SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------
FORM 10-K
---------------
(Mark One)
[ x ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1996
[ ] 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. .
---------- ---
<PAGE>
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
Columbus Southern 8-3/8% Junior Subordinated
Power Company 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
Indiana Michigan Cumulative Preferred Stock,
Power Company Non-Voting, $100 par value:
4-1/8% Chicago Stock Exchange
8% Junior Subordinated
Deferrable 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 chapter) 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 None
Kentucky Power Company None
Ohio Power Company 4-1/2% Cumulative Preferred
Stock, Voting, $100 par value
Aggregate market value Number of shares
of voting stock held of common stock
by non-affiliates of outstanding of
the registrants at the registrants at
March 7, 1997 March 7, 1997
---------------------- ------------------
AEP Generating Company None 1,000
($1,000 par value)
American Electric Power
Company, Inc. $7,747,000,000 188,235,000
($6.50 par value)
Appalachian Power Company $12,500,000 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 $18,700,000 27,952,473
(no par value)
NOTE ON MARKET VALUE OF VOTING STOCK HELD BY NON-AFFILIATES
All of the common stock of AEP Generating Company, Appalachian Power
Company, Columbus Southern Power Company, Indiana Michigan Power Company,
Kentucky Power Company and Ohio Power Company is owned by American Electric
Power Company, Inc. (see Item 12 herein). The voting stock owned by
non-affiliates of (i) Appalachian Power Company consists of 198,388 shares of
Cumulative Preferred Stock, no par value; and (ii) Ohio Power Company consists
of 258,252 shares of Cumulative Preferred Stock, $100 par value. Some of the
series of Cumulative Preferred Stock are not regularly traded. The aggregate
market value of the Cumulative Preferred Stock is based on the average of the
high and low prices on the closest trading date to March 7, 1997 for series
traded on the Philadelphia Stock Exchange, or the most recent reported bid
prices for those series not recently traded. Where recent market price
information was not available with respect to a series, the market price for
such series is based on the price of a recently traded series with an
adjustment related to any difference in the current yields of the two series.
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K
INTO WHICH DOCUMENT
DESCRIPTION IS INCORPORATED
----------- -------------------
Portions of Annual Reports of the following companies
for the fiscal year ended December 31, 1996: Part II
AEP Generating Company
American Electric Power Company, Inc.
Appalachian Power Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Ohio Power Company
Portions of Proxy Statement of American Electric Power
Company, Inc., dated March 10, 1997, for Annual
Meeting of Shareholders Part III
Portions of Information Statements of the following
companies for 1997 Annual Meeting of Shareholders,
to be filed within 120 days after December 31, 1996: 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.
TABLE OF CONTENTS
Page
Number
------
Glossary of Terms . . . . . . . . . . . . . . . . . . . . . . . . . i
Part I
Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . . 1
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . 27
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . 31
Item 4. Submission of Matters to a Vote of Security Holders . . . 32
Executive Officers of the Registrants. . . . . . . . . . . . . . . 32
Part II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters. . . . . . . . . . . . . . . . . . 35
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . 35
Item 7. Management's Discussion and Analysis of Results
of Operations and Financial Condition. . . . . . . . . 35
Item 8. Financial Statements and Supplementary Data . . . . . . . 36
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure . . . . . . . . 36
Part III
Item10. Directors and Executive Officers of the Registrants . . . 37
Item11. Executive Compensation. . . . . . . . . . . . . . . . . . 38
Item12. Security Ownership of Certain Beneficial
Owners and Management. . . . . . . . . . . . . . . . . 41
Item13. Certain Relationships and Related Transactions. . . . . . 42
Part IV
Item14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K. . . . . . . . . . . . . . . . . . 43
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
Index to Financial Statement Schedules. . . . . . . . . . . . . . . S-1
Independent Auditors' Report. . . . . . . . . . . . . . . . . . . . S-2
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . E-1
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report,
they have the meanings indicated below.
Term Meaning
---- -------
AEGCo . . . . . . . AEP Generating Company, an electric utility subsidiary of
AEP.
AEP . . . . . . . . American Electric Power Company, Inc.
AEP System or
the System. . . . The American Electric Power System, an integrated
electric utility system, owned and operated by AEP's
electric utility subsidiaries.
