SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
AMENDMENT NO. 1
(Mark One)
[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission Registrant; State of Incorporation; I.R.S. Employer
File Number Address; and Telephone Number Identification No.
1-3525 American Electric Power Company, Inc. 13-4922640
(A New York Corporation)
1 Riverside Plaza
Columbus, Ohio 43215
Telephone (614) 223-1000
0-18135 AEP Generating Company 31-1033833
(An Ohio Corporation)
1 Riverside Plaza
Columbus, Ohio 43215
Telephone (614) 223-1000
1-3457 Appalachian Power Company 54-0124790
(A Virginia Corporation)
40 Franklin Road, S.W.
Roanoke, Virginia 24011
Telephone (540) 985-2300
1-2680 Columbus Southern Power Company 31-4154203
(An Ohio Corporation)
215 North Front Street
Columbus, Ohio 43215
Telephone (614) 464-7700
1-3570 Indiana Michigan Power Company 35-0410455
(An Indiana Corporation)
One Summit Square
P. O. Box 60
Fort Wayne, Indiana 46801
Telephone (219) 425-2111
1-6858 Kentucky Power Company 61-0247775
(A Kentucky Corporation)
1701 Central Avenue
Ashland, Kentucky 41101
Telephone (800) 572-1141
1-6543 Ohio Power Company 31-4271000
(An Ohio Corporation)
301 Cleveland Avenue, S.W.
Canton, Ohio 44702
Telephone (330) 456-8173
AEP Generating Company, Columbus Southern Power Company and Kentucky
Power Company meet the conditions set forth in General Instruction I(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 I(2) to such Form 10-K.
Indicate by check mark whether the registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that
the registrants were required to file such reports), and (2) have been subject
to such filing requirements for the past 90 days. Yes (check mark) 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
8-1/4% Junior Subordinated Deferrable
Interest Debentures, Series A,
Due 2026 New York Stock Exchange
8% Junior Subordinated Deferrable
Interest Debentures, Series B,
Due 2027 New York Stock Exchange
7.20% Senior Notes, Series A,
Due 2038 New York Stock Exchange
Columbus Southern 8-3/8% Junior Subordinated Deferrable
Power Company Interest Debentures, Series A,
Due 2025 New York Stock Exchange
7.92% Junior Subordinated Deferrable
Interest Debentures, Series B,
Due 2027 New York Stock Exchange
Indiana Michigan 8% Junior Subordinated Deferrable
Power Company Interest Debentures, Series A,
Due 2026 New York Stock Exchange
Kentucky Power Company 8.72% Junior Subordinated Deferrable
Interest Debentures, Series A,
Due 2025 New York Stock Exchange
Ohio Power Company 8.16% Junior Subordinated Deferrable
Interest Debentures, Series A,
Due 2025 New York Stock Exchange
7.92% Junior Subordinated Deferrable
Interest Debentures, Series B,
Due 2027 New York Stock Exchange
Indicate by check mark if disclosure of delinquent filers with respect
to American Electric Power Company, Inc. pursuant to Item 405 of Regulation S-
K (Section 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
statement of American Electric Power Company, Inc. incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K. ____
Indicate by check mark if disclosure of delinquent filers with respect
to Appalachian Power Company, Indiana Michigan Power Company or Ohio Power
Company pursuant to Item 405 of Regulation S-K (Section 229.405 of this chap-
ter) is not contained herein, and will not be contained, to the best of
registrant's knowledge, in the definitive information statements of
Appalachian Power Company or Ohio Power Company incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K. (check mark)
Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of each class
AEP Generating Company None
American Electric Power Company, Inc. None
Appalachian Power Company None
Columbus Southern Power Company None
Indiana Michigan Power Company 4-1/8% Cumulative Preferred Stock,
Non-Voting, $100 par value
Kentucky Power Company None
Ohio Power Company 4-1/2% Cumulative Preferred Stock,
Voting, $100 par value
Aggregate market value
of voting and non-voting Number of shares
common equity held of common stock
by non-affiliates of outstanding of
the registrants at the registrants at
February 13, 1998 February 13, 1998
AEP Generating Company None 1,000
($1,000 par value)
American Electric Power
Company, Inc. $9,333,250,000 189,989,989
($6.50 par value)
Appalachian Power Company None 13,499,500
(no par value)
Columbus Southern Power
Company None 16,410,426
(no par value)
Indiana Michigan Power
Company None 1,400,000
(no par value)
Kentucky Power Company None 1,009,000
($50 par value)
Ohio Power Company None 27,952,473
(no par value)
NOTE ON MARKET VALUE OF COMMON EQUITY 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).
DOCUMENTS INCORPORATED BY REFERENCE
Part of Form 10-K
Into Which Document
Description Is Incorporated
Portions of Annual Reports of the following companies for the
fiscal year ended December 31, 1997: 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. for 1998 Annual Meeting of Shareholders,
to be filed within 120 days after December 31, 1997 Part III
Portions of Information Statements of the following companies
for 1998 Annual Meeting of Shareholders, to be filed within
120 days after December 31, 1997: Part III
Appalachian Power Company
Ohio Power Company
This combined Form 10-K is separately filed by AEP Generating Company,
American Electric Power Company, Inc., Appalachian Power Company, Columbus
Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company
and Ohio Power Company. Information contained herein relating to any
individual registrant is filed by such registrant on its own behalf. Except
for American Electric Power Company, Inc., each registrant makes no
representation as to information relating to the other registrants.
EXPLANATORY NOTE
This Amendment No. 1 to Form 10-K for the fiscal year ended December 31,
1997, is filed in order to revise certain amounts reported in Item 1 under the
heading "Construction Expenditures--Environmental Expenditures".
PART I
Item 1. Business
General
AEP was incorporated under the laws of the State of New York in 1906 and
reorganized in 1925. It is a public utility holding company which owns,
directly or indirectly, all of the outstanding common stock of its domestic
electric utility subsidiaries and varying percentages of other subsidiaries.
Substantially all of the operating revenues of AEP and its subsidiaries are
derived from the furnishing of electric service. In addition, in recent years
AEP has been pursuing various unregulated business opportunities in the U.S.
and worldwide as discussed in New Business Development.
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 subsidiar-
ies 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. The electric utility subsidiaries of AEP have traditionally provided
electric service, consisting of generation, transmission and distribution, on
an integrated basis to their retail customers. As a result of the changing
nature of the electric business (see Competition and Business Change),
effective January 1, 1996, AEP's subsidiaries realigned into four functional
business units: Power Generation; Nuclear Generation; Energy Delivery; and
Corporate Development. In addition, the electric utility subsidiaries began
to do business as "American Electric Power." The legal and financial
structure of AEP and its subsidiaries, however, did not change.
At December 31, 1997, the subsidiaries of AEP had a total of 17,844
employees. AEP, as such, has no employees. The operating subsidiaries of AEP
are:
APCo (organized in Virginia in 1926) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 877,000 retail customers in the southwestern portion of
Virginia and southern West Virginia, and in supplying electric power at
wholesale to other electric utility companies and municipalities in
those states and in Tennessee. At December 31, 1997, APCo and its
wholly owned subsidiaries had 3,877 employees. Among the principal
industries served by APCo are coal mining, primary metals, chemicals and
textile mill products. In addition to its AEP System interconnections,
APCo also is interconnected with the following unaffiliated utility
companies: Carolina Power & Light Company, Duke Energy Corporation and
VEPCo. A comparatively small part of the properties and business of
APCo is located in the northeastern end of the Tennessee Valley. APCo
has several points of interconnection with TVA and has entered into
agreements with TVA under which APCo and TVA interchange and transfer
electric power over portions of their respective systems.
CSPCo (organized in Ohio in 1937, the earliest direct predecessor
company having been organized in 1883) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 621,000 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, 1997,
CSPCo had 1,802 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
interconnections, CSPCo also is interconnected with the following
unaffiliated utility companies: CG&E, DP&L and Ohio Edison Company.
I&M (organized in Indiana in 1925) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 549,000 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, 1997, I&M had 3,306 employees. Among
the principal industries served are primary metals, transportation
equipment, electrical and electronic machinery, fabricated metal
products, rubber and miscellaneous plastic products and chemicals and
allied products. Since 1975, I&M has leased and operated the assets of
the municipal system of the City of Fort Wayne, Indiana. In addition to
its AEP System interconnections, I&M also is interconnected with the
following unaffiliated utility companies: Central Illinois Public
Service Company, CG&E, Commonwealth Edison Company, Consumers Energy
Company, Illinois Power Company, Indianapolis Power & Light Company,
Louisville Gas and Electric Company, Northern Indiana Public Service
Company, PSI Energy Inc. and Richmond Power & Light Company.
KEPCo (organized in Kentucky in 1919) is engaged in the
generation, sale, purchase, transmission and distribution of electric
power to approximately 168,000 customers in an area in eastern Kentucky,
and in supplying electric power at wholesale to other utilities and
municipalities in Kentucky. At December 31, 1997, KEPCo had 731
employees. In addition to its AEP System interconnections, KEPCo also
is interconnected with the following unaffiliated utility companies:
Kentucky Utilities Company and East Kentucky Power Cooperative Inc.
KEPCo is also interconnected with TVA.
Kingsport Power Company (organized in Virginia in 1917) provides
electric service to approximately 43,000 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,
1997, Kingsport Power Company had 85 employees.
OPCo (organized in Ohio in 1907 and reincorporated in 1924) is
engaged in the generation, sale, purchase, transmission and distribution
of electric power to approximately 679,000 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, 1997, OPCo and its wholly
owned subsidiaries had 4,376 employees. Among the principal industries
served by OPCo are primary metals, rubber and plastic products, stone,
clay, glass and concrete products, petroleum refining and chemicals. In
addition to its AEP System interconnections, OPCo also is interconnected
with the following unaffiliated utility companies: CG&E, The Cleveland
Electric Illuminating Company, DP&L, Duquesne Light Company, Kentucky
Utilities Company, Monongahela Power Company, Ohio Edison Company, The
Toledo Edison Company and West Penn Power Company.
Wheeling Power Company (organized in West Virginia in 1883 and
reincorporated in 1911) provides electric service to approximately
43,000 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, 1997, Wheeling
Power Company had 94 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, information
systems, engineering, financial, legal, maintenance and other services at cost
to the AEP System companies. The executive officers of AEP and its public
utility subsidiaries are all employees of the Service Corporation.
Regulation
General
AEP and its subsidiaries are subject to the broad regulatory provisions
of PUHCA administered by the SEC. The public utility subsidiaries' retail
rates and certain other matters are subject to regulation by the public
utility commissions of the states in which they operate. Such subsidiaries
are also subject to regulation by the FERC under the Federal Power Act in
respect of rates for interstate sale at wholesale and transmission of electric
power, accounting and other matters and construction and operation of
hydroelectric projects. I&M is subject to regulation by the NRC under the
Atomic Energy Act of 1954, as amended, with respect to the operation of the
Cook Plant.
Possible Change to PUHCA
The provisions of PUHCA, administered by the SEC, regulate all aspects
of a registered holding company system, such as the AEP System. PUHCA
requires that the operations of a registered holding company system be limited
to a single integrated public utility system and such other businesses as are
incidental or necessary to the operations of the system. In addition, PUHCA
governs, among other things, financings, sales or acquisitions of assets and
intra-system transactions.
On June 20, 1995, the SEC released a report from its Division of
Investment Management recommending a conditional repeal of PUHCA, including
its limits on financing and on geographic and business diversification.
Specific federal authority, however, would be preserved over access to the
books and records of registered holding company systems, audit authority over
registered holding companies and their subsidiaries and oversight over affili-
ate transactions. This authority would be transferred to the FERC.
Legislation was introduced in Congress in 1997 that would repeal PUHCA and
transfer certain federal authority to the FERC as recommended in the SEC
report as part of broader legislation regarding changes in the electric
industry. It is expected that a number of bills contemplating the
restructuring of the electric utility industry will be introduced in the cur-
rent Congress. See Competition and Business Change. If PUHCA is repealed,
registered holding company systems, including the AEP System, will be able to
compete in the changing industry without the constraints of PUHCA. Management
of AEP believes that removal of these constraints would be beneficial to the
AEP System.
PUHCA and the rules and orders of the SEC currently require that
transactions between associated companies in a registered holding company
system be performed at cost with limited exceptions. Over the years, the AEP
System has developed numerous affiliated service, sales and construction
relationships and, in some cases, invested significant capital and developed
significant operations in reliance upon the ability to recover its full costs
under these provisions.
Legislation has been introduced in Congress to repeal PUHCA or modify
its provisions governing intra-system transactions. The effect of repeal or
amendment of PUHCA on AEP's intra-system transactions depends on whether the
assurance of full cost recovery is eliminated immediately or phased-in and
whether it is eliminated for all intra-system transactions or only some. If
the cost recovery assurance is eliminated immediately for all intra-system
transactions, it could have a material adverse effect on results of operations
and financial condition of AEP and OPCo.
Conflict of Regulation
Public utility subsidiaries of AEP can be subject to regulation of the
same subject matter by two or more jurisdictions. In such situations, it is
possible that the decisions of such regulatory bodies may conflict or that the
decision of one such body may affect the cost of providing service and so the
rates in another jurisdiction. In a case involving OPCo, the U.S. Court of
Appeals for the District of Columbia held that the determination of costs to
be charged to associated companies by the SEC under PUHCA precluded the FERC
from determining that such costs were unreasonable for ratemaking purposes.
The U.S. Supreme Court also has held that a state commission may not conclude
that a FERC approved wholesale power agreement is unreasonable for state
ratemaking purposes. Certain actions that would overturn these decisions or
otherwise affect the jurisdiction of the SEC and FERC are under consideration
by the U.S. Congress and these regulatory bodies. Such conflicts of
jurisdiction often result in litigation and, if resolved adversely to a public
utility subsidiary of AEP, could have a material adverse effect on the results
of operations or financial condition of such subsidiary or AEP.
