCUMULATED DEPRECIA-
TION AND
AMORTIZATION OF
ELECTRIC UTILITY
PLANT:
Production:
Steam -- Fossil-
fired.................. $3,031,186 $266,379 $102,831 $(10,299) $3,184,435
Steam -- Nuclear.. 691,605 57,274 26,196 1 722,684
Transmission........ 988,745 61,924 14,346 2,128 1,038,451
Distribution........ 1,060,477 131,114 72,527 1,693 1,120,757
General............. 509,247 72,205 56,792 21,144 545,804
---------- -------- -------- -------- ----------
Total........... $6,281,260 $588,896 $272,692 $ 14,667 $6,612,131
========== ======== ======== ======== ==========
ACCUMULATED DEPRECIA-
TION AND
AMORTIZATION OF NON-
UTILITY PROPERTY AND
OTHER PROPERTY IN-
VESTMENTS........... $ 112,089 $ 10,924 $ 12,196 $ 8,283 $ 119,100
========== ======== ======== ======== ==========
YEAR ENDED DECEMBER 31,
1992:
ACCUMULATED DEPRECIA-
TION AND
AMORTIZATION OF
ELECTRIC UTILITY
PLANT:
Production:
Steam -- Fossil-
fired.................. $2,852,539 $260,053 $ 83,573 $ 2,167 $3,031,186
Steam -- Nuclear.. 638,563 54,842 1,800 691,605
Transmission........ 940,326 60,390 11,705 (266) 988,745
Distribution........ 1,010,778 126,184 77,317 832 1,060,477
General............. 509,978 76,441 95,332 18,160 509,247
---------- -------- -------- -------- ----------
Total........... $5,952,184 $577,910 $269,727 $ 20,893 $6,281,260
========== ======== ======== ======== ==========
ACCUMULATED DEPRECIA-
TION AND
AMORTIZATION OF NON-
UTILITY PROPERTY AND
OTHER PROPERTY IN-
VESTMENTS........... $ 100,293 $ 10,064 $ (178) $ 1,554 $ 112,089
========== ======== ======== ======== ==========
YEAR ENDED DECEMBER 31,
1991:
ACCUMULATED DEPRECIA-
TION AND
AMORTIZATION OF
ELECTRIC UTILITY
PLANT:
Production:
Steam -- Fossil-
fired.................. $2,659,971 $249,507 $ 57,998 $ 1,059 $2,852,539
Steam -- Nuclear.. 589,526 55,140 6,033 (70) 638,563
Transmission........ 904,357 59,073 22,706 (398) 940,326
Distribution........ 953,193 120,499 64,364 1,450 1,010,778
General............. 481,296 78,059 62,429 13,052 509,978
---------- -------- -------- -------- ----------
Total........... $5,588,343 $562,278 $213,530 $ 15,093 $5,952,184
========== ======== ======== ======== ==========
ACCUMULATED DEPRECIA-
TION AND
AMORTIZATION OF NON-
UTILITY PROPERTY AND
OTHER PROPERTY IN-
VESTMENTS........... $ 95,070 $ 11,232 $ 7,282 $ 1,273 $ 100,293
========== ======== ======== ======== ==========
S-4
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE VIII --
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -----------------------------------------------------------------------------------------
ADDITIONS
-----------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- -----------------------------------------------------------------------------------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
DEDUCTED FROM ASSETS:
Accumulated Provision
for
Uncollectible Ac-
counts............ $ 7,287 $ 14,237 $ 4,163(a) $21,639(b) $ 4,048
======== ======== ======= ======= ========
NOT SHOWN ELSEWHERE:
Operating Reserves:
Maintenance........ $ 8,123 $(1,036) $ 184(c) $ 3,918(d) $ 3,353
Nuclear Plant
Decommissioning
Costs.......... 146,451 23,255(e) -0- -0- 169,706
Uranium Enrichment
Decontamination
and
Decommissioning
Fund Assess-
ment........... 45,500 -0- -0- 10,517(d) 34,983
Workers' Compensa-
tion and Other. 60,348 24,762 2,521 29,591(d,f) 58,040
-------- -------- ------- ------- --------
Total............ $260,422 $ 46,981 $ 2,705 $44,026 $266,082
======== ======== ======= ======= ========
YEAR ENDED DECEMBER 31,
1992:
DEDUCTED FROM ASSETS:
Accumulated Provision
for
Uncollectible Ac-
counts............ $ 9,599 $ 12,888 $ 4,096(a) $19,296(b) $ 7,287
======== ======== ======= ======= ========
NOT SHOWN ELSEWHERE:
Operating Reserves:
Maintenance........ $ 12,874 $ (878) $ 385(c) $ 4,258(d) $ 8,123
Nuclear Plant
Decommissioning
Costs.......... 125,716 20,735(e) -0- -0- 146,451
Uranium Enrichment
Decontamination
and
Decommissioning
Fund Assess-
ment........... -0- -0- 45,500 -0- 45,500
Workers' Compensa-
tion and Other. 52,987 29,012 12,956 34,607(d) 60,348
-------- -------- ------- ------- --------
Total............ $191,577 $48,869 $58,841 $38,865 $260,422
======== ======== ======= ======= ========
YEAR ENDED DECEMBER 31,
1991:
DEDUCTED FROM ASSETS:
Accumulated Provision
for
Uncollectible Ac-
counts............ $ 11,827 $12,517 $ 3,625(a) $18,370(b) $ 9,599
======== ======== ======= ======= ========
NOT SHOWN ELSEWHERE:
Operating Reserves:
Maintenance........ $ 20,831 $ (1,531) $ 221(c) $ 6,647(d) $ 12,874
Nuclear Plant
Decommissioning
Costs.......... 106,632 19,084(e) -0- -0- 125,716
Workers' Compensa-
tion and Other. 47,142 29,449 2,987 26,591(d) 52,987
-------- -------- ------- ------- --------
Total............ $174,605 $47,002 $ 3,208 $33,238 $191,577
======== ======== ======= ======= ========
- --------
(a)Recoveries on accounts previously written off.
(b)Uncollectible accounts written off.
(c)Billings to others.
(d)Payments and accrual adjustments.
(e)Includes interest on trust funds.
(f)Adjust royalty provision.
S-5
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE IX --
SHORT-TERM BORROWINGS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- ----------------------------------------------------------------------------------
MAXIMUM AVERAGE WEIGHTED
CATEGORY OF WEIGHTED AMOUNT AMOUNT AVERAGE
AGGREGATE BALANCE AT AVERAGE OUTSTANDING OUTSTANDING INTEREST RATE
SHORT-TERM END OF INTEREST DURING THE DURING THE DURING THE
BORROWINGS PERIOD RATE PERIOD PERIOD (A) PERIOD (B)
- ----------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
Notes Payable......... $ 65,526 3.5% $ 70,425 $ 47,282 3.3%
Commercial Paper...... 213,450 3.7 256,950 141,829 3.3
YEAR ENDED DECEMBER 31,
1992:
Notes Payable......... $ 79,150 4.0% $115,875 $ 72,889 3.9%
Commercial Paper...... 174,004 4.1 314,355 167,328 4.2
YEAR ENDED DECEMBER 31,
1991:
Notes Payable......... $ 76,783 5.3% $149,970 $ 82,886 6.3%
Commercial Paper...... 335,600 5.4 335,600 170,528 6.3
- --------
(a)Sum of month-end short-term borrowings divided by number of months
outstanding.
(b)Interest for the period divided by average amount outstanding.
S-6
AEP GENERATING COMPANY SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN F COLUMN F COLUMN F COLUMN F
- -------------------------------------------------------------------------------
1993 1992 1991 1990
---------- ---------- ---------- ----------
BALANCE AT BALANCE AT BALANCE AT BALANCE AT
END OF END OF END OF END OF
CLASSIFICATION PERIOD PERIOD PERIOD PERIOD
- -------------------------------------------------------------------------------
(IN THOUSANDS)
ELECTRIC UTILITY PLANT:
Production -- Steam -- Fossil-
fired............................. $627,502 $622,274 $619,728 $616,469
General.......................... 1,757 1,774 1,809 1,830
Construction Work in Progress.... 1,773 3,933 3,762 4,654
-------- -------- -------- --------
Total.......................... $631,032 $627,981 $625,299 $622,953
======== ======== ======== ========
Total additions of $4,089,000 in 1993, $4,512,000 in 1992 and $3,796,000 in
1991 were less than 10% of the total as of the respective year-ends.
Retirements or sales of $1,038,000 in 1993, $1,830,000 in 1992 and $1,450,000
in 1991 were less than 10% of the total as of the respective year-ends. There
were no additions to individual accounts in excess of two percent of total
assets.