AFUDC . . . . . . . Allowance for funds used during construction. Defined in
regulatory systems of accounts as the net cost of
borrowed funds used for construction and a reasonable
rate of return on other funds when so used.
APCo . . . . . . . Appalachian Power Company, an electric utility subsidiary
of AEP.
Buckeye . . . . . . Buckeye Power, Inc., an unaffiliated corporation.
CCD Group . . . . . CSPCo, CG&E and DP&L.
CG&E. . . . . . . . The Cincinnati Gas & Electric Company, an unaffiliated
utility company.
Cook Plant. . . . . The Donald C. Cook Nuclear Plant, owned by I&M.
CSPCo . . . . . . . Columbus Southern Power Company, an electric utility
subsidiary of AEP.
DOE . . . . . . . . United States Department of Energy.
DP&L. . . . . . . . The Dayton Power and Light Company, an unaffiliated
utility company.
Federal EPA . . . . United States Environmental Protection Agency.
FERC. . . . . . . . Federal Energy Regulatory Commission (an independent
commission within the DOE).
I&M . . . . . . . . Indiana Michigan Power Company, an electric utility
subsidiary of AEP.
IURC. . . . . . . . Indiana Utility Regulatory Commission.
KEPCo . . . . . . . Kentucky Power Company, an electric utility subsidiary of
AEP.
KPSC. . . . . . . . Kentucky Public Service Commission.
MPSC. . . . . . . . Michigan Public Service Commission.
NEIL. . . . . . . . Nuclear Electric Insurance Limited.
NPDES . . . . . . . National Pollutant Discharge Elimination System.
NRC . . . . . . . . Nuclear Regulatory Commission.
Ohio EPA. . . . . . Ohio Environmental Protection Agency.
OPCo. . . . . . . . Ohio Power Company, an electric utility subsidiary of
AEP.
OVEC. . . . . . . . Ohio Valley Electric Corporation, an electric utility
company in which AEP and CSPCo own a 44.2% equity
interest.
PCB's . . . . . . . Polychlorinated biphenyls.
PUCO. . . . . . . . The Public Utilities Commission of Ohio.
PUHCA . . . . . . . Public Utility Holding Company Act of 1935, as amended.
RCRA. . . . . . . . Resource Conservation and Recovery Act of 1976, as
amended.
Rockport Plant. . . A generating plant, consisting of two 1,300,000-kilowatt
coal-fired generating units, near Rockport, Indiana.
SEC . . . . . . . . Securities and Exchange Commission.
Service
Corporation . . . . American Electric Power Service Corporation, a service
subsidiary of AEP.
SO2 Allowance . . . An allowance to emit one ton of sulfur dioxide granted
under the Clean Air Act Amendments of 1990.
TVA . . . . . . . . Tennessee Valley Authority.
VEPCo . . . . . . . Virginia Electric and Power Company, an unaffiliated
utility company.
Virginia SCC. . . . State Corporation Commission of Virginia.
West Virginia PSC . Public Service Commission of West Virginia.
Zimmer or
Zimmer Plant. . . . Wm. H. Zimmer Generating Station, commonly owned by
CSPCo, CG&E and DP&L.
i
PART I ---------------------------------------------------------------------
Item 1. BUSINESS
- ----------------------------------------------------------------------------
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 electric
utility and 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
subsidiaries are physically interconnected, and their operations are
coordinated, as a single integrated electric utility system. Transmission
networks are interconnected with extensive distribution facilities in the
territories served. 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, 1996, the subsidiaries of AEP had a total of 17,951
employees. AEP, as such, has no employees. The operating subsidiaries of AEP
are:
APCo (organized in Virginia in 1926) is engaged in the generation,
purchase, transmission and distribution of electric power to
approximately 867,000 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, 1996, APCo and its wholly owned
subsidiaries had 3,900 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 Power Company and VEPCo. A
comparatively small part of the properties and business of APCo is
located in the northeastern end of the Tennessee Valley. APCo has
several points of interconnection with TVA and has entered into
agreements with TVA under which APCo and TVA interchange and transfer
electric power over portions of their respective systems.