Classes of Service
The principal classes of service from which the major electric utility
subsidiaries of AEP derive revenues and the amount of such revenues (from
kilowatt-hour sales) during the year ended December 31, 1997 are as follows:
<TABLE>
<CAPTION>
AEP
AEGCo APCo CSPCo I&M KEPCo OPCo System (a)
<S> <C> <C> <C> <C> <C> <C> <C>
(in thousands)
Retail
Residential
Without Electric Heating . . . . $ 0 $ 227,457 $ 317,341 $ 237,475 $ 40,395 $ 274,680 $1,117,740
With Electric Heating . . . . . 0 336,395 110,385 110,547 65,522 147,503 806,095
Total Residential . . . . . . . 0 563,852 427,726 348,022 105,917 422,183 1,923,835
Commercial . . . . . . . . . . . 0 281,939 381,368 264,031 56,680 263,212 1,286,452
Industrial . . . . . . . . . . . 0 382,056 147,367 332,218 94,645 618,548 1,637,058
Miscellaneous . . . . . . . . . 0 32,271 16,170 6,465 863 8,109 67,387
Total Retail . . . . . . . . . 0 1,260,118 972,631 950,736 260,105 1,312,052 4,914,732
Wholesale (sales for resale) . . 227,803 410,813 141,769 415,077 89,337 597,133 1,080,190
Total from KWH Sales . . . . . 227,803 1,670,931 1,114,400 1,365,813 349,442 1,909,185 5,994,922
Provision for Revenue Refunds . . 0 (250) 0 0 0 0 (250)
Total Net of Provision for
Revenue Refunds . . . . . . . . . 227,803 1,670,681 1,114,400 1,365,813 349,442 1,909,185 5,994,672
65 49,329 25,204 26,104 10,101 56,633 166,696
$227,868 $1,720,010 $1,139,604 $1,391,917 $359,543 $1,965,818 $6,161,368
</TABLE>
__________
(a) Includes revenues of other subsidiaries not shown and reflects elimination
of intercompany transactions.
Sale of Power
AEP's electric utility subsidiaries own or lease generating stations
with total generating capacity of 23,759 megawatts. See Item 2 for more
information regarding the generating stations. They operate their generating
plants as a single interconnected and coordinated electric utility system and
share the costs and benefits in the AEP System Power Pool. Most of the
electric power generated at these stations is sold, in combination with
transmission and distribution services, to retail customers of AEP's utility
subsidiaries in their service territories. These sales are made at rates that
are established by the public utility commissions of the state in which they
operate. See Rates and Regulation. Some of the electric power is sold at
wholesale to non-affiliated companies.
AEP System Power Pool
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. In addition, since 1995, APCo,
CSPCo, I&M, KEPCo and OPCo have been parties to the AEP System Interim
Allowance Agreement which provides, among other things, for the transfer of
SO2 Allowances associated with transactions under the Interconnection
Agreement.
The following table shows the net credits or (charges) allocated among
the parties under the Interconnection Agreement and Interim Allowance
Agreement during the years ended December 31, 1995, 1996 and 1997:
<TABLE>
<CAPTION>
1995 1996 1997(a)
(in thousands)
<S> <C> <C> <C>
APCo . . . . . . $(252,000) $(258,000) $(237,000)
CSPCo . . . . . . (143,000) (145,000) (138,000)
I&M . . . . . . . 118,000 121,000 67,000
KEPCo . . . . . . 23,000 2,000 20,000
OPCo . . . . . . 254,000 280,000 288,000
</TABLE>
__________
(a) Includes credits and charges from allowance transfers related to the
transactions.
Wholesale Sales of Power to Non-Affiliates
AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo also sell electric power on a
wholesale basis to non-affiliated electric utilities and power marketers.
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 net realization (revenue less operating, maintenance, fuel and
federal income tax expenses) of the various companies from such sales during
the years ended December 31, 1995, 1996 and 1997:
<TABLE>
<CAPTION>
1995(a) 1996(a) 1997(a)
(in thousands)
<S> <C> <C> <C>
AEGCo(b) . . . . $ 29,200 $ 26,300 $ 26,200
APCo(c) . . . . . 24,100 36,800 37,500
CSPCo(c) . . . . 12,000 18,100 18,300
I&M(c)(d) . . . . 34,700 43,000 42,400
KEPCo(c) . . . . 5,000 7,600 7,700
OPCo(c) . . . . . 20,200 30,200 30,200
Total System . $125,200 $162,000 $162,300
</TABLE>
__________
(a) Such sales do not include wholesale sales to full/partial requirement
customers of AEP System companies. See the discussion below.
(b) All amounts for AEGCo are from sales made pursuant to a long-term power
agreement. See AEGCo - Unit Power Agreements.
(c) All amounts, except for I&M, are from System sales which are allocated
among APCo, CSPCo, I&M, KEPCo and OPCo based upon member-load-ratio.
All System sales made in 1995, 1996 and 1997 were made on a short-term
basis, except that $22,500,000, $33,300,000 and $25,900,000
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 1995, 1996 and 1997
amounts for I&M include $21,000,000, $20,900,000 and $21,100,000 from a
long-term agreement to sell 250 megawatts of power scheduled to
terminate in 2009.
The AEP System has long-term system agreements to sell the following to
unaffiliated utilities: (1) 205 megawatts of electric power through August
2010; and (2) 50 megawatts of electric power through August 2001.
In addition to long-term and short-term sales, APCo, CSPCo, I&M, KEPCo
and OPCo serve unaffiliated wholesale customers that are full/partial
requirement customers. The aggregate maximum demand for these customers in
1997 was 611, 109, 451, 18 and 140 megawatts for APCo, CSPCo, I&M, KEPCo and
OPCo, respectively. Although the terms of the contracts with these customers
vary, they generally can be terminated by the customer upon one to four years'
notice. Since 1995, customers have given notices of termination, effective in
1998 and 1999, for 405, 63 and 131 megawatts for APCo, I&M and OPCo,
respectively.
Several wholesale customers, some of whom had previously given notice of
termination, have entered into long-term contracts, ranging from five to seven
years, with the AEP System. The expected demand under these contracts
aggregates approximately 450 megawatts.
In June 1993, certain municipal customers of APCo, who have since given
APCo notice to terminate their contracts in 1998, filed an application with
the FERC for transmission service in order to reduce by 50 megawatts the power
these customers then purchased under existing Electric Service Agreements
(ESAs) and to purchase power from a third party. APCo maintains that its
agreements with these customers are full-requirements contracts which preclude
the customers from purchasing power from third parties. On February 10, 1994,
the FERC issued an order finding that the ESAs are not full requirements
contracts and that the ESAs give these municipal wholesale customers the
option of substituting alternative sources of power for energy purchased from
APCo. On May 24, 1994, APCo appealed the February 10, 1994 order of the FERC
to the U.S. Court of Appeals for the District of Columbia Circuit. On July 1,
1994, the FERC ordered the requested transmission service and granted a
complaint filed by the municipal customers directing certain modifications to
the ESAs in order to accommodate their power purchases from the third party.
Following FERC's denial of APCo's requests for rehearing, on December 20,
1995, APCo appealed the July 1, 1994 orders to the U.S. Court of Appeals for
the District of Columbia. Effective August 1994, these municipal customers
reduced their purchases by 40 megawatts. Certain of these customers further
reduced their purchases by an additional 21 megawatts effective February 1996.
On December 17, 1996, the U.S. Court of Appeals reversed the FERC's order
directing APCo to provide transmission service and remanded the case to the
FERC, where it remains pending.
Transmission Services
AEP's electric utility subsidiaries own and operate transmission and
distribution lines and other facilities to deliver electric power. See Item 2
for more information regarding the transmission and distribution lines. AEP's
electric utility subsidiaries operate their transmission lines as a single
interconnected and coordinated system and share the cost and benefits in the
AEP System Transmission Pool. Most of the transmission and distribution
services is sold, in combination with electric power, to retail customers of
AEP's utility subsidiaries in their service territories. These sales are made
at rates that are established by the public utility commissions of the state
in which they operate. See Rates and Regulations. Some transmission services
also are separately sold to non-affiliated companies.
AEP System Transmission Pool
APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Transmission
Agreement, dated April 1, 1984, as amended (the Transmission Agreement),
defining how they share the costs associated with their relative ownership of
the extra-high-voltage transmission system (facilities rated 345 kv and above)
and certain facilities operated at lower voltages (138 kv and above). Like
the Interconnection Agreement, this sharing is based upon each company's
"member-load-ratio." See Sale of Power.
The following table shows the net credits or (charges) allocated among
the parties to the Transmission Agreement during the years ended December 31,
1995, 1996 and 1997:
<TABLE>
<CAPTION>
1995 1996 1997
(in thousands)
<S> <C> <C> <C>
APCo . . . . . . $( 5,400) $( 6,500) $( 8,400)
CSPCo . . . . . . ( 31,100) ( 30,600) ( 29,900)
I&M . . . . . . . 46,700 46,300 46,100
KEPCo . . . . . . 3,500 3,300 2,700
OPCo . . . . . . ( 13,700) ( 12,500) ( 10,500)
</TABLE>
Transmission Services for Non-Affiliates
APCo, CSPCo, I&M, KEPCo, OPCo and other System companies also provide
transmission services for non-affiliated companies. The following table shows
the revenues net of federal income tax expenses of the various companies from
such services during the years ended December 31, 1995, 1996 and 1997:
<TABLE>
<CAPTION>
1995 1996 1997
(in thousands)
<S> <C> <C> <C>
APCo . . . . . . $ 6,000 $ 13,800 $ 18,000
CSPCo . . . . . . 4,200 8,000 10,200
I&M . . . . . . . 4,800 7,700 10,500
KEPCo . . . . . . 1,200 2,800 3,900
OPCo . . . . . . 17,800 17,800 27,200
$ 34,000 $ 50,100 $ 69,800
</TABLE>
The AEP System has contracts with non-affiliated companies for
transmission of approximately 5,000 megawatts of electric power on an annual
or longer basis.
On April 24, 1996, the FERC issued orders 888 and 889. These orders
require each public utility that owns or controls interstate transmission
facilities to file an open access network and point-to-point transmission
tariff that offers services comparable to the utility's own uses of its trans-
mission system. The orders also require utilities to functionally unbundle
their services, by requiring them to use their own tariffs in making off-
system and third-party sales. As part of the orders, the FERC issued a pro-
forma tariff which reflects the Commission's views on the minimum non-price
terms and conditions for non-discriminatory transmission service. In
addition, the orders require all transmitting utilities to establish an Open
Access Same-time Information System ("OASIS") which electronically posts
transmission information such as available capacity and prices, and require
utilities to comply with Standards of Conduct which prohibit utilities' system
operators from providing non-public transmission information to the utility's
merchant employees. The orders also allow a utility to seek recovery of
certain prudently-incurred stranded costs that result from unbundled transmis-
sion service.
On July 9, 1996, the AEP System companies filed a tariff conforming with
the FERC's pro-forma transmission tariff, subject to the resolution of certain
pricing issues, which are still pending before FERC.
During 1996 and 1997 AEP engaged in discussions with several utilities
regarding the creation of an independent system operator to operate the
transmission system in the Midwestern region of the United States. On January
15, 1998, nine utilities or utility systems filed with the FERC a proposal to
form the Midwest Independent Transmission System Operator, Inc. ("Midwest
ISO"). AEP was not a participant in that filing, but supports the formation
of voluntary ISOs, and is currently examining its options, which include,
among others, participation in the Midwest ISO. See Competition and Business
Change - AEP Position on Competition.
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 945,000 kilowatts. On March
1, 1998, it is scheduled to increase to approximately 1,900,000 kilowatts.
The proceeds from the sale of power by OVEC 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 1997. The power agreement with DOE terminates on December
31, 2005, subject to early termination by DOE on not less than three years
notice. The power agreement among OVEC and the sponsoring companies expires
by its terms on March 12, 2006.
Buckeye
Contractual arrangements among OPCo, Buckeye and other investor-owned
electric utility companies in Ohio provide for the transmission and delivery,
over facilities of OPCo and of other investor-owned utility companies, of
power generated by the two units at the Cardinal Station owned by Buckeye and
back-up power to which Buckeye is entitled from OPCo under such contractual
arrangements, to facilities owned by 27 of the rural electric cooperatives
which operate in the State of Ohio at 306 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 16, 1997, was recorded at 1,178,460 kilowatts.
Certain Industrial Customers
Century Aluminum of West Virginia, Inc. (formerly 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. The power requirements of such plants presently
are approximately 357,000 kilowatts for Century and 537,000 kilowatts for
Ormet.
On October 3, 1996, the PUCO approved, with some exceptions, a contract
pursuant to which OPCo will continue to provide electric service to Ravenswood
for the period July 1, 1996 through July 31, 2003. On February 6, 1997, the
PUCO approved an amendment to the contract addressing these exceptions and the
amended contract is now in effect.
On November 14, 1996, the PUCO approved (1) an interim agreement
pursuant to which OPCo will continue to provide electric service to Ormet for
the period December 1, 1997 through December 31, 1999 and (2) a joint petition
with an electric cooperative to transfer the right to serve Ormet to the
electric cooperative after December 31, 1999. As part of the territorial
transfer, OPCo and Ormet entered into an agreement which contains penalties
and other provisions designed to avoid having OPCo provide involuntary back-up
power to Ormet. See Legal Proceedings for a discussion of litigation
involving Ormet.
AEGCo
Since its formation in 1982, AEGCo's business has consisted of the
ownership and financing of its 50% interest in the Rockport Plant and, since
1989, 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 pro-
portionate 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 asso-
ciated 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 Agree-
ment 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 to December
31, 2004.