The methods used to compute the annual provisions for depreciation are
described in Note 1 of the Notes to Financial Statements. The current
provisions were determined using the following composite rates for functional
classes of property:
FUNCTIONAL CLASS OF PROPERTY COMPOSITE ANNUAL RATE
- --------------------------------------------------------------------------------
Production -- Steam-- Fossil-fired.................. 3.5%
General............................................. 3.8%
S-7
AEP GENERATING COMPANY SCHEDULE VI -- ACCUMULATED DEPRECIATION OF PROPERTY,
PLANT AND EQUIPMENT
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- --------------------------------------------------------------------------------
ADDITIONS OTHER
BALANCE AT CHARGED TO CHANGES -- BALANCE AT
BEGINNING COSTS AND RETIREMENTS ADD END OF
DESCRIPTION OF PERIOD EXPENSES OR SALES (DEDUCT) PERIOD
- --------------------------------------------------------------------------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
ACCUMULATED DEPRECIA-
TION
OF ELECTRIC UTILITY
PLANT:
Production --
Steam-- Fossil-
fired........... $160,443 $21,899 $ 980 $-0- $181,362
General............. 215 40 30 225
-------- ------- ------ ---- --------
Total............. $160,658 $21,939 $1,010 $-0- $181,587
======== ======= ====== ==== ========
YEAR ENDED DECEMBER 31,
1992:
ACCUMULATED DEPRECIA-
TION
OF ELECTRIC UTILITY
PLANT:
Production --
Steam-- Fossil-
fired........... $140,465 $21,679 $1,701 $-0- $160,443
General............. 201 45 31 215
-------- ------- ------ ---- --------
Total............. $140,666 $21,724 $1,732 $-0- $160,658
======== ======= ====== ==== ========
YEAR ENDED DECEMBER 31,
1991:
ACCUMULATED DEPRECIA-
TION
OF ELECTRIC UTILITY
PLANT:
Production --
Steam-- Fossil-
fired........... $120,447 $21,506 $1,491 $ 3 $140,465
General............. 156 59 11 (3) 201
-------- ------- ------ ---- --------
Total............. $120,603 $21,565 $1,502 $-0- $140,666
======== ======= ====== ==== ========
S-8
AEP GENERATING COMPANY SCHEDULE IX -- SHORT-TERM BORROWINGS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- ----------------------------------------------------------------------------------
MAXIMUM AVERAGE WEIGHTED
CATEGORY OF WEIGHTED AMOUNT AMOUNT AVERAGE
AGGREGATE BALANCE AT AVERAGE OUTSTANDING OUTSTANDING INTEREST RATE
SHORT-TERM END OF INTEREST DURING THE DURING THE DURING THE
BORROWINGS PERIOD RATE PERIOD PERIOD (A) PERIOD (B)
- ----------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
Notes Payable......... $15,250 3.5% $15,250 $15,250 3.4%
YEAR ENDED DECEMBER 31,
1992:
Notes Payable......... $ -0- --% $ -0- $ -0- --%
YEAR ENDED DECEMBER 31,
1991:
Notes Payable......... $ -0- --% $ -0- $ -0- --%
- --------
(a)Sum of month-end short-term borrowings divided by number of months
outstanding.
(b)Interest for the period divided by average amount outstanding.
S-9
APPALACHIAN POWER COMPANY AND SUBSIDIARIES SCHEDULE V -- PROPERTY, PLANT AND
EQUIPMENT
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN F COLUMN F COLUMN F COLUMN F
- --------------------------------------------------------------------------------
1993 1992 1991 1990
---------- ---------- ---------- ----------
BALANCE AT BALANCE AT BALANCE AT BALANCE AT
END OF END OF END OF END OF
CLASSIFICATION PERIOD PERIOD PERIOD PERIOD
- --------------------------------------------------------------------------------
(IN THOUSANDS)
ELECTRIC UTILITY PLANT:
Production:
Steam -- Fossil-fired.......... $1,631,038 $1,605,660 $1,589,041 $1,550,486
Hydro.......................... 149,967 146,048 144,971 143,482
Transmission..................... 987,147 956,169 893,110 857,490
Distribution..................... 1,225,436 1,153,799 1,086,706 1,021,681
General.......................... 140,942 131,654 112,648 93,342
Construction Work in Progress.... 59,170 45,405 58,357 54,034
---------- ---------- ---------- ----------
Total Electric Utility Plant... 4,193,700 4,038,735 3,884,833 3,720,515
NONUTILITY PROPERTY AND OTHER PROP-
ERTY INVESTMENTS.................. 86,275 87,908 87,059 85,791
---------- ---------- ---------- ----------
Total.......................... $4,279,975 $4,126,643 $3,971,892 $3,806,306
========== ========== ========== ==========
Total additions of $201,169,000 in 1993, $198,116,000 in 1992 and
$196,937,000 in 1991 were less than 10% of the total as of the respective year-
ends. Retirements or sales of $47,254,000 in 1993, $42,926,000 in 1992 and
$32,428,000 in 1991 were less than 10% of the total as of the respective year-
ends. There were no additions to individual accounts in excess of two percent
of total assets other than transfers from Construction Work in Progress.
The methods used to compute the annual provisions for depreciation are
described in Note 1 of the Notes to Consolidated Financial Statements. The
current provisions were determined using the following composite rates for
functional classes of property:
FUNCTIONAL CLASS OF PROPERTY COMPOSITE ANNUAL RATE
- --------------------------------------------------------------------------------
Production:
Steam -- Fossil-fired............................... 3.6%
Hydro............................................... 2.5%
Transmission........................................... 2.2%
Distribution........................................... 3.5%
General................................................ 3.3%
S-10
APPALACHIAN POWER COMPANY AND SUBSIDIARIES SCHEDULE VI -- ACCUMULATED
DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- --------------------------------------------------------------------------------
ADDITIONS OTHER
BALANCE AT CHARGED TO CHANGES -- BALANCE AT
BEGINNING COSTS AND RETIREMENTS ADD END OF
DESCRIPTION OF PERIOD EXPENSES OR SALES (DEDUCT) PERIOD
- --------------------------------------------------------------------------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
ACCUMULATED DEPRECIA-
TION AND
AMORTIZATION OF
ELECTRIC UTILITY
PLANT:
Production:
Steam -- Fossil-
fired.................. $ 770,638 $ 57,009 $17,212 $1,081 $ 811,516
Hydro............. 68,895 3,356 376 (2) 71,873
Transmission........ 255,010 20,202 5,459 116 269,869
Distribution........ 341,780 40,966 27,966 (129) 354,651
General............. 40,755 7,346 5,774 619 42,946
---------- -------- ------- ------ ----------
Total............. $1,477,078 $128,879 $56,787 $1,685 $1,550,855
========== ======== ======= ====== ==========
ACCUMULATED
DEPRECIATION AND
AMORTIZATION
OF NONUTILITY
PROPERTY AND OTHER
PROPERTY
INVESTMENTS......... $ 35,874 $ 1,844 $ 512 $ 664 $ 37,870
========== ======== ======= ====== ==========
YEAR ENDED DECEMBER 31,
1992:
ACCUMULATED DEPRECIA-
TION AND
AMORTIZATION OF
ELECTRIC UTILITY
PLANT:
Production:
Steam -- Fossil-
fired.................. $ 727,961 $ 53,934 $12,262 $1,005 $ 770,638
Hydro............. 66,603 2,717 425 68,895
Transmission........ 241,793 19,141 5,912 (12) 255,010
Distribution........ 330,855 40,110 29,196 11 341,780
General............. 37,862 6,676 4,028 245 40,755
---------- -------- ------- ------ ----------
Total............. $1,405,074 $122,578 $51,823 $1,249 $1,477,078
========== ======== ======= ====== ==========
ACCUMULATED DEPRECIA-
TION AND AMORTIZA-
TION
OF NONUTILITY PROP-
ERTY AND
OTHER PROPERTY IN-
VESTMENTS........... $ 32,865 $ 1,858 $ 4 $1,155 $ 35,874
========== ======== ======= ====== ==========
YEAR ENDED DECEMBER 31,
1991:
ACCUMULATED DEPRECIA-
TION AND
AMORTIZATION OF
ELECTRIC UTILITY
PLANT:
Production:
Steam -- Fossil-
fired.................. $ 684,633 $ 52,686 $10,339 $ 981 $ 727,961
Hydro............. 64,154 2,701 253 1 66,603
Transmission........ 229,699 18,113 5,426 (593) 241,793
Distribution........ 312,964 37,621 20,328 598 330,855
General............. 36,859 5,448 4,891 446 37,862
---------- -------- ------- ------ ----------
Total............. $1,328,309 $116,569 $41,237 $1,433 $1,405,074
========== ======== ======= ====== ==========
ACCUMULATED DEPRECIA-
TION AND AMORTIZA-
TION
OF NONUTILITY PROP-
ERTY AND
OTHER PROPERTY IN-
VESTMENTS........... $ 30,214 $ 1,868 $ 155 $ 938 $ 32,865
========== ======== ======= ====== ==========
S-11
APPALACHIAN POWER COMPANY AND SUBSIDIARIES SCHEDULE VIII -- VALUATION AND
QUALIFYING ACCOUNTS AND RESERVES
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ----------------------------------------------------------------------------------
ADDITIONS
---------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- ----------------------------------------------------------------------------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
DEDUCTED FROM ASSETS:
Accumulated Provi-
sion for
Uncollectible Ac-
counts........... $ 724 $3,392 $627(a) $3,399(b) $ 1,344
======= ====== ==== ====== =======
NOT SHOWN ELSEWHERE:
Operating Reserves
for
Workers' Compen-
sation and Other. $ 9,159 $6,021 $738 $3,940(c) $11,978
======= ====== ==== ====== =======
YEAR ENDED DECEMBER 31,
1992:
DEDUCTED FROM ASSETS:
Accumulated Provi-
sion for
Uncollectible Ac-
counts........... $ 987 $1,810 $672(a) $2,745(b) $ 724
======= ====== ==== ====== =======
NOT SHOWN ELSEWHERE:
Operating Reserves
for
Workers' Compensa-
tion and Oth-
er........... $ 9,033 $3,486 $518 $3,878(c) $ 9,159
======= ====== ==== ====== =======
YEAR ENDED DECEMBER 31,
1991:
DEDUCTED FROM ASSETS:
Accumulated Provi-
sion for
Uncollectible Ac-
counts........... $ 989 $2,036 $527(a) $2,565(b) $ 987
======= ====== ==== ====== =======
NOT SHOWN ELSEWHERE:
Operating Reserves
for
Workers' Compensa-
tion and Oth-
er........... $10,822 $3,397 $490 $5,676(c) $ 9,033
======= ====== ==== ====== =======
- --------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
(c) Payments and transfers.
S-12
APPALACHIAN POWER COMPANY AND SUBSIDIARIES SCHEDULE IX -- SHORT-TERM BORROWINGS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- -----------------------------------------------------------------------------------
MAXIMUM AVERAGE WEIGHTED
CATEGORY OF WEIGHTED AMOUNT AMOUNT AVERAGE
AGGREGATE BALANCE AT AVERAGE OUTSTANDING OUTSTANDING INTEREST RATE
SHORT-TERM END OF INTEREST DURING THE DURING THE DURING THE
BORROWINGS PERIOD RATE PERIOD PERIOD (A) PERIOD (B)
- -----------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
Notes Payable......... $ 3,400 3.6% $19,000 $ 5,021 3.3%
Commercial Paper...... 36,100 3.4 78,050 49,548 3.2
YEAR ENDED DECEMBER 31,
1992:
Notes Payable......... $ 4,300 4.0% $ 5,050 $ 4,692 4.1%
Commercial Paper...... 75,550 3.9 80,500 46,665 4.5
YEAR ENDED DECEMBER 31,
1991:
Notes Payable......... $ 5,150 5.1% $17,950 $ 7,523 6.3%
Commercial Paper...... 93,900 5.2 93,900 36,584 6.7
- --------
(a) Sum of month-end short-term borrowings divided by number of months
outstanding.