CSPCo (organized in Ohio in 1937, the earliest direct predecessor
company having been organized in 1883) is engaged in the generation,
purchase, transmission and distribution of electric power to
approximately 609,000 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, 1996,
CSPCo had 1,837 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,
purchase, transmission and distribution of electric power to
approximately 542,000 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, 1996, I&M had 3,393 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,
purchase, transmission and distribution of electric power to
approximately 167,000 customers in an area in eastern Kentucky, and in
supplying electric power at wholesale to other utilities and
municipalities in Kentucky. At December 31, 1996, KEPCo had 718
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, 1996,
Kingsport Power Company had 87 employees.
OPCo (organized in Ohio in 1907 and reincorporated in 1924) is
engaged in the generation, purchase, transmission and distribution of
electric power to approximately 673,000 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, 1996, OPCo and its wholly owned
subsidiaries had 4,418 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 41,000
customers in northern West Virginia. Wheeling Power Company has no
generating facilities of its own. It purchases electric power
distributed to its customers from OPCo. At December 31, 1996, Wheeling
Power Company had 96 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 affiliate
transactions. This authority would be transferred to the FERC. In January and
February 1997, legislation was introduced in Congress 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
current 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, 1996 are as follows:
<TABLE>
<CAPTION>
AEP
AEGCo APCo CSPCo I&M KEPCo OPCo System(a)
-------- --------- ----------- ---------- -------- ---------- ----------
(in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Retail
Residential
Without Electric Heating . $ -- $ 231,504 $ 325,351 $ 232,212 $ 41,602 $ 280,640 $1,132,140
With Electric Heating. . . -- 340,796 115,339 111,556 64,839 155,081 826,411
-------- ---------- ---------- ---------- -------- ---------- ----------
Total Residential . . . . -- 572,300 440,690 343,768 106,441 435,721 1,958,551
Commercial . . . . . . . . -- 284,765 383,621 253,750 58,417 265,886 1,284,670
Industrial . . . . . . . . -- 368,421 147,543 312,777 92,322 635,404 1,618,843
Miscellaneous. . . . . . . -- 32,035 16,043 6,445 846 8,065 66,930
-------- ---------- ---------- ---------- -------- ---------- ----------
Total Retail. . . . . . . -- 1,257,521 987,897 916,740 258,026 1,345,076 4,928,994
Wholesale (sales for resale) 225,767 332,800 93,496 391,478 57,141 526,702 792,592
-------- ---------- ---------- ---------- -------- ---------- ----------
Total from KWH Sales. . . 225,767 1,590,321 1,081,393 1,308,218 315,167 1,871,778 5,721,586
Provision for Revenue Refunds -- (7,581) -- -- -- -- (7,581)
-------- ---------- ---------- ---------- -------- ---------- ----------
Total Net of Provision for
Revenue Refunds . . . . 225,767 1,582,740 1,081,393 1,308,218 315,167 1,871,778 5,714,005
Other Operating Revenues. . 125 42,129 24,290 20,275 8,154 39,930 135,229
-------- ---------- ---------- ---------- -------- ---------- ----------
Total Electric Operating
Revenues $225,892 $1,624,869 $1,105,683 $1,328,493 $323,321 $1,911,708 $5,849,234
- ---------------------- ======== ========== ========== ========== ======== ========== ==========
</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. 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, 1994, 1995 and 1996:
1994 1995 1996(a)
---------- ---------- ----------
(in thousands)
APCo . . . . . . . . . $(254,000) $(252,000) $(258,000)
CSPCo. . . . . . . . . (105,000) (143,000) (145,000)
I&M. . . . . . . . . . 107,000 118,000 121,000
KEPCo. . . . . . . . . 12,000 23,000 2,000
OPCo . . . . . . . . . 240,000 254,000 280,000
- ----------------
(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, 1994, 1995 and 1996:
1994(a) 1995(a) 1996(a)
------- ------- -------
(in thousands)
AEGCo(b) . . . . . . . $ 30,800 $ 29,200 $ 26,300
APCo(c). . . . . . . . 25,000 24,100 36,800
CSPCo(c) . . . . . . . 11,700 12,000 18,100
I&M(c)(d). . . . . . . 34,600 34,700 43,000
KEPCo(c) . . . . . . . 4,800 5,000 7,600
OPCo(c). . . . . . . . 20,000 20,200 30,200
------- ------- -------
Total System. . . $126,900 $125,200 $162,000
======= ======= =======
- ----------------
(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 1994, 1995 and 1996 were made on a short-term basis,
except that $21,800,000, $22,500,000 and $33,300,000, 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 1994, 1995 and 1996
amounts for I&M include $21,600,000, $21,000,000 and $20,900,000 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) 100 megawatts of electric power through 1997; (2)
205 megawatts of electric power through 2010; and (3) 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
1996 was 606, 105, 413, 18 and 136 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.