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 32% of AEGCo's operating revenue in 1997 was derived from its
sales to VEPCo.
Capital Funds Agreement
AEGCo and AEP have entered into a capital funds agreement pursuant to
which, among other things, AEP has unconditionally agreed to make cash capital
contributions, or in certain 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) pro-
vide 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 and
revise the rules and responsibilities under which new generating capacity is
supplied; and substantial increases in construction costs and difficulties in
financing due to high costs of capital, uncertain capital markets, charter and
indenture limitations restricting conventional financing, and shortages of
cash for construction and other purposes.
Seasonality
Sales of electricity by the AEP System tend to increase and decrease
because of the use of electricity by residential and commercial customers for
cooling and heating and relative changes in temperature.
Franchises
The operating companies of the AEP System hold franchises to provide
electric service in various municipalities in their 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 and Business Change
General
The public utility subsidiaries of AEP, like other electric utilities,
have traditionally provided electric generation and energy delivery,
consisting of transmission and distribution services, as a single product to
their retail customers. FERC has required utilities to sell transmission
services separately from their other services. Proposals are being made that
would also require electric utilities to sell distribution services
separately. These proposals generally allow competition in the generation and
sale of electric power, but not in its transmission and distribution.
Competition in the generation and sale of electric power will require
resolution of complex issues, including who will pay for the unused generating
plant of, and other stranded costs incurred by, the utility when a customer
stops buying power from the utility; will all customers have access to the
benefits of competition; how will the rules of competition be established;
what will happen to conservation and other regulatory-imposed programs; how
will the reliability of the transmission system be ensured; and how will the
utility's obligation to serve be changed. As a result, it is not clear how or
when competition in generation and sale of electric power will be instituted.
However, if competition in generation and sale of electric power is
instituted, the public utility subsidiaries of AEP believe that they have a
favorable competitive position because of their relatively low costs. If
stranded costs are not recovered from customers, however, the public utility
subsidiaries of AEP, like all electric utilities, will be required by existing
accounting standards to recognize stranded investment losses.
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 and also to power marketers. The
Energy Policy Act of 1992 was designed, among other things, to foster
competition in the wholesale market (a) through amendments to PUHCA,
facilitating the ownership and operation of generating facilities by "exempt
wholesale generators" (which may include independent power producers as well
as affiliates of electric utilities) and (b) through amendments to the Federal
Power Act, authorizing the FERC under certain conditions to order utilities
which own transmission facilities to provide wholesale transmission services
for other utilities and entities generating electric power. The principal
factors in competing for such sales are price (including fuel costs),
availability of capacity and reliability of service. The public utility
subsidiaries of AEP believe that they maintain a favorable competitive
position on the basis of all of these factors. However, because of the
availability of capacity of other utilities and the lower fuel prices in
recent years, price competition has been, and is expected for the next few
years to be, particularly important.
FERC orders 888 and 889, issued in April 1996, provide that utilities
must functionally unbundle their transmission services, by requiring them to
use their own tariffs in making off-system and third-party sales. See
Transmission Services. The public utility subsidiaries of AEP have
functionally separated their wholesale power sales from their transmission
functions, as required by orders 888 and 889.
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 other energy
sources, 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 capability of customers to utilize sources of energy other than electric
power. With respect to self-generation, the public utility subsidiaries of
AEP believe that they maintain a favorable competitive position on the basis
of all of these factors. With respect to alternative sources of energy, the
public utility subsidiaries of AEP believe that the reliability of their
service and the limited ability of customers to substitute other cost-
effective sources for electric power place them in a favorable competitive
position, even though their prices may be higher than the costs of some other
sources of energy.
Significant changes in the global economy in recent years have led to
increased price competition for industrial companies in the United States,
including those served by the AEP System. Such industrial companies have
requested price reductions from their suppliers, including their suppliers of
electric power. In addition, industrial companies which are downsizing or
reorganizing often close a facility based upon its costs, which may include,
among other things, the cost of electric power. The public utility
subsidiaries of AEP cooperate with such customers to meet their business needs
through, for example, various off-peak or interruptible supply options and
believe that, as low cost suppliers of electric power, they should be less
likely to be materially adversely affected by this competition and may be
benefitted by attracting new industrial customers to their service
territories.
The legislatures and/or the regulatory commissions in many states are
considering or have adopted "retail customer choice" which, in general terms,
means the transmission by an electric utility of electric power generated by
an entity of the customer's choice over its transmission and distribution
system to a retail customer in such utility's service territory. A require-
ment 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 another electric utility, an independent power producer
or an intermediary, such as a power marketer. Although AEP's power generation
would have competitors under some of these proposals, its transmission and
distribution would not. If competition develops in retail power generation,
the public utility subsidiaries of AEP believe that they have a favorable
competitive position because of their relatively low costs.
Federal: Legislation to provide for retail competition among electric
energy suppliers has been introduced in both the U.S. Senate and House of
Representatives.
Indiana: In January 1998, S.B. 431 was introduced in the Indiana
Senate. The bill contained provisions allowing all customers the unrestricted
right to choose their generator of electricity by July 1, 2004. Under the
bill, customers could have chosen their power supplier after October 1, 1999,
by paying an access charge, while transmission and distribution services would
have continued to be regulated at the federal and state levels, respectively.
Prior to the full vote on the bill, S.B. 431 was amended on the Senate floor
to remove these restructuring provisions.
Michigan: In June 1995, the MPSC issued an order approving an
experimental five-year retail wheeling program and ordered Consumers Energy
Company (Consumers) and Detroit Edison Company (Detroit Edison), unaffiliated
utilities, to make retail delivery services available to a group of industrial
customers, in the amount of 60 megawatts and 90 megawatts, respectively. The
experiment, which commences when each utility needs new capacity, seeks to
determine whether a retail wheeling program best serves the public interest.
During the experiment, the MPSC will collect information regarding the effects
of retail wheeling. Consumers, Detroit Edison and other parties have appealed
the MPSC's order to the Michigan Supreme Court.
In January 1996, the Governor of Michigan endorsed a proposal of the
Michigan Jobs Commission to promote competition and customer choice in energy
and requested that the MPSC review the existing statutory and regulatory
framework governing Michigan utilities in light of increasing competition in
the utility industry. In December 1996, the MPSC staff issued a report on
electric industry restructuring which recommended a phase-in program from 1997
through 2004 of direct access to electricity suppliers applicable to all
customers. On June 5, 1997, the MPSC entered an order requiring electric
utilities (including I&M) to phase in retail open access for customers, with
full customer choice by 2002 (MPSC Order). Under the MPSC Order, customer
choice is phased in from 1997 through 2001, at the rate of 2.5% of each
utility's customer load per year, with all customers becoming eligible to
choose their electric supplier effective January 1, 2002. The MPSC Order
essentially adopted the December 1996 MPSC staff report that recommended full
recovery of stranded costs of utilities, including nuclear generating
investment, through the use of a transition charge applicable to customers
exercising choice. While concluding that securitization of stranded costs
would be feasible, the MPSC Order stated that legislative guidance is required
prior to the implementation of any securitization program.
As required by the MPSC Order, in July 1997, I&M filed a proposed open
access distribution tariff phasing-in customer choice for all customer
classes. The MPSC has not yet acted on I&M's filing. The MPSC has approved,
by orders dated January 14, 1998 and February 11, 1998, after contested
proceedings and with modifications, filings made by Consumers and Detroit
Edison. Detroit Edison, the Michigan Attorney General and other parties have
appealed the MPSC's orders to the Michigan Court of Appeals.
Ohio: On April 15, 1994, the Ohio Energy Strategy Task Force released
its final report. The report contained seven broad implementation strategies
along with 53 specific initiatives to be undertaken by government and the
private sector. One strategy recommended continuing to encourage competition
in the electric utility industry in a manner which maximizes benefits and
efficiencies for all customers. An initiative under this strategy recommends
facilitating informal roundtable discussions on issues concerning competition
in the electric utility industry and promoting increased competitive options
for Ohio businesses that do not unduly harm the interests of utility company
shareholders or ratepayers. The PUCO has begun such discussions. As a
result, on February 15, 1996, the PUCO adopted guidelines for interruptible
electric service, including a buy-through provision that will enable customers
to avoid being interrupted during utility capacity deficiencies by having the
utility purchase off-system replacement power for the customer. On February
28, 1997, CSPCo and OPCo implemented four new interruptible electric services
in conformance with the PUCO guidelines.
Also stemming from the roundtable discussions, on December 24, 1996, the
PUCO issued conjunctive electric service guidelines under which customers may
be aggregated for cost-of-service, rate design, rate eligibility and billing
purposes. Pursuant to a PUCO order, all Ohio electric utilities made
conjunctive electric service filings on March 31, 1997. Six unaffiliated
utilities have appealed these guidelines to the Ohio Supreme Court.
In February 1997, the Ohio General Assembly formed the Joint Committee
on Electric Utility Deregulation to study and report to the General Assembly
concerning deregulation of the electric utility industry in Ohio. The co-
chairs of the Joint Committee issued their report on January 6, 1998, which
described plans for introducing electric retail competition to Ohio consumers.
On February 18, 1998, the General Assembly's Joint Committee forwarded
its report to the House Speaker and Senate President. The report contains the
co-chairs report and the comments of other Committee members. The co-chairs
report proposes the establishment of a fully competitive marketplace by the
year 2000 and utility tax reform intended to place Ohio's utilities on a level
playing field with out-of-state suppliers.
One of the co-chairs has indicated her intention to introduce
legislation based on the co-chairs report's recommendations. However, there
are a number of other bills pending which could be used to enact deregulation.
Virginia: Pursuant to a resolution of the Virginia legislature, in
November 1997 the staff of the Virginia SCC provided its draft of a working
model of a restructured electric utility industry for Virginia to the joint
subcommittee of the legislature studying restructuring of the electric utility
industry.
Two major bills providing for the restructuring of the electric utility
industry were acted on by the Virginia General Assembly. One bill, introduced
by the chairman of the joint subcommittee, was "carried over" to serve as a
framework for study and debate over the balance of 1998, with oversight
provided by the joint subcommittee. The second bill, passed by the Virginia
General Assembly in March 1998, provides a general timetable for the
transition to retail competition by January 1, 2004, but leaves the details to
be decided in subsequent legislation.
West Virginia: In December 1996, the West Virginia PSC issued an order
initiating a general investigation into the restructuring of the regulated
electric industry. The Task Force established by the West Virginia PSC to
study electric industry restructuring issued its Initial Report in October
1997 and Supplemental Report on Recommended Legislation in January 1998. On
March 14, 1998, the West Virginia Legislature passed restructuring
legislation. If signed into law, the bill would authorize the West Virginia
PSC to proceed with the development of a plan for electric industry
restructuring in West Virginia, if restructuring is determined by the West
Virginia PSC to be in the public interest. Any plan developed and proposed by
the West Virginia PSC must be approved by the West Virginia Legislature before
such plan can be made effective.
AEP Position on Competition
In October 1995, AEP announced that it favored freedom for customers to
purchase electric power from anyone that they choose. Generation and sale of
electric power would be in the competitive marketplace. To facilitate
reliable, safe and efficient service, AEP supports creation of independent
system operators to operate the transmission system in a region of the United
States. In addition, AEP supports the evolution of regional power exchanges
which would establish a competitive marketplace for the sale of electric
power. Transmission and distribution would remain monopolies and subject to
regulation with respect to terms and price. Regulators would be able to
establish distribution service charges which would provide, as appropriate,
for recovery of stranded costs and regulatory assets. AEP's working model for
industry restructuring envisions a progressive transition to full customer
choice. Implementation of these measures would require legislative changes
and regulatory approvals.
Possible Strategic Responses
In response to the competitive forces and regulatory changes being faced
by AEP and its public utility subsidiaries, as discussed under this heading
and under Regulation, AEP and its public utility subsidiaries have from time
to time considered, and expect to continue to consider, various strategies
designed to enhance their competitive position and to increase their ability
to adapt to and anticipate changes in their utility business. These
strategies may include business combinations with other companies, internal
restructurings involving the complete or partial separation of their
generation, transmission and distribution businesses, acquisitions of related
or unrelated businesses, and additions to or dispositions of portions of their
franchised service territories. AEP and its public utility subsidiaries may
from time to time be engaged in preliminary discussions, either internally or
with third parties, regarding one or more of these potential strategies. No
assurances can be given as to whether any potential transaction of the type
described above may actually occur, or as to its ultimate effect on the
financial condition or competitive position of AEP and its public utility
subsidiaries.
New Business Development
AEP continues to consider new business opportunities, particularly those
which allow use of its expertise. These endeavors began in 1982 and are
conducted through AEP Resources, Inc. (Resources), AEP Resources Service
Company (formerly AEP Energy Services, Inc.) (AEPRESC) and AEP Energy
Services, Inc. (formerly AEP Energy Solutions, Inc.) (AEPES).
Resources' primary business is development of, and investment in, exempt
wholesale generators, foreign utility companies, qualifying cogeneration
facilities and other energy-related domestic and international investment
opportunities and projects.
On February 24, 1997, AEP and Public Service Company of Colorado (PSCo)
jointly agreed with the Board of Directors of Yorkshire Electricity Group plc
(Yorkshire Electricity) in the United Kingdom to make a cash tender offer (the
Tender Offer) for Yorkshire Electricity. The Tender Offer valued Yorkshire
Electricity at U.S. $2.4 billion. The Tender Offer was effected by Yorkshire
Holdings plc, a holding company owned by Yorkshire Power Group Limited, which
is equally owned and controlled by Resources and New Century International
Inc. (NCII), a wholly-owned subsidiary of PSCo, which is a wholly-owned
subsidiary of New Century Energies, Inc. Resources and NCII each contributed
U.S. $360 million toward the Tender Offer with the remaining U.S. $1.7 billion
funded through a non-recourse loan to Yorkshire Power Group Limited.