(b) Interest for the period divided by average amount outstanding.
S-13
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES SCHEDULE V -- PROPERTY, PLANT
AND EQUIPMENT
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN F COLUMN F COLUMN F COLUMN F
- --------------------------------------------------------------------------------
1993 1992 1991 1990
---------- ---------- ---------- ----------
BALANCE AT BALANCE AT BALANCE AT BALANCE AT
END OF END OF END OF END OF
CLASSIFICATION PERIOD PERIOD PERIOD PERIOD
- --------------------------------------------------------------------------------
(IN THOUSANDS)
ELECTRIC UTILITY PLANT:
Production -- Steam -- Fossil-
fired.............................. $1,443,506 $1,586,554 $1,581,389 $ 712,451
Transmission..................... 295,539 292,125 282,610 267,777
Distribution..................... 755,342 719,781 685,486 652,894
General.......................... 97,874 94,599 93,262 89,617
Construction Work in Progress.... 52,794 31,447 24,512 852,760
---------- ---------- ---------- ----------
Total Electric Utility Plant... 2,645,055 2,724,506 2,667,259 2,575,499
NONUTILITY PROPERTY AND OTHER PROP-
ERTY INVESTMENTS.................. 20,465 19,253 18,219 17,900
---------- ---------- ---------- ----------
Total.......................... $2,665,520 $2,743,759 $2,685,478 $2,593,399
========== ========== ========== ==========
Total additions of $97,455,000 in 1993, $80,279,000 in 1992 and $111,856,000
in 1991 were less than 10% of the total as of the respective year-ends.
Retirements or sales of $18,161,000 in 1993, $21,999,000 in 1992 and
$19,773,000 in 1991 were less than 10% of the total as of the respective year-
ends. There were no additions to individual accounts in excess of two percent
of total assets other than transfers from Construction Work in Progress. In
1993 other charges include a reduction of $157,535,000 to reflect the PUCO
disallowance of a portion of the Zimmer Plant investment as discussed in Note 2
of the Notes to Consolidated Financial Statements.
The methods used to compute the annual provisions for depreciation are
described in Note 1 of the Notes to Consolidated Financial Statements. The
current provisions were determined using the following composite rates for
functional classes of property:
FUNCTIONAL CLASS OF PROPERTY COMPOSITE ANNUAL RATE
- --------------------------------------------------------------------------------
Production -- Steam -- Fossil-fired..................... 3.2%
Transmission............................................ 2.3%
Distribution............................................ 3.7%
General................................................. 3.5%
S-14
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES SCHEDULE VI -- ACCUMULATED
DEPRECIATION OF PROPERTY, PLANT AND EQUIPMENT
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- -----------------------------------------------------------------------------------
ADDITIONS OTHER
BALANCE AT CHARGED TO CHANGES -- BALANCE AT
BEGINNING COSTS AND RETIREMENTS ADD END OF
DESCRIPTION OF PERIOD EXPENSES OR SALES (DEDUCT) PERIOD
- -----------------------------------------------------------------------------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
ACCUMULATED DEPRECIA-
TION
OF ELECTRIC UTILITY
PLANT:
Production --
Steam -- Fossil-fired... $336,754 $48,779 $ 6,847 $(10,213)(a) $368,473
Transmission........ 117,462 6,351 586 123,227
Distribution........ 272,536 27,043 8,392 (4) 291,183
General............. 27,615 5,398 4,083 4 28,934
-------- ------- ------- -------- --------
Total............. $754,367 $87,571 $19,908 $(10,213) $811,817
======== ======= ======= ======== ========
ACCUMULATED DEPRECIA-
TION
OF NONUTILITY PROP-
ERTY AND
OTHER PROPERTY IN-
VESTMENTS........... $ 932 $ 120 $ 221 $ -0- $ 831
======== ======= ======= ======== ========
YEAR ENDED DECEMBER 31,
1992:
ACCUMULATED DEPRECIA-
TION
OF ELECTRIC UTILITY
PLANT:
Production --
Steam -- Fossil-fired... $298,466 $50,423 $12,135 $336,754
Transmission........ 112,456 6,493 1,061 $ (426) 117,462
Distribution........ 254,597 26,250 8,737 426 272,536
General............. 27,566 4,602 4,508 (45) 27,615
-------- ------- ------- -------- --------
Total............. $693,085 $87,768 $26,441 $ (45) $754,367
======== ======= ======= ======== ========
ACCUMULATED DEPRECIA-
TION
OF NONUTILITY PROP-
ERTY AND
OTHER PROPERTY IN-
VESTMENTS........... $ 777 $ 160 $ 50 $ 45 $ 932
======== ======= ======= ======== ========
YEAR ENDED DECEMBER 31,
1991:
ACCUMULATED DEPRECIA-
TION
OF ELECTRIC UTILITY
PLANT:
Production --
Steam -- Fossil-fired... $265,452 $43,051 $10,037 $298,466
Transmission........ 106,471 6,760 753 $ (22) 112,456
Distribution........ 236,574 25,759 7,758 22 254,597
General............. 30,644 4,348 7,395 (31) 27,566
-------- ------- ------- -------- --------
Total............. $639,141 $79,918 $25,943 $ (31) $693,085
======== ======= ======= ======== ========
ACCUMULATED DEPRECIA-
TION
OF NONUTILITY PROP-
ERTY AND
OTHER PROPERTY IN-
VESTMENTS........... $ 877 $ 142 $ 287 $ 45 $ 777
======== ======= ======= ======== ========
- --------
(a) Reflects the write-off of accumulated depreciation related to a portion
of the Zimmer Plant investment that was disallowed by the PUCO as discussed in
Note 2 of the Notes to Consolidated Financial Statements.
S-15
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES SCHEDULE VIII -- VALUATION AND
QUALIFYING ACCOUNTS AND RESERVES
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ----------------------------------------------------------------------------------
ADDITIONS
---------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- ----------------------------------------------------------------------------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
DEDUCTED FROM ASSETS:
Accumulated Provi-
sion for
Uncollectible
Accounts........ $1,332 $4,167 $2,106(a) $6,614(b) $ 991
====== ====== ====== ====== ======
NOT SHOWN ELSEWHERE:
Operating Reserves
for
Workers' Compen-
sation and Oth-
er.............. $3,226 $2,026 $ 207 $ 432 $5,027
====== ====== ====== ====== ======
YEAR ENDED DECEMBER 31,
1992:
DEDUCTED FROM ASSETS:
Accumulated Provi-
sion for
Uncollectible
Accounts........ $1,134 $4,593 $1,981(a) $6,376(b) $1,332
====== ====== ====== ====== ======
NOT SHOWN ELSEWHERE:
Operating Reserves
for
Workers' Compen-
sation and Oth-
er.............. $3,779 $ (63) $ 123 $ 613(c) $3,226
====== ====== ====== ====== ======
YEAR ENDED DECEMBER 31,
1991:
DEDUCTED FROM ASSETS:
Accumulated Provi-
sion for
Uncollectible
Accounts........ $1,272 $4,407 $1,753(a) $6,298(b) $1,134
====== ====== ====== ====== ======
NOT SHOWN ELSEWHERE:
Operating Reserves
for
Workers' Compen-
sation and Oth-
er.............. $1,620 $2,704 $ 59 $ 604(c) $3,779
====== ====== ====== ====== ======
- --------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
(c) Payments.
S-16
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES SCHEDULE IX -- SHORT-TERM
BORROWINGS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- -----------------------------------------------------------------------------------
MAXIMUM AVERAGE WEIGHTED
CATEGORY OF WEIGHTED AMOUNT AMOUNT AVERAGE
AGGREGATE BALANCE AT AVERAGE OUTSTANDING OUTSTANDING INTEREST RATE
SHORT-TERM END OF INTEREST DURING THE DURING THE DURING THE
BORROWINGS PERIOD RATE PERIOD PERIOD (A) PERIOD (B)
- -----------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
Notes Payable......... $12,500 3.6% $37,250 $22,861 3.3%
Commercial Paper...... 12,725 3.8 60,250 21,756 3.3
YEAR ENDED DECEMBER 31,
1992:
Notes Payable......... $34,750 3.9% $71,600 $36,534 3.8%
Commercial Paper...... 19,069 4.2 73,910 45,251 4.1
YEAR ENDED DECEMBER 31,
1991:
Notes Payable......... $15,725 5.2% $52,275 $31,583 6.2%
Commercial Paper...... 50,475 5.6 50,475 26,929 6.3
- --------
(a) Sum of month-end short-term borrowings divided by number of months
outstanding.
(b) Interest for the period divided by average amount outstanding.