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.
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. 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,
1994, 1995 and 1996:
1994 1995 1996
--------- --------- ---------
(in thousands)
APCo . . . . . . . . . $(10,200) $ (5,400) $ (6,500)
CSPCo. . . . . . . . . (30,100) (31,100) (30,600)
I&M. . . . . . . . . . 50,300 46,700 46,300
KEPCo. . . . . . . . . 4,300 3,500 3,300
OPCo . . . . . . . . . (14,300) (13,700) (12,500)
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 net realization (revenue less operating, maintenance, fuel and federal
income tax expenses) of the various companies from such services during the
years ended December 31, 1994, 1995 and 1996:
1994 1995 1996
-------- -------- --------
(In thousands)
APCo . . . . . . . . . . $ 4,100 $ 6,000 $13,800
CSPCo. . . . . . . . . . 3,100 4,200 8,000
I&M. . . . . . . . . . . 6,700 4,800 7,700
KEPCo. . . . . . . . . . 800 1,200 2,800
OPCo . . . . . . . . . . 15,700 17,800 17,800
------- ------- -------
Total System . . . . . . $30,400 $34,000 $50,100
======= ======= =======
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 12, 1993, APCo, CSPCo, I&M, KEPCo and OPCo and two other AEP
System companies filed a transmission tariff with the FERC under which these
AEP System companies would provide limited transmission service to certain
companies. The tariff covered the terms and conditions of the service, as well
as the price which the companies pay for transmission services, regardless of
the source of electric power generation. On September 3, 1993, the FERC issued
an order accepting the transmission service tariff for filing, with the tariff
becoming effective on September 7, 1993, subject to refund.
On April 24, 1996, the FERC issued orders 888 and 889. These orders,
which resulted from the FERC's March 29, 1995 Notice of Proposed Rulemaking
("Mega-NOPR"), 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 transmission 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 transmission
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.
AEP is presently 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. 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 1,760,000 kilowatts. On October 1,
1997, it is scheduled to increase to approximately 1,900,000 kilowatts and to
remain at about that level through the remaining term of the contract. The
proceeds from the sale of power by OVEC, aggregating $312,000,000 in 1996, 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 1996. 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 301 delivery points. Buckeye is entitled
under such arrangements to receive, and is obligated to pay for, the excess of
its maximum one-hour coincident peak demand plus a 15% reserve margin over the
1,226,500 kilowatts of capacity of the generating units which Buckeye currently
owns in the Cardinal Station. Such demand, which occurred on January 18, 1994,
was recorded at 1,146,933 kilowatts.
CERTAIN INDUSTRIAL CUSTOMERS
Ravenswood Aluminum Corporation and Ormet Corporation operate major
aluminum reduction plants in the Ohio River Valley at Ravenswood, West
Virginia, and in the vicinity of Hannibal, Ohio, respectively. The power
requirements of such plants presently are approximately 356,000 kilowatts for
Ravenswood and 534,000 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 proportionate share of funds
required to permit continuation of the commercial operation of the Rockport
Plant and to perform all of its obligations, covenants and agreements under,
among other things, all loan agreements, leases and related documents to which
AEGCo is or becomes a party. See Capital Funds Agreement.