Yorkshire Power Group gained effective control of Yorkshire Electricity on
April 1, 1997. Yorkshire Electricity is an English independent regional
electricity company. It is principally engaged in the distribution of elec-
tricity to 2.1 million customers in its authorized service territory which is
comprised of 3,860 square miles and located centrally in the east coast of
England.
Resources' indirect subsidiary, AEP Pushan Power LDC, has a 70% interest
in Nanyang General Light Electric Co., Ltd. (Nanyang Electric), a joint
venture organized to develop and build two 125 megawatt coal-fired generating
units near Nanyang City in the Henan Province of The Peoples Republic of
China. Nanyang Electric was established in 1996 by AEP Pushan Power LDC,
Henan Electric Power Development Co. (15% interest) and Nanyang City Hengsheng
Energy Development Company Limited (formerly Nanyang Municipal Finance
Development Co.) (15% interest). Funding for the construction of the
generating units has commenced and will continue through completion which is
expected to occur by 1999. Resources' share of the total cost of the project
of $190 million is estimated to be approximately $110 million.
On October 2, 1997, Resources, DuPont and Conoco, the energy subsidiary
of DuPont, signed a letter of intent to form two jointly held venture
companies to provide energy management and capital to industrial and large
commercial customers. AEP Conoco Energy Capital will acquire and lease back
energy assets at industrial and large commercial facilities and provide future
capital for energy projects. AEP Conoco Energy Management Services will
provide energy management services. The ventures will initially acquire and
manage industrial energy assets valued at approximately $1 billion for DuPont
energy facilities at 33 U.S. industrial plants. Resources and DuPont will
each invest approximately $125 million in equity in the joint ventures with
the remainder to be financed through non-recourse debt.
AEPRESC offers engineering, construction, project management and other
consulting services for projects involving transmission, distribution or
generation of electric power both domestically and internationally.
AEP Communications, LLC (Communications) was formed in 1997 to pursue
opportunities in the telecommunications field. Communications is currently
constructing a fiber optic line that stretches between Kentucky, Ohio,
Virginia and West Virginia. This fiber optic line will be capable of
providing high speed telecommunications capacity to other telecommunications
companies. In addition to establishing and providing fiber optic services,
Communications also made investments in two companies engaged in providing
digital personal communications services, the West Virginia PCS Alliance, LC
and the Virginia PCS Alliance, LC.
AEP has received approval from the SEC under PUHCA to issue and sell
securities in an amount up to 50%, and is seeking approval to finance up to
100%, of its consolidated retained earnings (approximately $1,600,000,000 at
December 31, 1997), for investment in exempt wholesale generators and foreign
utility companies. Resources expects to investigate opportunities to develop
and invest in new, and invest in existing, generation projects worldwide.
The SEC adopted Rule 58, effective March 24, 1997, which permits AEP and
other registered holding companies to invest up to 15% of consolidated
capitalization in energy-related companies. AEPES, an energy-related company
under Rule 58, is authorized to engage in energy-related activities, including
marketing electricity, gas and other energy commodities.
In July 1996, AEP Power Marketing, Inc. (AEPPM), a wholly-owned
subsidiary of AEP, requested authority from FERC to market electric power at
wholesale at market-based rates. In September 1996, the FERC accepted the
filing, conditioned upon, among other things, the utility subsidiaries of AEP
refraining from (1) selling nonpower goods or services to any affiliate at a
price below its cost or market price, whichever is higher, and (2) purchasing
nonpower goods or services from any affiliate at a price above market price.
AEPPM has requested FERC to clarify that the applicability of this condition
relates only to transactions between AEP utility subsidiaries and AEPPM.
AEPPM is inactive pending FERC's decision.
These continuing efforts to invest in and develop new business
opportunities offer the potential of earning returns which may exceed those of
rate-regulated operations. However, they also involve a higher degree of risk
which must be carefully considered and assessed. AEP may make substantial
investments in these and other new businesses.
Proposed AEP-CSW Merger
AEP and CSW entered into an Agreement and Plan of Merger, dated as of
December 21, 1997, pursuant to which CSW would, on the closing date, merge
with and into a wholly owned merger subsidiary of AEP with CSW being the
surviving corporation. As a result of the merger, each outstanding share of
common stock, par value $3.50 per share, of CSW (other than shares owned by
AEP or CSW) shall be converted into the right to receive 0.6 of a share of
common stock, par value $6.50 per share, of AEP. Based on the price of AEP's
common stock on December 19, 1997, the transaction would be valued at $6.6
billion. The combined company will be named American Electric Power Company,
Inc. and will be based in Columbus, Ohio.
Consummation of the merger is subject to certain conditions, including
receipt of approval of the merger and the transactions contemplated thereby by
the shareholders of AEP and CSW and the receipt of the required regulatory
approvals. Assuming the receipt of all required approvals, completion of the
merger is anticipated to occur in the first half of 1999.
CSW is a global, diversified public utility holding company based in
Dallas, Texas. CSW owns four domestic electric utility subsidiaries serving
1.7 million customers in portions of the states of Texas, Oklahoma, Louisiana
and Arkansas and a regional electricity company in the United Kingdom. CSW
owns other international energy operations and non-utility subsidiaries
involved in energy-related investments, telecommunications, energy efficiency
services and financial transactions.
Construction Program
New Generation
The AEP System companies are continuously involved in an assessment of
the adequacy of its generation, transmission, distribution and other
facilities necessary to provide for the reliable supply of electric power and
energy to its customers. In this assessment and planning process, assumptions
are continually being reviewed as new information becomes available, and
assessments and plans are modified accordingly, as appropriate. Thus, system
reinforcement plans are subject to change, particularly with the anticipated
restructuring of the electric utility industry and the move to increasing
competition in the marketplace. See Competition and Business Change.
Committed or anticipated capability changes to the AEP System generation
resources through the year 2001 include: a purchase from an independent power
producer's hydro project with an expected capacity value of 28 megawatts,
reratings of several existing AEP System generating units, and the expiration
of the Rockport Unit 1 sale of 455 megawatts to VEPCo on December 31, 1999
(see AEGCo). Beyond these changes, there are no specific commitments for
additions of new generation resources on the AEP System. In this regard, the
most recent resource plan filed by AEP's electric utility subsidiaries with
various state commissions indicates no need for new generation resources until
beyond the year 2002. When the time for commitment to additional generation
resources approaches, all means for adding such resources, including self-
build and external resource options, will be considered. However, given the
restructuring that is expected to take place in the industry, the need of
AEP's operating companies for any additional generation resources in the fore-
seeable future is highly uncertain.
Proposed Transmission Facilities
APCo: On September 30, 1997, APCo refiled applications in Virginia and
West Virginia for certificates to build the Wyoming-Cloverdale 765,000-volt
line. The preferred route for this line is approximately 132 miles in length,
connecting APCo's Wyoming Station in southern West Virginia to APCo's
Cloverdale Station near Roanoke, Virginia. APCo's estimated cost is
$263,300,000.
APCo announced this project in 1990. Since then it has been in the
process of trying to obtain federal permits and state certificates. At the
federal level, the U.S. Forest Service (Forest Service) is directing the
preparation of an Environmental Impact Statement (EIS), which is required
prior to granting permits for crossing lands under federal jurisdiction.
Permits are needed from the (i) Forest Service to cross federal forests, (ii)
Army Corps of Engineers to cross the New River and a watershed near the
Wyoming Station, and (iii) National Park Service or Forest Service to cross
the Appalachian National Scenic Trail.
In June 1996, the Forest Service released a Draft EIS and preliminarily
identified a "No Action Alternative" as its preferred alternative. If this
alternative were incorporated into the Final EIS, APCo would not be authorized
to cross federal forests administered by the Forest Service. The Forest
Service stated that it would not prepare the Final EIS until after Virginia
and West Virginia determined need and routing issues.
In an interim order issued in 1995, the Virginia SCC found, based on the
record before it, that there is a compelling need for additional electric
capacity to serve APCo's Central and Eastern regions and that the proposed
transmission line may be the best possible solution. In December 1996, APCo
filed a report with the Virginia SCC reviewing the need for the project.
Based on that review and after considering all other feasible alternatives,
APCo concluded that the need for reinforcement of the transmission system
serving its Central and Eastern areas remains compelling and the proposed
project is the best alternative for addressing the need.
Procedural schedules have been issued in each state. In Virginia, five
public hearings will be held in March and April and an evidentiary hearing
will be held in July. In West Virginia, three public meetings will be held in
early May, followed by an evidentiary hearing. By statute, the West Virginia
PSC has 400 days from the filing date, or November 4, 1998, to issue the
certificate. If it fails to act, APCo receives the certificate automatically.
Virginia does not have such a time constraint.
If Virginia and West Virginia issue the required certificates, APCo will
cooperate with the Forest Service to complete the EIS process and obtain the
federal permits. Management estimates that the project cannot be completed
before the winter of 2002-2003. However, given the findings in the Draft EIS,
APCo cannot presently predict the schedule for completion of the state and
federal permitting process.
APCo and KEPCo: APCo and KEPCo have announced an improvement plan to be
implemented during a four-year period (1996-1999) to reinforce their 138,000-
volt transmission system. Included in this plan is a new transmission line to
link KEPCo's Big Sandy Plant to communities in eastern Kentucky. APCo's and
KEPCo's estimated project costs are $5,800,000 and $81,600,000, respectively.
The KPSC approved the project in its order dated June 11, 1996. Construction
commenced in late 1996.
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 1995, 1996 and 1997 and their current estimate of 1998
construction expenditures, in each case including AFUDC but excluding nuclear
fuel and other assets acquired under leases. The construction expenditures
for the years 1995-1997 were, and it is anticipated that the estimated
construction expenditures for 1998 will be, approximately:
<TABLE>
<CAPTION>
1995 1996 1997 1998
Actual Actual Actual Estimate
<S> <C> <C> <C> <C>
(in thousands)
AEGCo . . . . . . . . . . . $ 4,000 $ 2,200 $ 3,900 $ 4,200
APCo . . . . . . . . . . . 217,600 192,900 218,100 205,600
CSPCo . . . . . . . . . . . 99,500 93,600 108,900 117,900
I&M . . . . . . . . . . . . 113,000 90,500 123,400 169,100
KEPCo . . . . . . . . . . . 39,300 75,800 66,700 53,800
OPCo . . . . . . . . . . . 116,900 113,800 172,700 187,700
AEP System (a) . . . . .
$601,200 $578,000 $762,000 $847,000
</TABLE>
__________
(a) Includes expenditures of other subsidiaries not shown.
Reference is made to the footnotes to the financial statements entitled
Commitments and Contingencies incorporated by reference in Item 8, for further
information with respect to the construction plans of AEP and its operating
subsidiaries for the next three years.
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, en-
vironmental requirements and other factors. 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 estimated capital requirements for
the System's construction program.
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.
Environmental Expenditures: Expenditures related to compliance with air
and water quality standards, included in the gross additions to plant of the
System, during 1995, 1996 and 1997 and the current estimate for 1998 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
have been or may be adopted.
<TABLE>
<CAPTION>
1995 1996 1997 1998
Actual Actual Actual Estimate
<S> <C> <C> <C> <C>
(in thousands)
AEGCo . . . . . . . . . . . $ 0 $ 0 $ 0 $ 0
APCo . . . . . . . . . . . 7,800 10,500 9,100 11,500
CSPCo . . . . . . . . . . . 10,000 1,800 1,300 4,500
I&M . . . . . . . . . . . . 1,400 0 100 3,200
KEPCo . . . . . . . . . . . 600 100 1,300 4,000
OPCo . . . . . . . . . . . 3,100 1,600 11,800 32,800
AEP System . . . . . . .
$ 22,900 $ 14,000 $ 23,600 $ 56,000
</TABLE>
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. It has been the practice of AEP, in turn,
to finance cash capital contributions to the common stock equities of its
subsidiaries by issuing unsecured short-term debt, principally commercial
paper, and then to sell additional shares of Common Stock of AEP for the pur-
pose of retiring the short-term debt previously incurred. In 1997, AEP issued
approximately 1,755,000 shares of Common Stock pursuant to its Dividend
Reinvestment and Stock Purchase Plan. Although prevailing interest costs of
short-term bank debt and commercial paper generally have been lower than
prevailing interest costs of long-term debt securities, whenever interest
costs of short-term debt exceed costs of long-term debt, the companies might
be adversely affected by reliance on the use of short-term debt to finance
their construction and other capital requirements.
During the period 1995-1997, external funds from financings and capital
contributions by AEP amounted, with respect to APCo and KEPCo, to approximate-
ly 28% and 70%, 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, CSPCo, I&M and OPCo exceeded
the amount of funds from financings and capital contributions by AEP.
The ability of AEP and its 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 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, 1998, and the respective amounts of short-term debt outstanding on
that date, on a corporate basis, are shown in the following tabulation:
<TABLE>
<CAPTION>
Total AEP
Short-Term Debt AEP AEGCo APCo CSPCo I&M KEPCo OPCo System(a)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
(in millions)
Amount authorized . . . . . . . . . . . $150 $ 80 $250 $175 $175 $150 $250 $1,230
Amount outstanding:
Notes payable . . . . . . . . . . . . $ 24 $ 12 $ 34 $ 4 $ 57 -- $ 11 $ 199
Commercial paper . . . . . . . . . . 29 -- 96 63 63 37 68 356
$ 53 $ 12 $130 $ 67 $120 $ 37 $ 79 $ 555
</TABLE>
__________
(a) Includes short-term debt of other subsidiaries not shown.
Reference is made to the footnotes to the financial statements
incorporated by reference in Item 8 for further information with respect to
unused short-term bank lines of credit.
In order to issue additional first mortgage bonds 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 and charters.