S-17
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES SCHEDULE V -- PROPERTY, PLANT
AND EQUIPMENT
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN F COLUMN F COLUMN F COLUMN F
- -------------------------------------------------------------------------------
1993 1992 1991 1990
---------- ---------- ---------- ---------- ---
BALANCE AT BALANCE AT BALANCE AT BALANCE AT
END OF END OF END OF END OF
CLASSIFICATION PERIOD PERIOD PERIOD PERIOD
- -------------------------------------------------------------------------------
(IN THOUSANDS)
ELECTRIC UTILITY PLANT:
Production:
Steam -- Fossil-fired...... $1,118,655 $1,105,364 $1,085,337 $1,074,214
Steam -- Nuclear........... 1,483,872 1,454,541 1,442,892 1,401,648
Transmission................. 839,198 829,507 815,742 786,206
Distribution................. 608,752 576,309 551,055 520,988
General (including nuclear
fuel)......................... 152,470 182,414 157,340 185,781
Construction Work in Pro-
gress......................... 88,010 118,345 83,454 97,390
---------- ---------- ---------- ----------
Total Electric Utility
Plant......................... 4,290,957 4,266,480 4,135,820 4,066,227
NONUTILITY PROPERTY AND OTHER
PROPERTY INVESTMENTS.......... 193,493 191,743 190,518 200,405
---------- ---------- ---------- ----------
Total...................... $4,484,450 $4,458,223 $4,326,338 $4,266,632
========== ========== ========== ==========
Total additions of $125,247,000 in 1993, $175,728,000 in 1992 and
$149,187,000 in 1991 were less than 10% of the total as of the respective year-
ends. Retirements or sales of $61,586,000 in 1993, $25,301,000 in 1992 and
$40,396,000 in 1991 were less than 10% of the total as of the respective year-
ends. There were no additions to individual accounts in excess of two percent
of total assets other than transfers from Construction Work in Progress.
Amortization of nuclear fuel of $41,325,000 in 1993, $19,343,000 in 1992 and
$50,124,000 in 1991 was credited directly to the property account and charged
to fuel expense.
The methods used to compute the annual provisions for depreciation are
described in Note 1 of the Notes to Consolidated Financial Statements. The
current provisions were determined using the following composite rates for
functional classes of property:
FUNCTIONAL CLASS OF PROPERTY COMPOSITE ANNUAL RATE
- --------------------------------------------------------------------------------
Production:
Steam -- Fossil-fired................................. 4.6%
Steam -- Nuclear...................................... 3.4%
Transmission............................................ 1.9%
Distribution............................................ 4.2%
General................................................. 3.8%
S-18
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES SCHEDULE VI -- ACCUMULATED
DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- ---------------------------------------------------------------------------------------------------
ADDITIONS OTHER
BALANCE AT CHARGED TO CHANGES -- BALANCE AT
BEGINNING COSTS AND RETIREMENTS ADD END OF
DESCRIPTION OF PERIOD EXPENSES OR SALES (DEDUCT) PERIOD
- ---------------------------------------------------------------------------------------------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31, 1993:
ACCUMULATED DEPRECIATION AND
AMORTIZATION OF ELECTRIC UTILITY
PLANT:
Production:
Steam -- Fossil-fired.............. $ 447,978 $ 42,417 $14,608 $ 6 $ 475,793
Steam -- Nuclear................... 691,605 57,274 26,196 1 722,684
Transmission......................... 277,512 17,316 1,717 (17) 293,094
Distribution......................... 180,363 21,710 11,179 17 190,911
General.............................. 33,980 5,610 7,228 (15) 32,347
---------- -------- ------- ------ ----------
Total............................ $1,631,438 $144,327 $60,928 $ (8) $1,714,829
========== ======== ======= ====== ==========
ACCUMULATED DEPRECIATION AND
AMORTIZATION
OF NONUTILITY PROPERTY AND OTHER
PROPERTY INVESTMENTS................. $ 62,766 $ 7,992 $ 9,615 $7,616 $ 68,759
========== ======== ======= ====== ==========
YEAR ENDED DECEMBER 31, 1992:
ACCUMULATED DEPRECIATION AND
AMORTIZATION OF ELECTRIC UTILITY
PLANT:
Production:
Steam -- Fossil-fired.............. $ 419,455 $ 40,964 $12,427 $ (14) $ 447,978
Steam -- Nuclear................... 638,563 54,842 1,800 691,605
Transmission......................... 259,890 17,076 (446) 100 277,512
Distribution......................... 171,809 20,349 11,690 (105) 180,363
General.............................. 31,632 5,126 2,795 17 33,980
---------- -------- ------- ------ ----------
Total............................ $1,521,349 $138,357 $28,266 $ (2) $1,631,438
========== ======== ======= ====== ==========
ACCUMULATED DEPRECIATION AND
AMORTIZATION OF NONUTILITY PROPERTY AND
OTHER PROPERTY INVESTMENTS............ $ 55,028 $ 7,296 $ (93) $ 349 $ 62,766
========== ======== ======= ====== ==========
YEAR ENDED DECEMBER 31, 1991:
ACCUMULATED DEPRECIATION AND
AMORTIZATION OF ELECTRIC UTILITY
PLANT:
Production:
Steam -- Fossil-fired.............. $ 386,116 $ 40,567 $ 7,302 $ 74 $ 419,455
Steam -- Nuclear................... 589,526 55,140 6,033 (70) 638,563
Transmission......................... 251,438 16,767 8,369 54 259,890
Distribution......................... 163,965 19,424 11,582 2 171,809
General.............................. 30,240 5,259 3,775 (92) 31,632
---------- -------- ------- ------ ----------
Total............................ $1,421,285 $137,157 $37,061 $ (32) $1,521,349
========== ======== ======= ====== ==========
ACCUMULATED DEPRECIATION AND
AMORTIZATION OF NONUTILITY PROPERTY
AND OTHER PROPERTY INVESTMENTS........ $ 52,730 $ 8,767 $ 6,759 $ 290 $ 55,028
========== ======== ======= ====== ==========
S-19
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES SCHEDULE VIII -- VALUATION AND
QUALIFYING ACCOUNTS AND RESERVES
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ------------------------------------------------------------------------------------------
ADDITIONS
-----------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- ------------------------------------------------------------------------------------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
DEDUCTED FROM ASSETS:
Accumulated Provision
for
Uncollectible Ac-
counts............ $ 562 $ 1,380 $ 624(a) $ 2,062(b) $ 504
======== ======= ======= ======= ========
NOT SHOWN ELSEWHERE:
Operating Reserves:
Maintenance........ $ 2,162 $ 685 $ -0- $ 2,847(d) $ -0-
Nuclear Plant
Decommissioning
Costs........... 146,451 23,255(e) -0- 169,706
Uranium Enrichment
Decontamination
and
Decommissioning
Fund Agreement. 45,500 -0- -0- 10,517(d) 34,983
Workers'
Compensation,
Coal Inventory
Adjustment, and
Other.......... 9,348 1,197 1,619 6,894(d)(f) 5,270
-------- ------- ------- ------- --------
Total............ $203,461 $25,137 $ 1,619 $20,258 $209,959
======== ======= ======= ======= ========
YEAR ENDED DECEMBER 31,
1992:
DEDUCTED FROM ASSETS:
Accumulated Provision
for
Uncollectible Ac-
counts............ $ 629 $ 1,736 $ 650(a) $ 2,453(b) $ 562
======== ======= ======= ======= ========
NOT SHOWN ELSEWHERE:
Operating Reserves:
Maintenance........ $ 4,466 $ 356 $ -0- $ 2,660(d) $ 2,162
Nuclear Plant
Decommissioning
Costs........... 125,716 20,735(e) -0- -0- 146,451
Uranium Enrichment
Decontamination
and
Decommissioning
Fund Agreement. -0- -0- 45,500 -0- 45,500
Workers'
Compensation,
Coal Inventory
Adjustment, and
Other.......... 15,184 2,065 1,296 9,197(d) 9,348
-------- ------- ------- ------- --------
Total............ $145,366 $23,156 $46,796 $11,857 $203,461
======== ======= ======= ======= ========
YEAR ENDED DECEMBER 31,
1991:
DEDUCTED FROM ASSETS:
Accumulated Provision
for
Uncollectible Ac-
counts............ $ 714 $ 1,674 $ 645(a) $ 2,404(b) $ 629
======== ======= ======= ======= ========
NOT SHOWN ELSEWHERE:
Operating Reserves:
Maintenance........ $ 7,551 $ -0- $ 118(c) $ 3,203(d) $ 4,466
Nuclear Plant
Decommissioning
Costs........... 106,632 19,084(e) -0- -0- 125,716
Workers'
Compensation,
Coal Inventory
Adjustment, and
Other.......... 9,489 9,418 2,607 6,330(d) 15,184
-------- ------- ------- ------- --------
Total............ $123,672 $28,502 $ 2,725 $ 9,533 $145,366
======== ======= ======= ======= ========
- --------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
(c) Billings to others.
(d) Payments and accrual adjustments.
(e) Includes interest on trust funds.
(f) Adjust Royalty Provision.
S-20
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES SCHEDULE IX -- SHORT-TERM
BORROWINGS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- -----------------------------------------------------------------------------------
MAXIMUM AVERAGE WEIGHTED
CATEGORY OF WEIGHTED AMOUNT AMOUNT AVERAGE
AGGREGATE BALANCE AT AVERAGE OUTSTANDING OUTSTANDING INTEREST RATE
SHORT-TERM END OF INTEREST DURING THE DURING THE DURING THE
BORROWINGS PERIOD RATE PERIOD PERIOD (A) PERIOD (B)
- -----------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
Notes Payable......... $ -0- -- % $17,200 $17,200 3.3%
Commercial Paper...... 50,075 3.6 50,075 27,832 3.3
YEAR ENDED DECEMBER 31,
1992:
Notes Payable......... $ -0- -- % $23,800 $12,431 3.9%
Commercial Paper...... 44,200 4.3 44,200 25,509 4.0
YEAR ENDED DECEMBER 31,
1991:
Notes Payable......... $14,850 5.4% $32,325 $14,810 6.4%
Commercial Paper...... 36,100 5.5 36,100 15,010 6.4
- --------
(a) Sum of month-end short-term borrowings divided by number of months
outstanding.
(b) Interest for the period divided by average amount outstanding.