Unit Power Agreements
A unit power agreement between AEGCo and I&M (the I&M Power Agreement)
provides for the sale by AEGCo to I&M of all the power (and the energy
associated therewith) available to AEGCo at the Rockport Plant. I&M is
obligated, whether or not power is available from AEGCo, to pay as a demand
charge for the right to receive such power (and as an energy charge for any
associated energy taken by I&M) such amounts, as when added to amounts received
by AEGCo from any other sources, will be at least sufficient to enable AEGCo to
pay all its operating and other expenses, including a rate of return on the
common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power
Agreement will continue in effect until the date that the last of the lease
terms of Unit 2 of the Rockport Plant has expired unless extended in specified
circumstances.
Pursuant to an assignment between I&M and KEPCo, and a unit power
agreement between KEPCo and AEGCo, AEGCo sells KEPCo 30% of the power (and the
energy associated therewith) available to AEGCo from both units of the Rockport
Plant. KEPCo has agreed to pay to AEGCo in consideration for the right to
receive such power the same amounts which I&M would have paid AEGCo under the
terms of the I&M Power Agreement for such entitlement. The KEPCo unit power
agreement expires on December 31, 1999, unless extended.
A unit power agreement among AEGCo, I&M, VEPCo, and APCo provides for,
among other things, the sale of 70% of the power and energy available to AEGCo
from Unit 1 of the Rockport Plant to VEPCo by AEGCo from January 1, 1987
through December 31, 1999. VEPCo has agreed to pay to AEGCo in consideration
for the right to receive such power those amounts which I&M would have paid
AEGCo under the terms of the I&M Power Agreement for such entitlement.
Approximately 32% of AEGCo's operating revenue in 1996 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) provide
its proportionate share of the funds required to permit commercial operation of
the Rockport Plant, (iii) enable AEGCo to perform all of its obligations,
covenants and agreements under, among other things, all loan agreements, leases
and related documents to which AEGCo is or becomes a party (AEGCo Agreements),
and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo
Obligations) under the AEGCo Agreements, other than indebtedness, obligations
or liabilities owing to AEP. The Capital Funds Agreement will terminate after
all AEGCo Obligations have been paid in full.
INDUSTRY PROBLEMS
The electric utility industry, including the operating subsidiaries of
AEP, has encountered at various times in the last 15 years significant problems
in a number of areas, including: delays in and limitations on the recovery of
fuel costs from customers; proposed legislation, initiative measures and other
actions designed to prohibit construction and operation of certain types of
power plants under certain conditions and to eliminate or reduce the extent of
the coverage of fuel adjustment clauses; inadequate rate increases and delays
in obtaining rate increases; jurisdictional disputes with state public
utilities commissions regarding the interstate operations of integrated
electric systems; requirements for additional expenditures for pollution
control facilities; increased capital and operating costs; construction delays
due, among other factors, to pollution control and environmental considerations
and to material, equipment and fuel shortages; the economic effects on net
income (which when combined with other factors may be immediate and adverse)
associated with placing large generating units and related facilities in
commercial operation, including the commencement at that time of substantial
charges for depreciation, taxes, maintenance and other operating expenses, and
the cessation of AFUDC with respect to such units; uncertainties as to
conservation efforts by customers and the effects of such efforts on load
growth; depressed economic conditions in certain regions of the United States;
increasingly competitive conditions in the wholesale and retail markets;
proposals to deregulate certain portions of the industry 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 "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 requirement to transmit
directly to retail customers would have the result of permitting retail
customers to purchase electric power, at the election of such customers, not
only from the electric utility in whose service area they are located but from
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 1997, S.B. 427 was introduced in the Indiana Senate.
The bill proposed that all customers would have the unrestricted right to
choose their generator of electricity by July 1, 2004. Under the bill,
customers could choose their power supplier after October 1, 1999, by paying an
access charge. Transmission and distribution services would continue to be
regulated at the federal and state levels, respectively. The Indiana Senate
Commerce Committee held hearings on S.B. 427, and on February 25, 1997, amended
the bill to have a legislative committee study electric industry competition.
Michigan: In June 1995, the MPSC issued an order approving an
experimental five-year retail wheeling program and ordered Consumers Energy
Company and Detroit Edison Company, 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 commences when
each utility needs new capacity. The experiment seeks, as its goal, to
determine whether a retail wheeling program best serves the public interest in
a manner that promotes retail competition in a non-discriminatory fashion.