The most restrictive of these provisions in each instance generally requires
(1) for the issuance of first mortgage bonds 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 (2) for the issuance of additional preferred stock by APCo,
I&M and OPCo, a minimum, after income tax, gross income coverage of one and
one-half times pro forma annual interest charges and preferred stock
dividends, in each case for a period of twelve consecutive calendar months
within the fifteen calendar months immediately preceding the proposed new
issue. In computing such coverages, the companies include as a component of
earnings revenues collected subject to refund (where applicable) and, to the
extent not limited by the instrument under which the computation is made,
AFUDC, including amounts positioned and classified as an allowance for
borrowed funds used during construction. These coverage provisions have from
time to time restricted the ability of one or more of the above subsidiaries
of AEP to issue senior securities.
The respective mortgage and preferred stock coverages of APCo, CSPCo,
I&M, KEPCo and OPCo under their respective 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, with respect
to the preferred stock coverages, that the respective short-term debt of the
companies at those dates were to remain outstanding for a twelve-month period
at the respective rates of interest prevailing at those dates, were at least
those stated in the following table:
<TABLE>
<CAPTION>
December 31,
1995 1996 1997
<S> <C> <C> <C>
APCo
Mortgage coverage . . . . . . . 3.47 3.98 3.72
Preferred stock coverage . . . 1.78 1.99 1.92
CSPCo
Mortgage coverage . . . . . . . 3.90 4.44 4.95
I&M
Mortgage coverage . . . . . . . 6.25 6.66 7.57
Preferred stock coverage . . . 2.63 3.07 2.88
KEPCo
Mortgage coverage . . . . . . . 2.86 3.22 4.23
OPCo
Mortgage coverage . . . . . . . 6.17 8.27 9.74
Preferred stock coverage . . . 3.04 3.63 3.67
</TABLE>
Although certain other subsidiaries of AEP either are not subject to any
coverage restrictions or are not subject to restrictions as constraining as
those to which APCo, CSPCo, I&M, KEPCo and OPCo are subject, their ability to
finance substantial portions of their construction programs may be subject to
market limitations and other constraints unless other assurances are
furnished.
AEP believes that the ability of some of its subsidiaries to issue
short- and long-term debt securities and preferred stock in the amounts
required to finance their business may depend upon the timely approval of rate
increase applications. If one or more of the 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 curtailment of construction and
other outlays or the use of alternative financing arrangements, if available,
which may be more costly.
AEP's subsidiaries have also utilized, and expect to continue to
utilize, additional financing arrangements, such as leasing arrangements,
including the leasing of utility assets, coal mining and transportation
equipment and facilities and nuclear fuel. Pollution control revenue bonds
have been used in the past and may be used in the future in connection with
the construction of pollution control facilities; however, Federal tax law has
limited the utilization of this type of financing except for purposes of
certain financing of solid waste disposal facilities and of certain refunding
of outstanding pollution control revenue bonds issued before August 16, 1986.
Rates and Regulation
General
The rates charged by the electric utility subsidiaries of AEP are
approved by the FERC or one of the state utility commissions as applicable.
The FERC regulates wholesale rates and the state commissions regulate retail
rates. In recent years the number of rate increase applications filed by the
operating subsidiaries of AEP with their respective state commissions and the
FERC has decreased. Under current rate regulation, if increases in operating,
construction and capital costs exceed increases in revenues resulting from
previously granted rate increases and increased customer demand, then it may
be appropriate for certain of AEP's electric utility subsidiaries to file rate
increase applications in the future.
Generally the rates of AEP's operating subsidiaries are determined based
upon the cost of providing service including a reasonable return on
investment. Certain states served by the AEP System allow alternative forms
of rate regulation in addition to the traditional cost-of-service approach.
The IURC may approve alternative regulatory plans which could include setting
customer rates based on market or average prices, price caps, index-based
prices and prices based on performance and efficiency. The Virginia SCC may
approve (i) special rates, contracts or incentives to individual customers or
classes of customers and (ii) alternative forms of regulation including, but
not limited to, the use of price regulation, ranges of authorized returns,
categories of services and price indexing.
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. See Competition and Business
Change.
APCo
FERC: On February 14, 1992, APCo filed with the FERC applications for
an increase in its wholesale rates to Kingsport Power Company and non-
affiliated customers in the amounts of approximately $3,933,000 and
$4,759,000, respectively. APCo began collecting the rate increases, subject
to refund, on September 15, 1992. In addition, the Financial Accounting
Standards Board has issued Statement of Financial Accounting Standards No.
106, Employers' Accounting for Postretirement Benefits Other Than Pensions
(SFAS 106), which requires employers, beginning in 1993, to accrue for the
costs of retiree benefits other than pensions. These rates include the higher
level of SFAS 106 costs. On November 9, 1993, the administrative law judge
issued an initial decision recommending, among other things, the higher level
of postretirement benefits other than pensions under SFAS 106. FERC action on
APCo's applications is pending.
Virginia: In June 1997, APCo filed an application with the Virginia SCC
for approval of an alternative regulatory plan (Plan) and proposed, among
other things, an increase of $30,500,000 in base rates on an annual basis to
be effective July 13, 1997. APCo's Plan would institute a moratorium period
during which no changes from the rate levels (including APCo's current 1.482
cents/kwh fuel factor) proposed by APCo would be made prior to January 1,
2001. In addition, the Plan includes a sharing of earnings above certain
levels between APCo and its customers, and acceleration of the recovery of
generation-related regulatory assets. On July 10, 1997, the Virginia SCC
issued an order suspending implementation of the proposed rates until November
11, 1997 when these rates were placed into effect subject to refund. A
hearing has been scheduled for July 6, 1998 to consider APCo's proposal.
West Virginia: On December 27, 1996, the West Virginia PSC approved a
settlement agreement among APCo and other parties. In accordance with that
agreement, the West Virginia PSC reduced APCo's base rates and Expanded Net
Energy Cost (ENEC) rates by $5,000,000 and $28,000,000, respectively, on a
one-time annual basis, effective November 1, 1996. Under the terms of the
agreement, APCo's rates would not increase prior to January 1, 2000 and,
through this date, ENEC cost variances will be subject to deferred accounting
and a cumulative ENEC recovery balance will be maintained. Regardless of the
actual cumulative ENEC recovery balance at December 31, 1999, ratepayers will
not be responsible for any cumulative underrecovery and any cumulative overre-
coveries will be treated in a manner to be determined by the West Virginia
PSC, except that ENEC overrecoveries during each calendar year through
December 31, 1999, in excess of $10,000,000 per period, will be accumulated
and shared equally between APCo and its ratepayers.
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%).
From the in-service date of March 1991 until rates went into effect in
May 1992, deferred carrying charges of $43,000,000 were recorded on the Zimmer
Plant investment. Recovery of the deferred carrying charges will be sought in
the next PUCO base rate proceeding in accordance with the PUCO accounting
order that authorized the deferral.
I&M
On September 9, 1997, I&M filed a petition with the IURC requesting
approval of accounting authority to increase nuclear decommissioning expense
in an amount equal to the expiring Rockport phase-in plan amortization
expense. The petition would increase I&M's Indiana jurisdictional nuclear
decommissioning provision by $10,900,000 annually, effective September 1,
1997. A hearing on I&M's petition was held on February 3, 1998, and an order
is awaited from the IURC. I&M has recorded the requested increased nuclear
decommissioning expense provision, but has not deposited the increased
provision into its nuclear decommissioning trust funds pending IURC approval.
OPCo
Under the terms of a stipulation agreement approved by the PUCO in
November 1992, beginning December 1, 1994, the cost of coal burned at the
Gavin Plant is subject to a 15-year predetermined price of $1.575 per million
Btus with quarterly escalation adjustments. A 1995 PUCO-approved settlement
agreement fixes the EFC factor at 1.465 cents per kwh for the period June 1995
through November 1998. After the first to occur of either full recovery of
these costs or November 2009, the price that OPCo can recover for coal from
its affiliated Meigs mine which supplies the Gavin Plant will be limited to
the lower of cost or the then-current market price. The agreements provide
OPCo with the opportunity to recover any operating losses incurred under the
predetermined or fixed price, as well as its investment in, and liabilities
and closing costs associated with, its affiliated mining operations
attributable to its Ohio jurisdiction, to the extent the actual cost of coal
burned at the Gavin Plant is below the predetermined price.
Based on the estimated future cost of coal burned at Gavin Plant,
management believes that the Ohio jurisdictional portion of the investment in,
and liabilities and closing costs of, the affiliated mining operations,
including deferred amounts, will be recovered under the terms of the pre-
determined price agreement. Management intends to seek from non-Ohio
jurisdictional ratepayers recovery of the non-Ohio jurisdictional portion of
the investment in, and the liabilities and closing costs of, OPCo's Meigs,
Muskingum and Windsor mines, but there can be no assurance that such recovery
will be approved. The non-Ohio jurisdictional portion of shutdown costs for
these mines, which includes the investment in the mines, leased asset buy-
outs, reclamation costs and employee benefits, is estimated to be
approximately $53,000,000 for Meigs, $37,000,000 for Muskingum and $12,000,000
for Windsor, after tax at December 31, 1997.
OPCo's Muskingum and Windsor mines may have to close by January 2000 as
a result of compliance by the Muskingum River Plant and Cardinal Unit 1 with
the Phase II requirements of the Clean Air Act Amendments of 1990 (see
Environmental and Other Matters - Air Pollution Control - Acid Rain). The
Muskingum and Windsor mines supply coal to Muskingum River Plant and Cardinal
Plant, respectively. The Muskingum and/or Windsor mines could close prior to
January 2000 depending on the economics of continued operation under the terms
of the 1995 settlement agreement. Unless future shutdown costs and/or the
cost of coal production of OPCo's Meigs, Muskingum and Windsor mines can be
recovered, AEP's and OPCo's results of operations would be adversely affected.
Management anticipates closing the Muskingum mine in 1999, Windsor mine
in 2000 and Meigs mine in 2001. Management, however, in making such a
determination, will consider certain factors, including the competitiveness of
the price of the coal extracted from the mine and the value of SO2 Allowances
after the accelerated amortization of mine closure and the recovery of other
costs.
In November 1992, the municipal wholesale customers of OPCo filed a
complaint with the SEC requesting an investigation of the sale of the Martinka
mining operation to an unaffiliated company and an investigation into the
pricing of OPCo's affiliated coal purchases back to 1986. OPCo has filed a
response with the SEC seeking to dismiss this complaint. These customers also
sought to intervene in three proceedings before the SEC. In September 1996,
the SEC denied two requests to intervene, but has not ruled on the complaint.
Fuel Supply
The following table shows the sources of power generated by the AEP
System:
<TABLE>
<CAPTION>
1993 1994 1995 1996 1997
<S> <C> <C> <C> <C> <C>
Coal . . . . . . . . . . . 86% 91% 88% 87% 92%
Nuclear . . . . . . . . . . 13% 8% 11% 12% 7%
Hydroelectric and other . . 1% 1% 1% 1% 1%
</TABLE>
Variations in the generation of nuclear power are primarily related to
refueling outages and, in 1997, the shutdown of the Cook Plant to respond to
issues raised by the NRC. See Cook Plant Shutdown.
Coal
The Clean Air Act Amendments of 1990 provide for the issuance of annual
allowance allocations covering sulfur dioxide emissions at levels below
historic emission levels for many coal-fired generating units of the AEP
System. Phase I of this program began in 1995 and Phase II begins in 2000,
with both phases requiring significant changes in coal supplies and suppliers.
The full extent of such changes, particularly in regard to Phase II, however,
has not been determined. See Environmental and Other Matters - Air Pollution
Control - Acid Rain 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 power to
other regions or systems experiencing fuel shortages, and to rate-making
principles by which such electric utilities would be compensated. In
addition, the Federal Government is authorized, under prescribed conditions,
to allocate coal and to require the transportation thereof, for the use of
power plants or major fuel-burning installations.
System companies have developed programs to conserve coal supplies at
System plants which involve, on a progressive basis, limitations on sales of
power and energy to neighboring utilities, appeals to customers for voluntary
limitations of electric usage to essential needs, curtailment of sales to
certain industrial customers, voltage reductions and, finally, mandatory
reductions in cases where current coal supplies fall below minimum levels.
Such programs have been filed and reviewed with officials of Federal and state
agencies and, in some cases, 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
3,460 coal hopper cars to be used in unit train movements, as well as 13
towboats, 307 jumbo barges and 183 standard barges. Subsidiaries of AEP also
own or lease coal transfer facilities at various other locations.
The System generating companies procure coal from coal reserves which
are owned or mined by subsidiaries of AEP, and through purchases pursuant to
long-term contracts, or on a spot purchase basis, from unaffiliated producers.