S-21
KENTUCKY POWER COMPANY SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN F COLUMN F COLUMN F COLUMN F
- --------------------------------------------------------------------------------
1993 1992 1991 1990
---------- ---------- ---------- ----------
BALANCE AT BALANCE AT BALANCE AT BALANCE AT
END OF END OF END OF END OF
CLASSIFICATION PERIOD PERIOD PERIOD PERIOD
- --------------------------------------------------------------------------------
(IN THOUSANDS)
ELECTRIC UTILITY PLANT:
Production -- Steam -- Fossil-
fired........................... $211,617 $205,771 $204,045 $201,362
Transmission..................... 249,966 243,002 239,138 231,346
Distribution..................... 281,834 267,280 254,146 241,053
General.......................... 54,637 54,397 50,927 48,334
Construction Work in Progress.... 9,374 10,406 8,453 11,020
-------- -------- -------- --------
Total Electric Utility Plant... 807,428 780,856 756,709 733,115
NONUTILITY PROPERTY AND OTHER PROP-
ERTY INVESTMENTS.................. 6,846 7,249 7,217 7,217
-------- -------- -------- --------
Total.......................... $814,274 $788,105 $763,926 $740,332
======== ======== ======== ========
Total additions of $37,808,000 in 1993, $35,203,000 in 1992 and $31,369,000
in 1991 were less than 10% of the total as of the respective year-ends.
Retirements or sales of $12,000,000 in 1993, $11,352,000 in 1992 and $8,092,000
in 1991 were less than 10% of the total as of the respective year-ends. There
were no additions to individual accounts in excess of two percent of total
assets other than transfers from Construction Work in Progress.
The methods used to compute the annual provisions for depreciation are
described in Note 1 of the Notes to Financial Statements. The current
provisions were determined using the following composite rates for functional
classes of property:
FUNCTIONAL CLASS OF PROPERTY COMPOSITE ANNUAL RATE
- --------------------------------------------------------------------------------
Production -- Steam -- Fossil-fired.................... 3.8%
Transmission........................................... 1.7%
Distribution........................................... 3.5%
General................................................ 2.5%
S-22
KENTUCKY POWER COMPANY SCHEDULE VI -- ACCUMULATED DEPRECIATION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- --------------------------------------------------------------------------------
ADDITIONS OTHER
BALANCE AT CHARGED TO CHANGES -- BALANCE AT
BEGINNING COSTS AND RETIREMENTS ADD END OF
DESCRIPTION OF PERIOD EXPENSES OR SALES (DEDUCT) PERIOD
- --------------------------------------------------------------------------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
ACCUMULATED DEPRECIA-
TION AND
AMORTIZATION OF
ELECTRIC UTILITY
PLANT:
Production --
Steam -- Fossil-fired... $116,273 $ 7,853 $ 4,849 $-0- $119,277
Transmission........ 57,652 4,168 1,221 (1) 60,598
Distribution........ 52,542 9,405 5,233 9 56,723
General............. 11,875 2,329 2,103 (26) 12,075
-------- ------- ------- ---- --------
Total............. $238,342 $23,755 $13,406 $(18) $248,673
======== ======= ======= ==== ========
ACCUMULATED DEPRECIA-
TION
OF NONUTILITY PROP-
ERTY AND
OTHER PROPERTY IN-
VESTMENTS........... $ 828 $ 83 $ -0- $-0- $ 911
======== ======= ======= ==== ========
YEAR ENDED DECEMBER 31,
1992:
ACCUMULATED DEPRECIA-
TION AND
AMORTIZATION OF
ELECTRIC UTILITY
PLANT:
Production --
Steam -- Fossil-fired... $110,714 $ 7,739 $ 2,184 $ 4 $116,273
Transmission........ 54,759 4,030 1,131 (6) 57,652
Distribution........ 49,640 8,966 6,064 52,542
General............. 11,096 2,181 1,369 (33) 11,875
-------- ------- ------- ---- --------
Total............. $226,209 $22,916 $10,748 $(35) $238,342
======== ======= ======= ==== ========
ACCUMULATED DEPRECIA-
TION
OF NONUTILITY PROP-
ERTY AND
OTHER PROPERTY IN-
VESTMENTS........... $ 740 $ 88 $ -0- $-0- $ 828
======== ======= ======= ==== ========
YEAR ENDED DECEMBER 31,
1991:
ACCUMULATED DEPRECIA-
TION AND
AMORTIZATION OF
ELECTRIC UTILITY
PLANT:
Production --
Steam -- Fossil-fired... $104,631 $ 7,524 $ 1,441 $-0- $110,714
Transmission........ 51,827 4,102 1,133 (37) 54,759
Distribution........ 47,370 8,531 6,292 31 49,640
General............. 9,808 1,811 493 (30) 11,096
-------- ------- ------- ---- --------
Total............. $213,636 $21,968 $9,359 $(36) $226,209
======== ======= ======= ==== ========
ACCUMULATED DEPRECIA-
TION
OF NONUTILITY PROP-
ERTY AND
OTHER PROPERTY IN-
VESTMENTS........... $ 663 $ 77 $ -0- $-0- $ 740
======== ======= ======= ==== ========
S-23
KENTUCKY POWER COMPANY SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS AND
RESERVES
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ---------------------------------------------------------------------------------
ADDITIONS
---------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- ---------------------------------------------------------------------------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
DEDUCTED FROM ASSETS:
Accumulated Provi-
sion for
Uncollectible
Accounts........ $ 248 $ 390 $179(a) $ 609(b) $ 208
====== ====== ==== ====== ======
NOT SHOWN ELSEWHERE:
Operating Reserves
for
Workers' Compen-
sation
and Other....... $2,023 $1,323 $(22) $ 692(c) $2,632
====== ====== ==== ====== ======
YEAR ENDED DECEMBER 31,
1992:
DEDUCTED FROM ASSETS:
Accumulated Provi-
sion for
Uncollectible
Accounts........ $ 352 $ 630 $106(a) $ 840(b) $ 248
====== ====== ==== ====== ======
NOT SHOWN ELSEWHERE:
Operating Reserves
for
Workers' Compen-
sation
and Other....... $1,962 $1,162 $(34) $1,067(c) $2,023
====== ====== ==== ====== ======
YEAR ENDED DECEMBER 31,
1991:
DEDUCTED FROM ASSETS:
Accumulated Provi-
sion for
Uncollectible
Accounts........ $ 148 $ 645 $ 84(a) $ 525(b) $ 352
====== ====== ==== ====== ======
NOT SHOWN ELSEWHERE:
Operating Reserves
for
Workers' Compen-
sation
and Other....... $1,240 $1,309 $121 $ 708(c) $1,962
====== ====== ==== ====== ======
- --------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
(c) Payments.
S-24
KENTUCKY POWER COMPANY SCHEDULE IX -- SHORT-TERM BORROWINGS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- -----------------------------------------------------------------------------------
MAXIMUM AVERAGE WEIGHTED
CATEGORY OF WEIGHTED AMOUNT AMOUNT AVERAGE
AGGREGATE BALANCE AT AVERAGE OUTSTANDING OUTSTANDING INTEREST RATE
SHORT-TERM END OF INTEREST DURING THE DURING THE DURING THE
BORROWINGS PERIOD RATE PERIOD PERIOD (A) PERIOD (B)
- -----------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
Notes Payable......... $26,250 3.5% $26,250 $ 7,240 3.4%
Commercial Paper...... 11,900 3.8 35,300 19,394 3.4
YEAR ENDED DECEMBER 31,
1992:
Notes Payable......... $ 5,350 4.2% $13,000 $ 6,845 4.1%
Commercial Paper...... 11,550 4.2 11,550 4,350 3.8
YEAR ENDED DECEMBER 31,
1991:
Notes Payable......... $18,500 5.0% $20,525 $11,675 7.9%
Commercial Paper...... -0- -- 21,200 8,908 6.8
- --------
(a) Sum of month-end short-term borrowings divided by number of months
outstanding.
(b) Interest for the period divided by average amount outstanding.
S-25
OHIO POWER COMPANY AND SUBSIDIARIES SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN F COLUMN F COLUMN F COLUMN F
- --------------------------------------------------------------------------------
1993 1992 1991 1990
---------- ---------- ---------- ----------
BALANCE AT BALANCE AT BALANCE AT BALANCE AT
END OF END OF END OF END OF
CLASSIFICATION PERIOD PERIOD PERIOD PERIOD
- --------------------------------------------------------------------------------
(IN THOUSANDS)
ELECTRIC UTILITY PLANT:
Production -- Steam -- Fossil-
fired............................. $2,412,973 $2,391,432 $2,337,827 $2,300,012
Transmission..................... 767,548 758,134 741,085 727,159
Distribution..................... 766,639 731,559 689,588 668,259
General (including mining as-
sets)............................. 754,347 773,122 879,533 826,522
Construction Work in Progress.... 100,820 79,535 113,323 102,125
---------- ---------- ---------- ----------
Total Electric Utility Plant... 4,802,327 4,733,782 4,761,356 4,624,077
NONUTILITY PROPERTY AND OTHER PROP-
ERTY INVESTMENTS.................. 89,558 83,953 52,748 49,179
---------- ---------- ---------- ----------
Total.......................... $4,891,885 $4,817,735 $4,814,104 $4,673,256
========== ========== ========== ==========
Total additions of $197,089,000 in 1993, $201,737,000 in 1992 and
$228,500,000 in 1991 were less than 10% of the total as of the respective year-
ends. Retirements or sales of $128,775,000 in 1993, $191,662,000 in 1992 and
$90,472,000 in 1991 were less than 10% of the total as of the respective year-
ends. There were no additions to individual accounts in excess of two percent
of total assets other than transfers from Construction Work in Progress.