During the experiment, the MPSC will collect information regarding the effects
of retail wheeling. Consumers, Detroit Edison and other parties have appealed
the MPSC's order to the Michigan Court of Appeals.
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. I&M, in response to a MPSC order promulgated pursuant to
the Michigan Jobs Committee proposals, filed in June 1996 a proposed open
access distribution tariff applicable to new or expanding electric loads. The
MPSC has not yet taken action on I&M's filing. In December 1996, the MPSC
staff issued a report on electric industry restructuring which recommends a
phase-in program from 1997 through 2004 of direct access to electricity
suppliers applicable to all customers. The MPSC is holding hearings on the
staff report and has directed utilities to provide information on the
implementation of the staff's recommendations.
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. The Ohio investor-owned electric utilities were ordered by the PUCO
to file conjunctive electric service tariff applications conforming to the
guidelines.
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 Joint
Committee is scheduled to issue its report by October 1, 1997. In February
1997, H.B. 220 was introduced in the Ohio House of Representatives. The bill
is essentially identical to H.B. 653 introduced in the last session. The bill
proposes that all customers be permitted to select their electricity suppliers
effective January 1, 1998. The bill eliminates price regulation of electricity
generation functions in favor of market based prices. Service area rights for
Ohio's electricity suppliers would be confined to distribution service.
Transmission and distribution services would continue to be regulated at the
federal and state levels, respectively. The bill would require Ohio's electric
utilities to functionally unbundle their generation, transmission and
distribution services. Electric utilities would be permitted to recover
transition costs provided that such recovery does not cause prices to exceed
those in effect on the effective date of the legislation.
Virginia: In September 1995, the Virginia SCC instituted a proceeding to
review and consider policy regarding restructuring and the role of competition
in the electric utility industry in Virginia. Pursuant to the Virginia SCC's
order, its staff conducted an investigation into current issues in the electric
utility industry and, in July 1996, filed a report of its observations and
recommendations. Following the receipt of comments from interested parties,
the Virginia SCC issued an order in November 1996 directing the three largest
electric utility companies in the state, including APCo, to file various
studies and information with the Virginia SCC by March 31, 1997. In addition,
the November 1996 order directs the staff of the Virginia SCC to file reports
on subjects pertinent to the ongoing investigation throughout 1997.
In February 1997, the Virginia legislature passed a resolution requiring
the staff of the Virginia SCC to develop and provide to the joint subcommittee
of the legislature studying restructuring of the electric utility industry, by
November 1997, its draft of a working model of a restructured electric utility
industry most appropriate for Virginia. Five working groups, consisting of
representatives from the Virginia SCC staff and other interested parties, have
been organized to develop various aspects of such a model.
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 establishment of competition in power supply markets,
and the establishment of retail wheeling and intra-state open access of
jurisdictional power distribution systems. Pursuant to the West Virginia PSC's
order, various parties have filed comments and the West Virginia PSC has
scheduled a hearing on these matters commencing May 1, 1997.
Certain Other States in the Vicinity of AEP's Service Territory: In
March 1996, the Illinois Commerce Commission approved, and two Illinois-based
electric utilities implemented, retail wheeling pilot programs whereby certain
classes of customers are eligible to choose their electricity providers. In
addition, several bills have been introduced in the Illinois legislature that
would provide for retail competition among electric energy suppliers.
In May 1996, the New York Public Service Commission issued an Opinion and
Order Regarding Competitive Opportunities for Electric Service. The Opinion
and Order required each of the seven major electric utilities in New York to
file a rate/restructuring plan with the New York Public Service Commission in
which the utilities were to classify transmission and distribution facilities
and address the formation of an independent system operator for their
transmission systems. The Opinion and Order called for the establishment of a
competitive wholesale power market by early 1997 and the introduction of retail
customer choice early in 1998.
In late 1996, Pennsylvania enacted the Electricity Generation Customer
Choice and Competition Act. The Act requires Pennsylvania's electric utilities
to unbundle their rates and services and to provide open access over their
transmission and distribution systems to allow competitive suppliers to
generate and sell electricity directly to consumers in Pennsylvania. The Act
provides for phased implementation of retail access, with 33% of the peak load
having direct access by January 1, 1999, 66% of the peak load having direct
access by January 1, 2000, and all customers having direct access by January 1,
2001. Transmission and distribution of electricity will continue to be
regulated as a monopoly subject to the jurisdiction of the Pennsylvania Public
Utility Commission.