The following table shows the amount of coal delivered to the AEP System
during the past five years, the proportion of such coal which was obtained
either from coal-mining subsidiaries, from unaffiliated suppliers under long-
term contracts or through spot or short-term purchases, and the average
delivered price of spot coal purchased by System companies:
<TABLE>
<CAPTION>
1993 1994 1995 1996 1997
<S> <C> <C> <C> <C> <C>
Total coal delivered to
AEP operated plants (thousands of tons) . . . . . 40,561 49,024 46,867 51,030 54,292
Sources (percentage):
Subsidiaries . . . . . . . . . . . . . . . . . . . 20% 15% 14% 13% 14%
Long-term contracts . . . . . . . . . . . . . . . 66% 65% 75% 71% 66%
Spot or short-term purchases . . . . . . . . . . . 14% 20% 11% 16% 20%
Average price per ton of spot-purchased coal . . . $23.55 $23.00 $25.15 $23.85 $24.38
</TABLE>
The average cost of coal consumed during the past five years by all AEP
System companies, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo is shown in the
following tables:
<TABLE>
<CAPTION>
1993 1994 1995 1996 1997
<S> <C> <C> <C> <C> <C>
Dollars per ton
AEP System Companies . . . . . 33.57 33.95 32.52 31.70 31.77
AEGCo . . . . . . . . . . . . . 17.74 18.59 18.80 18.22 19.30
APCo . . . . . . . . . . . . . 42.65 39.89 38.86 37.60 36.09
CSPCo . . . . . . . . . . . . . 33.87 32.80 33.23 31.70 31.69
I&M . . . . . . . . . . . . . . 23.80 22.85 23.25 22.99 23.68
KEPCo . . . . . . . . . . . . . 27.08 26.83 26.91 27.25 26.76
OPCo . . . . . . . . . . . . . 38.12 41.10 37.58 35.96 36.00
Cost per Million Btu's
AEP System Companies . . . . . 150.89 152.41 145.26 140.48 140.23
AEGCo . . . . . . . . . . . . . 107.71 112.06 112.87 109.25 115.21
APCo . . . . . . . . . . . . . 173.32 161.37 156.96 152.54 146.54
CSPCo . . . . . . . . . . . . . 143.66 140.45 140.79 134.60 134.44
I&M . . . . . . . . . . . . . . 129.39 123.62 125.50 121.16 123.36
KEPCo . . . . . . . . . . . . . 113.90 113.40 114.77 114.42 110.37
OPCo . . . . . . . . . . . . . 161.25 173.51 157.62 151.55 151.66
</TABLE>
The coal supplies at AEP System plants vary from time to time depending
on various factors, including customers' usage of electric power, space
limitations, the rate of consumption at particular plants, labor unrest and
weather conditions which may interrupt deliveries. At December 31, 1997, the
System's coal inventory was approximately 43 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 1997 of the
coal-fired generating units of AEP's principal electric utility subsidiaries,
coal requirements of these units over the remainder of their useful lives and
the average sulfur content of coal delivered in 1997 to these units.
Reference is made to Environmental and Other Matters for information
concerning current emissions limitations in the AEP System's various
jurisdictions and the effects of the Clean Air Act Amendments.
<TABLE>
<CAPTION>
Average Sulfur Content
of Delivered Coal
Estimated Require-
Total Consumption ments for Remainder
During 1997 of Useful Lives Pounds of SO2
(In Thousands of Tons) (In Millions of Tons) By Weight Per Million Btu's
<S> <C> <C> <C> <C>
AEGCo(a) . . . . 5,043 251 0.3% 0.7
APCo . . . . . . 11,682 446 0.8% 1.3
CSPCo . . . . . . 6,082(b) 236(b) 2.8% 4.7
I&M(c) . . . . . 7,304 294 0.7% 1.4
KEPCo . . . . . . 2,909 91 1.3% 2.1
OPCo . . . . . . 20,493 642 2.1% 3.5
</TABLE>
(a) Reflects AEGCo's 50% interest in the Rockport Plant.
(b) Includes coal requirements for CSPCo's interest in Beckjord, Stuart and
Zimmer Plants.
(c) Includes I&M's 50% interest in the Rockport Plant.
AEGCo: See Fuel Supply - I&M for a discussion of the coal supply for
the Rockport Plant.
APCo: Substantially all of the coal consumed at APCo's generating
plants is obtained from unaffiliated suppliers under long-term contracts
and/or on a spot purchase basis.
The average sulfur content by weight of the coal received by APCo at its
generating stations approximated 0.8% during 1997, whereas the maximum sulfur
content permitted, for emission standard purposes, for existing plants in the
regions in which APCo's generating stations are located ranged between 0.78%
and 2% by weight depending in some circumstances on the calorific value of the
coal which can be obtained for some generating stations.
CSPCo: CSPCo has coal supply agreements with unaffiliated suppliers for
the delivery of approximately 3,400,000 tons per year through 1998. Some of
this coal is washed to improve its quality and consistency for use principally
at Unit 4 of the Conesville Plant.
CSPCo has been informed by CG&E and DP&L that, with respect to the CCD
Group units partly owned but not operated by CSPCo, sufficient coal has been
contracted for or is believed to be available for the approximate lives of the
respective units operated by them. Under the terms of the operating
agreements with respect to CCD Group units, each operating company is
contractually responsible for obtaining the needed fuel.
I&M: I&M has two coal supply agreements with unaffiliated suppliers
pursuant to which the suppliers are delivering low sulfur coal from surface
mines in Wyoming, principally for consumption by the Rockport Plant. Under
these agreements, the suppliers will sell to I&M, for consumption by I&M at
the Rockport Plant or consignment to other System companies, coal with an
average sulfur content not exceeding 1.2 pounds of sulfur dioxide per million
Btu's of heat input. One contract with remaining deliveries of 52,010,543
tons expires on December 31, 2014 and another contract with remaining deliv-
eries of 43,395,000 tons expires on December 31, 2004.
All of the coal consumed at I&M's Tanners Creek Plant is obtained from
unaffiliated suppliers under long-term contracts and/or on a spot purchase
basis.
KEPCo: Substantially all of the coal consumed at KEPCo's Big Sandy
Plant is obtained from unaffiliated suppliers under long-term contracts and/or
on a spot purchase basis. KEPCo has coal supply agreements with unaffiliated
suppliers pursuant to which KEPCo will receive approximately 2,300,000 tons of
coal in 1998. To the extent that KEPCo has additional coal requirements, it
may purchase coal from the spot market and/or suppliers under contract to
supply other System companies.
OPCo: The coal consumed at OPCo's generating plants is obtained from
both affiliated and unaffiliated suppliers. The coal obtained from
unaffiliated suppliers is purchased under long-term contracts and/or on a spot
purchase basis.
OPCo and certain of its coal-mining subsidiaries own or control coal
reserves in the State of Ohio which contain approximately 200,000,000 tons of
clean recoverable coal, which ranges in sulfur content between 3.4% and 4.5%
sulfur by weight (weighted average, 3.8%), which can be recovered based upon
existing mining plans and projections and employing current mining practices
and techniques. OPCo and certain of its mining subsidiaries own an additional
113,000,000 tons of clean recoverable coal in Ohio which ranges in sulfur
content between 2.4% and 3.4% sulfur by weight (weighted average 2.6%).
Recovery of this coal would require substantial development.
OPCo and certain of its coal-mining subsidiaries also own or control
coal reserves in the State of West Virginia which contain approximately
103,000,000 tons of clean recoverable coal ranging in sulfur content between
1.4% and 4.0% sulfur by weight (weighted average, 2.2%) of which approximately
26,000,000 tons can be recovered based upon existing mining plans and
projections and employing current mining practices and techniques.
Nuclear
I&M has made commitments to meet certain of the nuclear fuel
requirements of the Cook Plant. The nuclear fuel cycle consists of the mining
and milling of uranium ore to uranium concentrates; the conversion of uranium
concentrates to uranium hexafluoride; the enrichment of uranium hexafluoride;
the fabrication of fuel assemblies; the utilization of nuclear fuel in the
reactor; and the reprocessing or other disposition of spent fuel. Steps cur-
rently are being taken, based upon the planned fuel cycles for the Cook Plant,
to review and evaluate I&M's requirements for the supply of nuclear fuel. I&M
has made and will make purchases of uranium in various forms in the spot,
short-term, and mid-term markets until it decides that deliveries under long-
term supply contracts are warranted.
For purposes of the storage of high-level radioactive waste in the form
of spent nuclear fuel, I&M has completed modifications to its spent nuclear
fuel storage pool to permit normal operations through 2010.
I&M's costs of nuclear fuel consumed do not assume any residual or
salvage value for residual plutonium and uranium.
Nuclear Waste and Decommissioning
The Nuclear Waste Policy Act of 1982, as amended, establishes Federal
responsibility for the permanent off-site disposal of spent nuclear fuel and
high-level radioactive waste. Disposal costs are paid by fees assessed
against owners of nuclear plants and deposited into the Nuclear Waste Fund
created by the Act. In 1983, I&M entered into a contract with DOE for the
disposal of spent nuclear fuel. Under terms of the contract, for the disposal
of nuclear fuel consumed after April 6, 1983 by I&M's Cook Plant, I&M is
paying to the fund a fee of one mill per kilowatt-hour, which I&M is currently
recovering from customers. For the disposal of nuclear fuel consumed prior to
April 7, 1983, I&M must pay the U.S. Treasury a fee estimated at approximately
$71,964,000, exclusive of interest of $108,873,000 at December 31, 1997. The
aggregate amount has been recorded as long-term debt. Because of the current
uncertainties surrounding DOE's program to provide for permanent disposal of
spent nuclear fuel, I&M has not yet paid any of the pre-April 1983 fee. At
December 31, 1996, funds collected from customers to pay the pre-April 1983
fee and accrued interest approximated the long-term liability. In November
1996, the IURC and MPSC issued orders approving flexible funding procedures in
which any excess funds collected for pre-April 7, 1983 spent nuclear fuel dis-
posal would be deposited into I&M's nuclear decommissioning trust funds.
On May 30, 1995, I&M and a group of unaffiliated utilities owning and
operating nuclear plants filed a petition for review in the U.S. Court of
Appeals for the District of Columbia Circuit requesting that the court issue a
declaration that the Nuclear Waste Policy Act of 1982 (NWPA) imposes on DOE an
unconditional obligation to begin acceptance of spent nuclear fuel and high
level radioactive waste by January 31, 1998. On July 23, 1996, the court
ruled that the NWPA creates an obligation in DOE, reciprocal to the utilities'
obligation to pay, to start disposing of the spent nuclear fuel and high level
radioactive waste no later than January 31, 1998. The court remanded the case
to DOE, holding that determination of a remedy was premature, since DOE had
not yet defaulted on its obligations.
In December 1996, I&M received a letter from DOE advising that DOE
anticipates that it will be unable to begin acceptance of spent nuclear fuel
and high level radioactive waste for disposal in a repository or interim
storage facility by January 31, 1998. On January 31, 1997, in anticipation of
DOE's breach of their statutory and contractual obligations, I&M along with 35
unaffiliated utilities and 33 states filed joint petitions for review in the
U.S. Court of Appeals for the District of Columbia Circuit requesting that the
court permit the utilities to suspend further payments into the nuclear waste
fund, authorize escrow of the payments, and order further action on the part
of DOE to meet its obligations under the NWPA. On November 12, 1997, the
Court of Appeals issued a decision granting in part and denying in part the
utilities' request for relief. The court ordered DOE to proceed with
contractual remedies and to refrain from concluding that DOE's delay is
unavoidable due to the lack of a repository or the lack of interim storage
authority. The court, however, declined to order DOE to begin disposing of
fuel. On January 31, 1998, the deadline for DOE's performance, the DOE failed
to begin disposing of the utilities' spent nuclear fuel. In February 1998,
the states and the utilities filed with the Court of Appeals for additional
relief in connection with DOE's failure to meet the January 31, 1998 deadline.
Studies completed in 1997 estimate decommissioning and low-level
radioactive waste disposal costs for the Cook Plant to range from $700,000,000
to $1.152 billion in 1997 nondiscounted dollars. The wide range is caused by
variables in assumptions, including the estimated length of time spent nuclear
fuel must be stored at the Cook Plant subsequent to ceasing operations, which
depends on future developments in the federal government's spent nuclear fuel
disposal program. Continued delays in the federal fuel disposal program can
result in increased decommissioning costs. I&M is recovering decommissioning
costs in its three rate-making jurisdictions based on at least the lower end
of the range in the most recent respective decommissioning study available at
the time of the rate proceeding (the study range utilized in the Indiana rate
case, I&M's primary jurisdiction, was $588,000,000 to $1.102 billion in 1991
dollars). I&M records decommissioning costs in other operation expense and
records a noncurrent liability equal to the decommissioning cost recovered in
rates which was $28,000,000 in 1997, $27,000,000 in 1996 and $30,000,000 in
1995 (including $4,000,000 in special deposits). At December 31, 1997, I&M
had recognized a decommissioning liability of $381,000,000. I&M will continue
to reevaluate periodically the cost of decommissioning and to seek regulatory
approval to revise its rates as necessary.
Funds recovered through the rate-making process for disposal of spent
nuclear fuel consumed prior to April 7, 1983 and for nuclear decommissioning
have been segregated and deposited in external funds for the future payment of
such costs. Trust fund earnings decrease the amount to be recovered from
ratepayers.
The ultimate cost of retiring I&M's Cook Plant may be materially
different from the estimates contained in the site-specific study and the
funding targets as a result of (a) the type of decommissioning plan selected,
(b) the escalation of various cost elements (including, but not limited to,
general inflation), (c) the further development of regulatory requirements
governing decommissioning, (d) the limited availability to date of significant
experience in decommissioning such facilities, (e) the technology available at
the time of decommissioning differing significantly from that assumed in these
studies and (f) the availability of nuclear waste disposal facilities.
Accordingly, management is unable to provide assurance that the ultimate cost
of decommissioning the Cook Plant will not be significantly greater than
current projections.
The Low-Level Waste Policy Act of 1980 (LLWPA) mandates that the
responsibility for the disposal of low-level waste rests with the individual
states. Low-level radioactive waste consists largely of ordinary refuse and
other items that have come in contact with radioactive materials. To
facilitate this approach, the LLWPA authorized states to enter into regional
compacts for low-level waste disposal subject to Congressional approval. The
LLWPA also specified that, beginning in 1986, approved compacts may prohibit
the importation of low-level waste from other regions, thereby providing a
strong incentive for states to enter into compacts. Michigan, the state where
the Cook Plant is located, was a member of the Midwest Compact, but its
membership was revoked in 1991. Michigan is responsible for developing a
disposal site for the low-level waste generated in Michigan.