The methods used to compute the annual provisions for depreciation are
described in Note 1 of the Notes to Consolidated Financial Statements. The
current provisions for other than mining assets were determined using the
following composite rates for functional classes of property:
FUNCTIONAL CLASS OF PROPERTY COMPOSITE ANNUAL RATE
- --------------------------------------------------------------------------------
Production -- Steam -- Fossil-fired..................... 3.6%
Transmission............................................ 1.7%
Distribution............................................ 3.9%
General................................................. 2.1%
The current provisions for mining assets were calculated by use of the
following methods:
DESCRIPTION METHOD
------------------------------- ----------------------------------------
Mining Structures and Equipment Straight-Line method (original
lives range from 1 to 30 years)
Coal Interests and Mine Units-of-production method (based on
Development Costs estimated recoverable tonnages; current
rate averages 55 cents per ton)
S-26
OHIO POWER COMPANY AND SUBSIDIARIES SCHEDULE VI -- ACCUMULATED DEPRECIATION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- --------------------------------------------------------------------------------
ADDITIONS OTHER
BALANCE AT CHARGED TO CHANGES -- BALANCE AT
BEGINNING COSTS AND RETIREMENTS ADD END OF
DESCRIPTION OF PERIOD EXPENSES OR SALES (DEDUCT) PERIOD
- --------------------------------------------------------------------------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
ACCUMULATED DEPRECIA-
TION AND AMORTIZA-
TION
OF ELECTRIC UTILITY
PLANT:
Production --
Steam-- Fossil-fired... $1,130,205 $ 85,065 $ 57,958 $ (1,172) $1,156,140
Transmission........ 265,418 13,130 5,261 2,029 275,316
Distribution........ 180,959 28,503 18,480 1,750 192,732
General (including
mining assets)......... 339,429 38,022 30,100 20,543 367,894
---------- -------- -------- -------- ----------
Total............. $1,916,011 $164,720 $111,799 $ 23,150 $1,992,082
========== ======== ======== ======== ==========
ACCUMULATED DEPRECIA-
TION OF
NONUTILITY PROPERTY
AND OTHER
PROPERTY INVEST-
MENTS............... $ 11,467 $ 800 $ 1,652 $ (2) $ 10,613
========== ======== ======== ======== ==========
YEAR ENDED DECEMBER 31,
1992:
ACCUMULATED DEPRECIA-
TION AND AMORTIZA-
TION
OF ELECTRIC UTILITY
PLANT:
Production --
Steam-- Fossil-fired... $1,088,875 $ 82,596 $ 42,438 $ 1,172 $1,130,205
Transmission........ 255,931 12,903 3,493 77 265,418
Distribution........ 172,672 27,180 19,357 464 180,959
General (including
mining assets)......... 354,233 45,633 78,384 17,947 339,429
---------- -------- -------- -------- ----------
Total............. $1,871,711 $168,312 $143,672 $ 19,660 $1,916,011
========== ======== ======== ======== ==========
ACCUMULATED DEPRECIA-
TION OF
NONUTILITY PROPERTY
AND OTHER
PROPERTY INVEST-
MENTS............... $ 10,740 $ 588 $ (139) $ -0- $ 11,467
========== ======== ======== ======== ==========
YEAR ENDED DECEMBER 31,
1991:
ACCUMULATED DEPRECIA-
TION AND AMORTIZA-
TION
OF ELECTRIC UTILITY
PLANT:
Production --
Steam-- Fossil-fired... $1,034,539 $ 81,472 $ 27,136 $ -0- $1,088,875
Transmission........ 250,219 12,600 7,093 205 255,931
Distribution........ 162,754 25,983 16,780 715 172,672
General (including
mining assets)......... 328,787 51,907 39,192 12,731 354,233
---------- -------- -------- -------- ----------
Total............. $1,776,299 $171,962 $ 90,201 $ 13,651 $1,871,711
========== ======== ======== ======== ==========
ACCUMULATED DEPRECIA-
TION OF
NONUTILITY PROPERTY
AND OTHER
PROPERTY INVEST-
MENTS............... $ 10,473 $ 347 $ 80 $ -0- $ 10,740
========== ======== ======== ======== ==========
S-27
OHIO POWER COMPANY AND SUBSIDIARIES SCHEDULE VIII -- VALUATION AND QUALIFYING
ACCOUNTS AND RESERVES
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ------------------------------------------------------------------------------------
ADDITIONS
---------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- ------------------------------------------------------------------------------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
DEDUCTED FROM ASSETS:
Accumulated Provi-
sion for
Uncollectible Ac-
counts........... $ 4,353 $ 4,812 $ 549(a) $ 8,754(b) $ 960
======= ======= ======= ======= =======
NOT SHOWN ELSEWHERE:
Operating Reserves:
Maintenance....... $ 5,961 $(1,721) $ 184(c) $ 1,071(d) $ 3,353
Reclamation....... 8,537 7,508 -0- 7,313(d) 8,732
Workers' Compensa-
tion and Oth-
er........... 20,302 5,790 (91) 9,327(d) 16,674
------- ------- ------- ------- -------
Total........... $34,800 $11,577 $ 93 $17,711 $28,759
======= ======= ======= ======= =======
YEAR ENDED DECEMBER 31,
1992:
DEDUCTED FROM ASSETS:
Accumulated Provi-
sion for
Uncollectible Ac-
counts........... $ 4,815 $ 4,084 $ 618(a) $ 5,164(b) $ 4,353
======= ======= ======= ======= =======
NOT SHOWN ELSEWHERE:
Operating Reserves:
Maintenance....... $ 8,336 $(1,239) $ 297(c) $ 1,433(d) $ 5,961
Reclamation....... 9,089 7,456 -0- 8,008(d) 8,537
Workers' Compensa-
tion and Oth-
er........... 7,938 11,690 11,026 10,352(d) 20,302
------- ------- ------- ------- -------
Total........... $25,363 $17,907 $11,323 $19,793 $34,800
======= ======= ======= ======= =======
YEAR ENDED DECEMBER 31,
1991:
DEDUCTED FROM ASSETS:
Accumulated Provi-
sion for
Uncollectible Ac-
counts........... $ 8,540 $ 2,042 $ 557(a) $ 6,324(b) $ 4,815
======= ======= ======= ======= =======
NOT SHOWN ELSEWHERE:
Operating Reserves:
Maintenance....... $11,532 $(1,531) $ 56(c) $ 1,721(d) $ 8,336
Reclamation....... 13,121 2,329 -0- 6,361(d) 9,089
Workers' Compensa-
tion and Oth-
er........... 6,873 9,355 (295) 7,995(d) 7,938
------- ------- ------- ------- -------
Total........... $31,526 $10,153 $ (239) $16,077 $25,363
======= ======= ======= ======= =======
- --------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
(c) Billings to others.
(d) Payments.
S-28
OHIO POWER COMPANY AND SUBSIDIARIES SCHEDULE IX -- SHORT-TERM BORROWINGS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- -----------------------------------------------------------------------------------
MAXIMUM AVERAGE WEIGHTED
CATEGORY OF WEIGHTED AMOUNT AMOUNT AVERAGE
AGGREGATE BALANCE AT AVERAGE OUTSTANDING OUTSTANDING INTEREST RATE
SHORT-TERM END OF INTEREST DURING THE DURING THE DURING THE
BORROWINGS PERIOD RATE PERIOD PERIOD (A) PERIOD (B)
- -----------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993:
Notes Payable......... $ 2,251 3.1% $ 45,650 $10,564 3.2%
Commercial Paper...... 38,000 3.6 68,700 33,033 3.4
YEAR ENDED DECEMBER 31,
1992:
Notes Payable......... $ -0- --% $ 26,000 $14,167 4.2%
Commercial Paper...... -0- -- 102,945 70,711 4.2
YEAR ENDED DECEMBER 31,
1991:
Notes Payable......... $ 1,208 6.0% $ 45,995 $13,065 6.0%
Commercial Paper...... 132,325 5.4 132,325 77,492 6.3
- --------
(a) Sum of month-end short-term borrowings divided by number of months
outstanding.
(b) Interest for the period divided by average amount outstanding.
S-29
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. (S)201.24 and (S)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
EXHIBIT
NUMBER DESCRIPTION
------- -----------
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)(1)(A) -- Copy of Lease Agreement (AEGCO Trust 1), dated as of December
1, 1989, between AEGCo and Wilmington Trust Company
[Registration Statement No. 33-32752, Exhibit 28(c)(1)(C)].
*10(c)(1)(B) -- Copy of Lease Supplement No. 1 (AEGCO Trust 1), dated as of
October 15, 1990.
10(c)(2)(A) -- Copy of Lease Agreement (AEGCO Trust 2), dated as of December
1, 1989, between AEGCo and Wilmington Trust Company
[Registration Statement No. 33-32752, Exhibit 28(c)(2)(C)].
*10(c)(2)(B) -- Copy of Lease Supplement No. 1 (AEGCO Trust 2), dated as of
October 15, 1990.
10(c)(3)(A) -- Copy of Lease Agreement (AEGCO Trust 3), dated as of December
1, 1989, between AEGCo and Wilmington Trust Company
[Registration Statement No. 33-32752, Exhibit 28(c)(3)(C)].
*10(c)(3)(B) -- Copy of Lease Supplement No. 1 (AEGCO Trust 3), dated as of
October 15, 1990.
10(c)(4)(A) -- Copy of Lease Agreement (AEGCO Trust 4), dated as of December
1, 1989, between AEGCo and Wilmington Trust Company
[Registration Statement No. 33-32752, Exhibit 28(c)(4)(C)].
*10(c)(4)(B) -- Copy of Lease Supplement No. 1 (AEGCO Trust 4), dated as of
October 15, 1990.
10(c)(5)(A) -- Copy of Lease Agreement (AEGCO Trust 5), dated as of December
1, 1989, between AEGCo and Wilmington Trust Company
[Registration Statement No. 33-32752, Exhibit 28(c)(5)(C)].
*10(c)(5)(B) -- Copy of Lease Supplement No. 1 (AEGCO Trust 5), dated as of
October 15, 1990.
10(c)(6)(A) -- Copy of Lease Agreement (AEGCO Trust 6), dated as of December
1, 1989, between AEGCo and Wilmington Trust Company
[Registration Statement No. 33-32752, Exhibit 28(c)(6)(C)].
*10(c)(6)(B) -- Copy of Lease Supplement No. 1 (AEGCO Trust 6), dated as of
October 15, 1990.
*13 -- Copy of those portions of the AEGCo 1993 Annual Report (for
the fiscal year ended December 31, 1993) which are
incorporated by reference in this filing,
*24 -- Power of Attorney.
E-1
AEGCO (continued)
EXHIBIT
NUMBER DESCRIPTION
------- -----------
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, 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.
+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).
*+10(g)(3) -- Service Corporation Umbrella Trust(TM) for Executives.
