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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
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(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 ________
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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
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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.
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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
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SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
REGISTRANT TITLE OF EACH CLASS
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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
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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
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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
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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
======== ========== ======== ========== ======== ========== ==========
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(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.