Although Michigan amended its law regarding low-level waste site
development in 1994 to allow a volunteer to host a facility, little progress
has been made to date. A bill was introduced in 1996 to further address the
issue but no action was taken. Development of required legislation and prog-
ress with the site selection process has been inhibited by many factors, and
management is unable to predict when a new disposal site for Michigan low-
level waste will be available.
On July 1, 1995, the disposal site in South Carolina reopened to accept
waste from most areas of the U.S., including Michigan. This was the first
opportunity for the Cook Plant to dispose of low-level waste since 1990. To
the extent practicable, the waste formerly placed in storage and the waste
presently generated are now being sent to the disposal site.
Energy Policy Act - Nuclear Fees
The Energy Policy Act of 1992 (Energy Act), contains a provision to fund
the decommissioning and decontamination of DOE's existing uranium enrichment
facilities from a combination of sources including assessments against
electric utilities which purchased enrichment services from DOE facilities.
I&M's remaining estimated liability is $39,325,000, subject to inflation
adjustments, and is payable in annual assessments over the next nine years.
I&M recorded a regulatory asset concurrent with the recording of the
liability. The payments are being recorded and recovered as fuel expense.
These assessments were held to be unlawful in a June 1995 decision of
the U.S. Court of Federal Claims in a case involving an unaffiliated utility.
Based upon that decision I&M filed a complaint in the same court seeking
refunds of the assessments levied with respect to its enrichment services
contracts. In May 1997 the U.S. Court of Appeals for the Federal Circuit
reversed the lower court's 1995 decision. The utility has petitioned the U.S.
Supreme Court for review of the decision. I&M's complaint has been stayed
pending a final decision in this case.
Environmental and Other Matters
AEP's subsidiaries are subject to regulation by federal, state and local
authorities with regard to air and water-quality control and other
environmental matters, and are subject to zoning and other regulation by local
authorities.
It is expected that costs related to environmental requirements will
eventually be reflected in the rates of AEP's electric utility subsidiaries
and that AEP's electric utility subsidiaries will be able to provide for
required environmental controls. However, some customers may curtail or cease
operations as a consequence of higher energy costs. There can be no assurance
that all such costs will be recovered. Moreover, legislation currently being
proposed at the state and federal levels governing restructuring of the
electric utility industry may also affect the recovery of certain costs. See
Competition and Business Change.
Except as noted herein, AEP's subsidiaries which own or operate
generating, transmission and distribution facilities are in substantial
compliance with pollution control laws and regulations.
Air Pollution Control
For the AEP System, compliance with the Clean Air Act (CAA) is requiring
substantial expenditures that generally are being recovered through increases
in the rates of AEP's operating subsidiaries. However, there can be no
assurance that all such costs will be recovered. See Construction Program -
Construction Expenditures.
Acid Rain: The Acid Rain Program (Title IV) of the Clean Air Act
Amendments of 1990 (CAAA) created an emission allowance program pursuant to
which utilities are authorized to emit a designated quantity of sulfur dioxide
(SO2), measured in tons per year, on a system wide or aggregate basis.
Emission reductions are required by virtue of the establishment of annual
allowance allocations at levels substantially below historical emission levels
for most utility units. There are two phases of SO2 control under the Acid
Rain Program. Phase I, effective January 1, 1995, requires SO2 emission
reductions from certain units that emitted SO2 above a rate of 2.5 pounds per
million Btu heat input in 1985. Phase I unit allowance allocations were
calculated based on 1985 utilization rates and an emission rate of 2.5 pounds
of SO2 per million Btu heat input. Phase I permits have been issued for all
Phase I affected units in the AEP System.
Phase II, which affects all fossil fuel-fired steam generating units
with capacity greater than 25 megawatts imposes more stringent SO2 emission
control requirements beginning January 1, 2000. If a unit emitted SO2 in 1985
at a rate in excess of 1.2 pounds per million Btu heat input, the Phase II
allowance allocation is premised upon an emission rate of 1.2 pounds at 1985
utilization levels. If actual SO2 emissions for a Phase II affected unit in
1985 were less than 1.2 pounds per million Btu, the allowance allocation is,
in most instances, based on the actual 1985 emission rate.
In addition to regulating SO2 emissions, Title IV of the CAAA contains
provisions regulating emissions of nitrogen oxides (NOx). In April 1995,
Federal EPA promulgated NOx emission limitations for tangentially fired
boilers and dry bottom wall-fired boilers for Phase I and Phase II units. In
addition, on December 19, 1996, Federal EPA published final NOx emission
limitations for wet bottom wall-fired boilers, cyclone boilers, units applying
cell burner technology and all other types of boilers. The regulations also
revised downward the NOx limitations applicable to tangentially fired and
wall-fired boilers in Phase II. These emission limitations are to be achieved
by January 1, 2000. On February 13, 1998, the U.S. Court of Appeals for the
District of Columbia Circuit, in an appeal in which the AEP System operating
companies participated, upheld the emission limitations.
Title I National Ambient Air Quality Standards Attainment: The CAA
contains additional provisions, other than the Acid Rain Program, which could
require reductions in emissions of NOx and other pollutants from fossil fuel-
fired power plants. Title I, dealing generally with attainment of federally
set National Ambient Air Quality Standards (NAAQS), establishes a tiered
system for classifying degrees of nonattainment with the one-hour NAAQS for
ozone. Depending upon the severity of non-attainment within a given non-
attainment area, reductions in NOx emissions from fossil fuel-fired power
plants may be required as part of a state's plan for achieving attainment with
the one-hour ozone NAAQS. While one-hour ozone NAAQS non-attainment is
largely restricted to urban areas, AEP System generating units could be
determined to be affecting downwind urban ozone concentrations and may
therefore, eventually be required to reduce NOx emissions pursuant to Title I.
In July 1997, Federal EPA revised the ozone and particulate matter
NAAQS, creating a new eight-hour ozone standard and establishing a new
standard for particulate matter less than 2.5 microns in diameter (PM2.5).
Both of these new standards have the potential to affect adversely the
operation of AEP System generating units. Substantial reductions in NOx
emissions from fossil fuel-fired power plants may be required as part of a
state's plan to attain the eight-hour ozone standard. The actual
implementation of the new PM2.5 NAAQS has been delayed for five years.
Substantial reductions in SO2 and/or other emissions from fossil fuel-fired
power plants may be required as part of a state's plan to attain the PM2.5
NAAQS. The AEP System operating companies joined with other utilities to
appeal the revised NAAQS by filing petitions for review in August and
September 1997 in the U.S. Court of Appeals for the District of Columbia
Circuit.
On July 9, 1997, Federal EPA proposed revisions to the New Source
Performance Standards applicable to new and modified fossil fuel-fired power
plants. Federal EPA characterized its proposal as "fuel neutral" since it
would impose the same stringent NOx emission limit (1.35lb./megawatt-hour net
energy output) for coal-fired boilers as for gas-fired boilers. If finalized,
the proposal would effectively require costly selective catalytic reduction or
comparable technology to control NOx emissions from new or modified coal-fired
boilers.
NOx SIP Calls and the Ozone Transport Assessment Group: In 1995, the
Environmental Council of States formed the Ozone Transport Assessment Group
(OTAG) to study the role of transport of ozone and ozone precursor emissions
(primarily NOx) in contributing to ozone nonattainment in the Northeast,
Chicago, and Atlanta nonattainment areas. OTAG was comprised of the
environmental commissioners of 37 eastern states, members of Federal EPA and
representatives from environmental and industry groups. OTAG studied the
ozone problem for two years, conducting extensive modeling and analysis of
ozone levels and the effects of ozone transport. OTAG submitted its final
recommendations to Federal EPA in July 1997.
After receipt of the OTAG recommendations, Federal EPA in October 1997
issued a notice (NOx transport SIP call) concluding that certain State
Implementation Plans are deficient because they allow NOx emissions that
contribute excessively to ozone nonattainment in downwind states. Federal
EPA's proposed NOx transport SIP call would establish state-by-state NOx
emission budgets for the five-month ozone season to be met by the year 2002.
The proposed NOx budgets apply to 22 eastern states and are premised mainly on
the assumption of controlling power plant NOx emissions to 0.15 lb./MBtu
(approximately 85% below 1990 levels). The NOx transport SIP call purports to
implement both the new eight-hour ozone standard and the one-hour ozone
standard. The NOx reductions called for by Federal EPA are clearly targeted
at coal-fired electric utilities and may adversely impact the ability of
electric utilities to obtain new and modified source permits. The cost of
meeting NOx emissions reduction requirements that might be imposed as a result
of the NOx transport SIP call cannot be precisely predicted at this time, but
could be significant.
Section 126 Petitions: On or about August 14, 1997, eight northeastern
states (New York, New Hampshire, Maine, Massachusetts, Rhode Island,
Pennsylvania, Connecticut, and Vermont) filed petitions with Federal EPA under
Section 126 of the Clean Air Act, claiming that NOx emissions from power
plants in midwestern states, including all the coal-fired plants of AEP's
operating subsidiaries, prevent the Northeast from attaining the ozone NAAQS.
Among other things, the petitioners generally seek NOx emission reductions 85%
below 1990 levels from the utility sources in midwestern states.
Federal EPA on or about December 19, 1997 entered into a Memorandum of
Agreement (MOA) with the petitioning states that establishes a schedule for
taking final action on the Section 126 petitions on approximately the same
time frame as Federal EPA's final action on the NOx transport SIP call. The
MOA calls for a proposed rulemaking on the Section 126 petitions by September
30, 1998 and final action by April 30, 1999 (subject to certain limited
exceptions). On January 9, 1998, a number of utilities, including the
operating companies of the AEP System, filed a petition in the U.S. Court of
Appeals for the District of Columbia Circuit seeking a review of the MOA. On
February 25, 1998, the eight northeastern states filed an action in the U.S.
District Court for the Southern District of New York seeking an order
directing Federal EPA to rule on the Section 126 petitions within 60 days of
receipt.
SO2 NAAQS: On January 30, 1998, the U.S. Court of Appeals for the
District of Columbia Circuit remanded the final rule promulgated in May 1996
by Federal EPA reaffirming the existing primary NAAQS for SO2. The court
directed Federal EPA to provide additional justification for the rule but did
not specify a schedule for completion.
Hazardous Air Pollutants: Hazardous air pollutant emissions from
utility boilers are potentially subject to control requirements under Title
III of the CAAA. The CAAA specifically directed Federal EPA to study
potential public health impacts of hazardous air pollutants emitted from
electric utility steam generating units. Federal EPA was required to report
the results of this study to Congress by November 1993 and to regulate
emissions of these hazardous pollutants if necessary. On February 25, 1998,
Federal EPA issued a final report to Congress citing as potential health and
environmental threats, mercury and
three other hazardous air pollutants present in power plant
emissions. Noting uncertainty regarding health effects and the absence of
control technology for mercury, no immediate regulatory action was proposed
regarding emission reductions.
In addition, Federal EPA is required to study the deposition of
hazardous pollutants in the Great Lakes, the Chesapeake Bay, Lake Champlain,
and other coastal waters. As part of this assessment, Federal EPA is
authorized to adopt regulations to prevent serious adverse effects to public
health and serious or widespread environmental effects. It is possible that
this assessment of water body deposition may result in additional regulation
of electric utility steam generating units.
Federal EPA was also required to study mercury emissions and report its
findings to Congress by 1994. Federal EPA presented that report to Congress
in December 1997. The report identifies electric utilities as being the third
leading emitter of mercury. Presently, mercury emissions from electric
utilities are not regulated under the CAA. However, Federal EPA intends to
engage in further studies of mercury emissions, which may lead to additional
regulation in the future.
Permitting and Enforcement: The CAAA expanded the enforcement authority
of the federal government by increasing the range of civil and criminal
penalties for violations of the CAA and enhancing administrative civil
provisions, adding a citizen suit provision and imposing a national operating
permit system, emission fee program and enhanced monitoring, recordkeeping and
reporting requirements for existing and new sources. On February 13, 1997,
Federal EPA issued the Credible Evidence rule, which allows Federal EPA to use
any credible evidence or information in lieu of, or in addition to, the test
methods prescribed by the regulation for determining compliance with emission
limits. This rule has the potential to expand significantly Federal EPA's
ability to bring enforcement actions and to increase the stringency of the
emission limits to which AEP System plants are subject. On March 10, 1997, a
number of industries, including AEP System operating companies, filed
petitions for review of the Credible Evidence Rule with the U.S. Court of
Appeals for the District of Columbia Circuit. Oral argument in that case is
scheduled to be heard on April 21, 1998.
Global Climate Change: In December 1997, delegates from 167 nations,
including the United States, agreed to a treaty, known as the "Kyoto
Protocol," establishing legally-binding emission reductions for gases
suspected of causing climate change. If the U.S. becomes a party to the
treaty it will be bound to reduce emissions of carbon dioxide (CO2), methane
and nitrous oxides by 7% below 1990 levels and emissions of hydrofluorcarbons,
perfluorocarbons and sulphur hexafluoride 7% below 1995 levels in the years
2008-2012. The Protocol will be available for signature from March 1998 to
March 1999 and requires ratification by at least 55 nations that account for
at least 55% of developed countries' 1990 emissions of CO2 to enter into
force. The agreement is not expected to be sent to the U.S. Senate for
ratification before 1999.
Since the AEP System is a significant emitter of carbon dioxide, its
financial condition could be adversely affected by the imposition of
limitations on CO2 emissions if compliance costs cannot be fully recovered
from customers. In addition, any such severe program to reduce CO2 emissions
could impose substantial costs on industry and society and erode the economic
base that AEP's operations serve.
West Virginia SO2 Limits: West Virginia promulgated SO2 limitations
which Federal EPA approved in February 1978. The emission limitations for the
Mitchell Plant have been approved by Federal EPA for primary ambient air
quality (health-related) standards only. West Virginia is obligated to
reanalyze SO2 emission limits for the Mitchell Plant with respect to
secondary ambient air quality (welfare-related) standards. Because the CAA
provides no specific deadline for approval of emission limits to achieve
secondary ambient air quality standards, it is not certain when Federal EPA
will take dispositive action regarding the Mitchell Plant.