E-2
AEP++ (continued)
EXHIBIT
NUMBER DESCRIPTION
------- -----------
+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(h)(2) -- Employment Agreement between John E. Katlic and the Service
Corporation [Annual Report on Form 10-K of AEGCo for the
fiscal year ended December 31, 1990, File No. 0-18135,
Exhibit 10(g)(2)].
*+10(i)(1) -- AEP Management Incentive Compensation Plan.
*+10(i)(2) -- American Electric Power System Performance Share Incentive
Plan.
10(j)(1)(A) -- Copy of Lease Agreement (AEGCO Trust 1), dated as of December
1, 1989, between AEGCo and Wilmington Trust Company
[Registration Statement No. 33-32752, Exhibit 28(c)(1)(C)].
10(j)(1)(B) -- Copy of Lease Supplement No. 1 (AEGCO Trust 1), dated as of
October 15, 1990. [Annual Report on Form 10-K of AEGCo for
the fiscal year ended December 31, 1993, File No. 0-18135,
Exhibit 10(c)(1)(B)].
10(j)(2)(A) -- Copy of Lease Agreement (AEGCO Trust 2), dated as of December
1, 1989, between AEGCo and Wilmington Trust Company
[Registration Statement No. 33-32752, Exhibit 28(c)(2)(C)].
10(j)(2)(B) -- Copy of Lease Supplement No. 1 (AEGCO Trust 2), dated as of
October 15, 1990. [Annual Report on Form 10-K of AEGCo for
the fiscal year ended December 31, 1993, File No. 0-18135,
Exhibit 10(c)(2)(B)].
10(j)(3)(A) -- Copy of Lease Agreement (AEGCO Trust 3), dated as of December
1, 1989, between AEGCo and Wilmington Trust Company
[Registration Statement No. 33-32752, Exhibit 28(c)(3)(C)].
10(j)(3)(B) -- Copy of Lease Supplement No. 1 (AEGCO Trust 3), dated as of
October 15, 1990. [Annual Report on Form 10-K of AEGCo for
the fiscal year ended December 31, 1993, File No. 0-18135,
Exhibit 10(c)(3)(B)].
10(j)(4)(A) -- Copy of Lease Agreement (AEGCO Trust 4), dated as of December
1, 1989, between AEGCo and Wilmington Trust Company
[Registration Statement No. 33-32752, Exhibit 28(c)(4)(C)].
10(j)(4)(B) -- Copy of Lease Supplement No. 1 (AEGCO Trust 4), dated as of
October 15, 1990. [Annual Report on Form 10-K of AEGCo for
the fiscal year ended December 31, 1993, File No. 0-18135,
Exhibit 10(c)(4)(B)].
10(j)(5)(A) -- Copy of Lease Agreement (AEGCO Trust 5), dated as of December
1, 1989, between AEGCo and Wilmington Trust Company
[Registration Statement No. 33-32752, Exhibit 28(c)(5)(C)].
10(j)(5)(B) -- Copy of Lease Supplement No. 1 (AEGCO Trust 5), dated as of
October 15, 1990. [Annual Report on Form 10-K of AEGCo for
the fiscal year ended December 31, 1993, File No. 0-18135,
Exhibit 10(c)(5)(B)].
10(j)(6)(A) -- Copy of Lease Agreement (AEGCO Trust 6), dated as of December
1, 1989, between AEGCo and Wilmington Trust Company
[Registration Statement No. 33-32752, Exhibit 28(c)(6)(C)].
10(j)(6)(B) -- Copy of Lease Supplement No. 1 (AEGCO Trust 6), dated as of
October 15, 1990. [Annual Report on Form 10-K of AEGCo for
the fiscal year ended December 31, 1993, File No. 0-18135,
Exhibit 10(c)(6)(B)].
10(j)(7)(A) -- Copy of Lease Agreement (I&M Trust 1), dated as of December
1, 1989, between I&M and Wilmington Trust Company
[Registration Statement No. 33-32753, Exhibit 28(a)(1)(C)].
E-3
AEP++ (continued)
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10(j)(7)(B) -- Copy of Lease Supplement No. 1 (I&M Trust 1), dated as of
October 15, 1990 [Annual Report on Form 10-K of I&M for the
fiscal year ended December 31, 1993, File No. 1-3570,
Exhibit 10(e)(1)(B)]
10(j)(8)(A) -- Copy of Lease Agreement (I&M Trust 2), dated as of December
1, 1989, between I&M and Wilmington Trust Company
[Registration Statement No. 33-32753, Exhibit 28(a)(2)(C)].
10(j)(8)(B) -- Copy of Lease Supplement No. 1 (I&M Trust 2), dated as of
October 15, 1990 [Annual Report on Form 10-K of I&M for the
fiscal year ended December 31, 1993, File No. 1-3570,
Exhibit 10(e)(2)(B)].
10(j)(9)(A) -- Copy of Lease Agreement (I&M Trust 3), dated as of December
1, 1989, between I&M and Wilmington Trust Company
[Registration Statement No. 33-32753, Exhibit 28(a)(3)(C)].
10(j)(9)(B) -- Copy of Lease Supplement No. 1 (I&M Trust 3), dated as of
October 15, 1990 [Annual Report on Form 10-K of I&M for the
fiscal year ended December 31, 1993, File No. 1-3570,
Exhibit 10(e)(3)(B)].
10(j)(10)(A) -- Copy of Lease Agreement (I&M Trust 4), dated as of December
1, 1989, between I&M and Wilmington Trust Company
[Registration Statement No. 33-32753, Exhibit 28(a)(4)(C)].
10(j)(10)(B) -- Copy of Lease Supplement No. 1 (I&M Trust 4), dated as of
October 15, 1990 [Annual Report on Form 10-K of I&M for the
fiscal year ended December 31, 1993, File No. 1-3570,
Exhibit 10(e)(4)(B)].
10(j)(11)(A) -- Copy of Lease Agreement (I&M Trust 5), dated as of December
1, 1989, between I&M and Wilmington Trust Company
[Registration Statement No. 33-32753, Exhibit 28(a)(5)(C)].
10(j)(11)(B) -- Copy of Lease Supplement No. 1 (I&M Trust 5), dated as of
October 15, 1990 [Annual Report on Form 10-K of I&M for the
fiscal year ended December 31, 1993, File No. 1-3570,
Exhibit 10(e)(5)(B)].
10(j)(12)(A) -- Copy of Lease Agreement (I&M Trust 6), dated as of December
1, 1989, between I&M and Wilmington Trust Company
[Registration Statement No. 33-32753, Exhibit 28(a)(6)(C)].
10(j)(12)(B) -- Copy of Lease Supplement No. 1 (I&M Trust 6), dated as of
October 15, 1990 [Annual Report on Form 10-K of I&M for the
fiscal year ended December 31, 1993, File No. 1-3570,
Exhibit 10(e)(6)(B)].
10(k) -- 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)].
*13 -- Copy of those portions of the AEP 1993 Annual Report (for
the fiscal year ended December 31, 1993) which are
incorporated by reference in this filing.
*21 -- List of subsidiaries of AEP.
*23 -- Consent of Deloitte & Touche.
*24 -- Power of Attorney.
APCO++
3(a) -- Copy of Restated Articles of Incorporation of APCo, and
amendments thereto to March 24, 1992 [Registration Statement
No. 33-50163; Exhibit 4(a)].
*3(b) -- Copy of Articles of Amendment to the Restated Articles of
Incorporation of APCo dated October 4, 1993 and October 28,
1993.
*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)].
E-4
APCO++ (continued)
EXHIBIT
NUMBER DESCRIPTION
------- -----------
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 to May 15, 1993
[Registration Statement No. 2-7289, Exhibit 7(b); Registration
Statement No. 2-19884, Exhibit 2(1); Registration Statement No.
2-24453, Exhibit 2(n); Registration Statement No. 2-60015,
Exhibits 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), 2(b)(6), 2(b)(7),
2(b)(8), 2(b)(9), 2(b)(10), 2(b)(12), 2(b)(14), 2(b)(15),
2(b)(16), 2(b)(17), 2(b)(18), 2(b)(19), 2(b)(20), 2(b)(21),
2(b)(22), 2(b)(23), 2(b)(24), 2(b)(25), 2(b)(26), 2(b)(27) and
2(b)(28); Registration Statement No. 2-64102, Exhibit 2(b)(29);
Registration Statement No. 2-66457, Exhibits (2)(b)(30) and
2(b)(31); Registration Statement No. 2-69217, Exhibit 2(b)(32);
Registration Statement No. 2-86237, Exhibit 4(b); Registration
Statement No. 33-11723, Exhibit 4(b); Registration Statement No.
33-17003, Exhibit 4(a)(ii); Registration Statement No. 33-30964,
Exhibit 4(b); Registration Statement No. 33-40720, Exhibit 4(b);
Registration Statement No. 33-45219, Exhibit 4(b); Registration
Statement No. 33-46128, Exhibits 4(b) and 4(c); Registration
Statement No. 33-53410, Exhibit 4(b); Registration Statement No.
33-59834, Exhibit 4(b); Registration Statement No. 33-50229,
Exhibits 4(b) and 4(c)].
*4(b) -- Copy of Indentures Supplemental dated October 1, 1993 and
November 1, 1993 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, File No. 1-3525, Exhibit 10(b)(2)].
+10(d)(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(d)(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(e)(1) -- Management Incentive Compensation Plan [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1993, File
No. 1-3525, Exhibit 10(i)].
E-5
APCO++ (continued)
EXHIBIT
NUMBER DESCRIPTION
------- -----------
+10(e)(2) -- American Electric Power System Performance Share Incentive
Plan [Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1993, File No. 1-3525, Exhibit 10(i)(2)].
+10(f)(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(f)(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(f)(3) -- Umbrella Trust(TM) 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(g)(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(g)(2) -- Employment Agreement between John E. Katlic and the Service
Corporation [Annual Report on Form 10-K of AEGCo for the
fiscal year ended December 31, 1990, File No.
0-18135, Exhibit 10(g)(2)].
*12 -- Statement re: Computation of Ratios
*13 -- Copy of those portions of the APCo 1993 Annual Report (for
the fiscal year ended December 31, 1993) 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, 1993, File No. 1-
3525, Exhibit 22].