West Virginia has had a request to increase the SO2 emission limitation
for Kammer pending before Federal EPA for many years, although the change has
not been acted upon by Federal EPA. On August 4, 1994, however, Federal EPA
issued a Notice of Violation to OPCo alleging that Kammer Plant was operating
in violation of the applicable federally enforceable SO2 emission limit. On
May 20, 1996, the Notice of Violation and an enforcement action subsequently
filed by Federal EPA were resolved through the entry of a consent decree in
the U.S. District Court for the Northern District of West Virginia. The
decree provides for compliance with an interim emission limit of 6.5 pounds of
SO2 per million Btu actual heat input on a three-hour basis and 5.8 pounds of
SO2 per million Btu on an annual basis. West Virginia and industrial sources
in the area of the Kammer Plant are developing a revision to the state
implementation plan with respect to SO2 emission limitations which is to be
submitted no later than November 1998. The interim emission limit for Kammer
will remain in effect until after that time.
Short Term SO2 Limits: On January 2, 1997, Federal EPA proposed a new
intervention level program under the authority of Section 303 of the CAA to
address five minute peak SO2 concentrations believed to pose a health risk to
certain segments of the population. The proposal establishes a "concern"
level and an "endangerment" level. States must investigate exceedances of the
concern level and decide whether to take corrective action. If the
endangerment level is exceeded, the state must take action to reduce SO2
levels. The effects of this proposed intervention program on AEP operations
cannot be predicted at this time.
Regional Haze: On July 31, 1997, Federal EPA proposed new rules to
regulate regional haze attributable to anthropogenic emissions. The primary
goal of the new regional haze program is to address visibility impairment in
and around "Class I" protected areas, such as national parks and wilderness
areas. Because regional haze precursor emissions are believed by Federal EPA
to travel long distances, Federal EPA proposes to regulate such precursor
emissions in every state. Under the proposal, each state must develop a
regional haze control program that imposes controls necessary to steadily
reduce visibility impairment in Class I areas on the worst days and that
ensures that visibility remains good on the best days. This is accomplished
using a unit of measurement known as a "deciview." The plan's goal is to
reduce visibility impairment by one deciview or more over each 10-15 year
period. The final time period will be set as part of the final rulemaking.
The AEP System is a significant emitter of fine particulate matter and
its precursors that could be linked to the creation of regional haze. The
finalization of Federal EPA's proposed rule to control regional haze may have
an adverse financial impact on AEP as it may trigger the requirement to
install costly new pollution control devices to control emissions of fine
particulate matter and its precursors (including SO2 and NOx). The actual
impact of the regional haze regulations cannot be determined at this time.
Life Extension: On July 21, 1992, Federal EPA published final
regulations in the Federal Register governing application of new source rules
to generating plant repairs and pollution control projects undertaken to
comply with the CAA. Generally, the rule provides that plants undertaking
pollution control projects will not trigger new source review requirements.
The Natural Resources Defense Council and a group of utilities, including five
AEP System companies, have filed petitions in the U.S. Court of Appeals for
the District of Columbia Circuit seeking a review of the regulations. The
court recently requested that the parties submit proposed briefing schedules.
Water Pollution Control
The Clean Water Act prohibits the discharge of pollutants to waters of
the United States from point sources except pursuant to an NPDES permit issued
by Federal EPA or a state under a federally authorized state program.
Under the Clean Water Act, effluent limitations requiring application of
the best available technology economically achievable are to be applied, and
those limitations require that no pollutants be discharged if Federal EPA
finds elimination of such discharges is technologically and economically
achievable.
The Clean Water Act provides citizens with a cause of action to enforce
compliance with its pollution control requirements. Since 1982, many such
actions against NPDES permit holders have been filed. To date, no AEP System
plants have been named in such actions.
All System Plants are operating with NPDES permits. Under EPA's
regulations, operation under an expired NPDES permit is authorized provided an
application is filed at least 180 days prior to expiration. Renewal applica-
tions are being prepared or have been filed for renewal of NPDES permits which
expire in 1998.
The NPDES permits generally require that certain thermal impact study
programs be undertaken. These studies have been completed for all System
plants. Thermal variances are in effect for all plants with once-through
cooling water. The thermal variances for Conesville and Muskingum River
plants impose thermal management conditions that could result in load curtail-
ment under certain conditions, but the cost impacts are not expected to be
significant. Based on favorable results of in-stream biological studies, the
thermal temperature limits for both Conesville and Muskingum River plants were
raised in the renewed permits issued in 1996. Consequently, the potential for
load curtailment and adverse cost impacts is further reduced.
Certain mining operations conducted by System companies as discussed
under Fuel Supply are also subject to Federal and state water pollution
control requirements, which may entail substantial expenditures for control
facilities, not included at present in the System's construction cost
estimates set forth herein.
The Federal Water Quality Act of 1987 requires states to adopt stringent
water quality standards for a large category of toxic pollutants and to
identify specialized control measures for dischargers to waters where it is
shown through the use of total maximum daily loads (TMDLs) that water quality
standards are not being met. Implementation of these provisions could result
in significant costs to the AEP System if biological monitoring requirements
and water quality-based effluent limits are placed in NPDES permits.
In March 1995, Federal EPA finalized a set of rules which establish
minimum water quality standards, anti-degradation policies and implementation
procedures for more stringently controlling releases of toxic pollutants into
the Great Lakes system. This regulatory package is called the Great Lakes
Water Quality Initiative (GLWQI). The most direct compliance cost impact
could be related to I&M's Cook Plant. Management cannot presently determine
whether the GLWQI would have a significant adverse impact on AEP operations.
The significance of such impact will depend on the outcome of Federal EPA's
policy on intake credits and site specific variables as well as Michigan's
implementation strategy. Federal EPA's rule is presently under review by the
District of Columbia Circuit Court of Appeals in litigation initiated by
several industry groups. If Indiana and Ohio eventually adopt the GLWQI
criteria for statewide application, AEP System plants located in those states
could also be affected.
Solid and Hazardous Waste
Section 311 of the Clean Water Act imposes substantial penalties for
spills of Federal EPA-listed hazardous substances into water and for failure
to report such spills. The Comprehensive Environmental Response, Compensa-
tion, and Liability Act (CERCLA) expanded the reporting requirements to cover
the release of hazardous substances generally into the environment, including
water, land and air. AEP's subsidiaries store and use some of these hazardous
substances, including PCBs contained in certain capacitors and transformers,
but the occurrence and ramifications of a spill or release of such substances
cannot be predicted.
CERCLA and similar state law provide governmental agencies with the
authority to require clean-up of hazardous waste sites and releases of
hazardous substances into the environment and to seek compensation for damages
to natural resources. Since liability under CERCLA is strict and can be
applied retroactively, AEP System companies which previously disposed of PCB-
containing electrical equipment and other hazardous substances may be required
to participate in remedial activities at such disposal sites should environ-
mental problems result. AEP System companies are presently defendants in five
cases involving cost-recovery lawsuits at Federal EPA-identified CERCLA sites.
OPCo is involved at three of these sites and I&M at the two other sites. AEP
System companies are identified as Potentially Responsible Parties (PRPs) for
seven additional federal sites, including CSPCo, KEPCo and Wheeling Power
Company at one site each, I&M at three sites, and OPCo at two sites. I&M has
been named as a PRP at one state remediation site. Management's present
estimates do not anticipate material cleanup costs for identified sites for
which AEP subsidiaries have been declared PRPs or are defendants in CERCLA
cost recovery litigation. However, if for reasons not currently identified
significant costs are incurred for cleanup, future results of operations and
possibly financial condition would be adversely affected unless the costs can
be recovered through rates.
Regulations issued by Federal EPA under the Toxic Substances Control Act
govern the use, distribution and disposal of PCBs, including PCBs in
electrical equipment. Deadlines for removing certain PCB-containing
electrical equipment from service have been met.
In addition to handling hazardous substances, the System companies
generate solid waste associated with the combustion of coal, the vast majority
of which is fly ash, bottom ash and flue gas desulfurization wastes. These
wastes presently are considered to be non-hazardous under RCRA and applicable
state law and the wastes are treated and disposed in surface impoundments or
landfills in accordance with state permits or authorization or beneficially
utilized. As required by RCRA, EPA evaluated whether high volume coal
combustion wastes (such as fly ash, bottom ash and flue gas desulfurization
wastes) should be regulated as hazardous waste. In August, 1993 EPA issued a
regulatory determination that such high volume coal combustion wastes should
not be regulated as hazardous waste. For low volume coal combustion wastes,
such as metal and boiler cleaning wastes, Federal EPA will gather additional
information and make a regulatory determination by April 1999. Until that
time, these low volume wastes are provisionally excluded from regulation under
the hazardous waste provisions of RCRA. All presently generated hazardous
waste is being disposed of at permitted off-site facilities in compliance with
applicable Federal and state laws and regulations. For System facilities
which generate such wastes, System companies have filed the requisite notices
and are complying with RCRA and applicable state regulations for generators.
Nuclear waste produced at the Cook Plant regulated under the Atomic Energy Act
is excluded from regulation under RCRA.
Federal EPA's technical requirements for underground storage tanks
containing petroleum will require retrofitting or replacement of an
appreciable number of tanks. Compliance costs for tank replacement and site
remediation have not been significant to date.
Electric and Magnetic Fields (EMF)
EMF is found everywhere there is electricity. Electric fields are
created by the presence of electric charges. Magnetic fields are produced by
the flow of those charges. This means that EMF is created by electricity
flowing in transmission and distribution lines, household wiring, and
appliances.
A number of studies in the past several years have examined the
possibility of adverse health effects from EMF. While some of the
epidemiological studies have indicated some association between exposure to
EMF and health effects, the majority of studies have indicated no such
association. On October 31, 1996, the National Academy of Sciences (NAS)
released a report, based on a review of over 500 studies spanning 17 years of
research, which contained the following summary statement: "... the con-
clusion of the committee is that the current body of evidence does not show
that exposure to these fields presents a human health hazard..." The epidemi-
ological studies that have received the most public attention, including the
NAS report, reflect a weak correlation between surrogate or indirect estimates
of EMF exposure and certain cancers. Studies using direct measurements of EMF
exposure show no such association.
On July 3, 1997, the results of a five-year study by the National Cancer
Institute (NCI) were released. The NCI researchers found no evidence that EMF
in the home increases the risk of childhood cancer.
The Energy Policy Act of 1992 established a coordinated Federal EMF
research program which will end in 1998. The program funding is $65,000,000,
half of which was provided by private parties including utilities. AEP has
contributed over $400,000 to this program. AEP has also supported an
extensive EMF research program coordinated by the Electric Power Research
Institute, working closely with its staff and contributing more than $500,000
to this effort in 1997. See Research and Development.
AEP's participation in the programs is a continuation of its efforts to
monitor and support further research and to communicate with its customers and
employees about this issue. Its operating company subsidiaries provide their
residential customers with information and field measurements on request,
although there is no scientific basis for interpreting such measurements.
A number of lawsuits based on EMF-related grounds have been filed in
recent years against electric utilities. A suit was filed on May 23, 1990
against I&M involving claims that EMF from a 345 KV transmission line caused
adverse health effects. No specific amount has been requested for damages in
this case and no trial date has been set.
Some states have enacted regulations to limit the strength of magnetic
fields at the edge of transmission line rights-of-way. No state which the AEP
System serves has done so. In March 1993, The Ohio Power Siting Board issued
its amended rules providing for additional consideration of the possible
effects of EMF in the certification of electric transmission facilities.
Applicants are required to address possible health effects and discuss the
consideration of design alternatives with respect to estimates of EMF levels.
Management cannot predict the ultimate impact of the question of EMF
exposure and adverse health effects. If further research shows that EMF
exposure contributes to increased risk of cancer or other health problems, or
if the courts conclude that EMF exposure harms individuals and that utilities
are liable for damages, or if states limit the strength of magnetic fields to
such a level that the current electricity delivery system must be
significantly changed, then the results of operations and financial condition
of AEP and its operating subsidiaries could be materially adversely affected
unless these costs can be recovered from ratepayers.
Research and Development
AEP and its subsidiaries are involved in a number of research projects
which are directed toward developing more efficient methods of burning coal,
reducing the contaminants resulting from combustion of coal, and improving the
efficiency and reliability of power transmission, distribution and
utilization.
AEP System operating companies are members of the Electric Power
Research Institute (EPRI), an organization that manages research and
development on behalf of the U.S. electric utility industry. EPRI, founded in
1973, manages technical research and development programs for its members to
improve power production, delivery and use. Approximately 700 utilities are
members. Total AEP dues to EPRI were $15,300,000 for 1997, $9,900,000 for
1996 and $9,600,000 for 1995.
Total research and development expenditures by AEP and its subsidiaries,
including EPRI dues, were approximately $23,600,000 for the year ended
December 31, 1997, $16,400,000 for the year ended December 31, 1996 and
$13,600,000 for the year ended December 31, 1995. This includes expenditures
of $4,600,000 for 1997, $3,300,000 for 1996 and $1,100,000 for 1995 related to
pressurized fluidized-bed combustion, a process in which sulfur is removed
during coal combustion and nitrogen oxide formation is minimized.
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this amendment to the
report on Form 10-K to be signed on its behalf by the undersigned,
thereunto duly authorized. The signature of the undersigned company shall
be deemed to relate only to matters having reference to such company and any
subsidiaries thereof.
KENTUCKY POWER COMPANY
By: /s/ G. P. Maloney
(G. P. Maloney, Vice President)
Date: April 1, 1998