*23 -- Consent of Deloitte & Touche
*24 -- Power of Attorney
CSPCO++
3(a) -- Copy of Amended Articles of Incorporation of CSPCo
[Registration Statement No. 33-45950, Exhibit 4(a)].
3(b)(1) -- Copy of Certificate of Amendment to Amended Articles of
Incorporation of CSPCo, dated November 19, 1990 [Registration
Statement No. 33-45950, Exhibit 4(b)].
3(b)(2) -- Copy of Certificate of Amendment to Amended Articles of
Incorporation of CSPCo, dated March 6, 1992 [Certificate of
Notification on Form U-6B-2, dated March 23, 1992].
3(c) -- Composite copy of Amended Articles of Incorporation of CSPCo,
as amended [Annual Report on Form 10-K of CSPCo for the
fiscal year ended December 31, 1991, File No. 1-2680, Exhibit
3(c)].
3(d) -- Copy of Code of Regulations and By-Laws of CSPCo [Annual
Report on Form 10-K of CSPCo for the fiscal year ended
December 31, 1987, File No. 1-2680, Exhibit 3(d)].
4(a) -- Copy of Indenture of Mortgage and Deed of Trust, dated
September 1, 1940, between CSPCo and City Bank Farmers Trust
Company (now Citibank, N.A.), as trustee, as supplemented and
amended [Registration Statement No. 2-59411, Exhibits 2(B)
and 2(C); Registration Statement No. 2-80535, Exhibit 4(b);
Registration Statement No. 2-87091, Exhibit 4(b);
Registration Statement No. 2-93208, Exhibit 4(b);
Registration Statement No. 2-97652, Exhibit 4(b);
Registration Statement No. 33-7081, Exhibit 4(b);
Registration Statement No. 33-12389, Exhibit 4(b);
Registration Statement No. 33-19227, Exhibits 4(b), 4(e),
4(f), 4(g) and 4(h); Registration Statement No. 33-35651,
Exhibit 4(b); Registration Statement No. 33-46859, Exhibits
4(b) and 4(c); Registration Statement No. 33-50316, Exhibits
4(b) and 4(c); Registration Statement No. 33-60336; Exhibits
4(b), 4(c) and 4(d); Registration Statement No. 33-50447,
Exhibits 4(b) and 4(c)].
*4(b) -- Copy of Supplemental Indentures dated October 1, 1993,
January 1, 1994 and March 1, 1994 to Indenture of Mortgage
and Deed of Trust.
E-6
CSPCO++ (continued)
EXHIBIT
NUMBER DESCRIPTION
------- -----------
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)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the CSPCo 1993 Annual Report (for the
fiscal year ended December 31, 1993) 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, 1993, File No. 1-3525,
Exhibit 22].
*23 -- Consent of Deloitte & Touche.
*24 -- Power of Attorney.
I&M++
*3(a) -- Copy of the Amended Articles of Acceptance of I&M and amendments
thereto.
*3(b) -- Composite Copy of the Amended Articles of Acceptance of I&M, as
amended.
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)].
E-7
I&M++ (continued)
EXHIBIT
NUMBER DESCRIPTION
------- -----------
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)].
*4(b) -- Copy of Indentures Supplemental dated October 15, 1993 and
February 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 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 Nuclear Material Lease Agreement, dated as of
December 1, 1990, between I&M and DCC Fuel Corporation.
10(e)(1)(A) -- Copy of Lease Agreement (I&M Trust 1), dated as of December
1, 1989, between I&M and Wilmington Trust Company
[Registration Statement No. 33-32753, Exhibit 28(a)(1)(C)].
*10(e)(1)(B) -- Copy of Lease Supplement No. 1 (I&M Trust 1), dated as of
October 15, 1990.
E-8
I&M++ (continued)
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10(e)(2)(A) -- Copy of Lease Agreement (I&M Trust 2), dated as of December
1, 1989, between I&M and Wilmington Trust Company
[Registration Statement No. 33-32753, Exhibit 28(a)(2)(C)].
*10(e)(2)(B) -- Copy of Lease Supplement No. 1 (I&M Trust 2), dated as of
October 15, 1990.
10(e)(3)(A) -- Copy of Lease Agreement (I&M Trust 3), dated as of December
1, 1989, between I&M and Wilmington Trust Company
[Registration Statement No. 33-32753, Exhibit 28(a)(3)(C)].
*10(e)(3)(B) -- Copy of Lease Supplement No. 1 (I&M Trust 3), dated as of
October 15, 1990.
10(e)(4)(A) -- Copy of Lease Agreement (I&M Trust 4), dated as of December
1, 1989, between I&M and Wilmington Trust Company
[Registration Statement No. 33-32753, Exhibit 28(a)(4)(C)].
*10(e)(4)(B) -- Copy of Lease Supplement No. 1 (I&M Trust 4), dated as of
October 15, 1990.
10(e)(5)(A) -- Copy of Lease Agreement (I&M Trust 5), dated as of December
1, 1989, between I&M and Wilmington Trust Company
[Registration Statement No. 33-32753, Exhibit 28(a)(5)(C)].
*10(e)(5)(B) -- Copy of Lease Supplement No. 1 (I&M Trust 5), dated as of
October 15, 1990.
10(e)(6)(A) -- Copy of Lease Agreement (I&M Trust 6), dated as of December
1, 1989, between I&M and Wilmington Trust Company
[Registration Statement No. 33-32753, Exhibit 28(a)(6)(C)].
*10(e)(6)(B) -- Copy of Lease Supplement No. 1 (I&M Trust 6), dated as of
October 15, 1990.
*12 -- Statement re: Computation of Ratios
*13 -- Copy of those portions of the I&M 1993 Annual Report (for the
fiscal year ended December 31, 1993) 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, 1993, File No. 1-
3525, Exhibit 22].
*23 -- Consent of Deloitte & Touche.
*24 -- Power of Attorney.
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 [Annual Report on Form 10-K of KEPCo
for the fiscal year ended December 31, 1990, File No. 1-6858,
Exhibit 3(b)].
4(a)(1) -- 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)].
*4(a)(2) -- Copy of Indentures Supplemental dated May 1, 1993, June 1,
1993 and June 15, 1993 to Mortgage and Deed of Trust.
10(a) -- Copy of Interconnection Agreement, dated July 6, 1951, among
APCo, CSPCo, KEPCo, I&M and OPCo and with the Service
Corporation, as amended [Registration Statement No. 2-52910,
Exhibit 5(a); Registration Statement No. 2-61009, Exhibit
5(b); and Annual Report on Form 10-K of AEP for the fiscal
year ended December 31, 1990, File No. 1-3525, Exhibit
10(a)(3)].
E-9
KEPCO (continued)
EXHIBIT
NUMBER DESCRIPTION
------- -----------
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)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy those portions of the KEPCo 1993 Annual Report (for the
fiscal year ended December 31, 1993) which are incorporated by
reference in this filing.
*23 -- Consent of Deloitte & Touche.
*24 -- Power of Attorney.
OPCO++
3(a) -- Copy of Amended Articles of Incorporation of OPCo, and
amendments thereto to April 6, 1993 [Registration Statement No.
33-50139, Exhibit 4(a)].
*3(b) -- Copy of Certificates of Amendment to the Amended Articles of
Incorporation of OPCo, dated October 4, 1993 and October 28,
1993.
*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)].
*4(b) -- Copy of Indentures Supplemental dated October 1, 1993, November
1, 1993 and December 1, 1993.
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC
and United States of America, acting by and through the United
States Atomic Energy Commission, and, subsequent to January 18,
1975, the Administrator of the Energy Research and Development
Administration, as amended [Registration Statement No. 2-60015,
Exhibit 5(a); Registration Statement No. 2-63234, Exhibit
5(a)(1)(B); Registration Statement No. 2-66301, Exhibit
5(a)(1)(C); Registration Statement No. 2-67728, Exhibit
5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal
year ended December 31, 1989, File No. 1-3457, Exhibit
10(a)(1)(F); Annual Report on Form 10-K of APCo for the fiscal
year ended December 31, 1992, File No. 1-3457, Exhibit
10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10, 1953,
among OVEC and the Sponsoring Companies, as amended
[Registration Statement No. 2-60015, Exhibit 5(c); Registration
Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form
10-K of APCo for the fiscal year ended December 31, 1992, File
No. 1-3457, Exhibit 10(a)(2)(B)].
10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and
Indiana-Kentucky Electric Corporation, as amended [Registration
Statement No. 2-60015, Exhibit 5(e)].
E-10
OPCO++ (continued)
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, between
APCo, CSPCo, KEPCo, I&M and OPCo and with the Service
Corporation, as amended [Registration Statement No. 2-52910,
Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b);
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 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(e) -- Copy of Power Agreement, dated November 16, 1966, between OPCo
and Ormet Generating Corporation and First Supplemental
Agreement thereto.
*10(f) -- 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.
+10(g)(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(g)(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(h)(1) -- Management Incentive Compensation Plan [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1993, File
No. 1-3525, Exhibit 10(i)].
+10(h)(2) -- American Electric Power System Performance Share Incentive Plan
[Annual Report on Form 10-K of AEP for the fiscal year ended
December 31, 1993, File No. 1-3525, Exhibit 10(i)(2)].
+10(i)(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(i)(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(i)(3) -- Umbrella Trust (TM) 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(j)(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(j)(2) -- Employment Agreement between John E. Katlic and the Service
Corporation [Annual Report on Form 10-K of AEGCo for the fiscal
year ended December 31, 1990, File No. 0-18135, Exhibit
10(g)(2)].
10(k) -- 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)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the OPCo 1993 Annual Report (for the
fiscal year ended December 31, 1993) which are incorporated by
reference in this filing.
E-11
OPCO++ (continued)
EXHIBIT
NUMBER DESCRIPTION
------- -----------
21 -- List of subsidiaries of OPCo [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1993, File No. 1-3525,
Exhibit 22].
*23 -- Consent of Deloitte & Touche.
*24 -- Power of Attorney.
--------------
++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.
E-12