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 International,
Limited (AEPRI), AEP Resources Engineering & Services Company (formerly AEP
Energy Services, Inc.) (AEPRES) and AEP Energy Services, Inc. (formerly AEP
Energy Solutions, Inc.) (AEPES).
Resources' and AEPRI's primary business is development of, and investment
in, exempt wholesale generators, foreign utility companies, qualifying
cogeneration facilities and other power 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 values Yorkshire
Electricity at U.S. $2.4 billion. The Tender Offer will be 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. Resources and
NCII will each contribute 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 Electricity is an English inde- pendent
regional electricity company. It is principally engaged in the distribution of
electricity to 2.1 million customers in its authorized service territory
comprised of 4,180 square miles in northeast England.
AEPRI's 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 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. AEPRI's share of the total cost of the project of $172 million is
estimated to be approximately $120 million.
AEPRES offers engineering, construction, project management and other
consulting services for projects involving transmission, distribution or
generation of electric power both domestically and internationally.
AEP has received approval from the SEC under PUHCA to finance up to 50%,
and is seeking approval to finance up to 100%, of its consolidated retained
earnings (approximately $1,500,000,000), 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.
In September 1996, the SEC authorized AEP to invest up to $100,000,000 in
subsidiaries engaged in the business of marketing energy commodities, including
electricity and gas. The SEC also 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. In September 1996,
AEP formed AEPES to market natural gas and consider marketing electric power at
retail where permitted by state law.
In July 1996, AEP Power Marketing, Inc. (AEP Marketing), a wholly-owned
subsidiary of AEP, requested authority from FERC to market electric power at
wholesale at market-based rates. In September, the FERC accepted the filing,
conditioned upon, among other things, that the utility subsidiaries of AEP not
(1) sell nonpower goods or services to any affiliate at a price below its cost
or market price, whichever is higher and (2) purchase nonpower goods or
services from any affiliate at a price above market price. AEP Marketing filed
a request that FERC clarify that this condition only apply to transactions
between utility subsidiaries and AEP Marketing. AEP Marketing 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.
CONSTRUCTION PROGRAM OF OPERATING COMPANIES
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 2000 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 termination
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 until about the year 2002, at
the very earliest. When the time for commitment to specific capacity additions
approaches, all means for adding such capacity, 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 foreseeable
future is highly uncertain.
Proposed Transmission Facilities
APCo: On March 23, 1990, APCo and VEPCo announced plans, subject to
regulatory approval, for major new transmission facilities. APCo will
construct approximately 115 miles of 765,000-volt line from APCo's Wyoming
station in southern West Virginia to APCo's Cloverdale station near Roanoke,
Virginia. VEPCo will construct approximately 102 miles of 500,000-volt line
from APCo's Joshua Falls station east of Lynchburg, Virginia to VEPCo's
Ladysmith station north of Richmond, Virginia. The construction of the
transmission lines and related station improvements will provide needed
reinforcement for APCo's internal load, reinforce the ability to exchange
electric power between the two companies and relieve present constraints on the
transmission of electric power from potential independent power producers in
the APCo service area to VEPCo. APCo's cost is estimated at $245,000,000 while
VEPCo's cost is estimated at $164,000,000. Management estimates that the
project cannot be completed before December 2002, but the actual service date
will be dependent upon the time necessary to meet various regulatory
requirements.
The U.S. Forest Service (Forest Service) is directing the preparation of
an Environmental Impact Statement (EIS) which will be required prior to the
granting of special use permits for crossing Federal lands. On June 18, 1996,
the Forest Service released a Draft EIS. The Forest Service preliminarily
identified a "No Action Alternative" as its preferred alternative. If this
alternative is incorporated in the Final EIS, APCo would not be authorized to
cross the Federally-administered lands of the Forest Service with the proposed
transmission line.
Hearings before the Virginia SCC were concluded in September 1993. A
report was issued by the hearing examiner in December 1993 which recommended
that the Virginia SCC grant APCo approval to construct the proposed
765,000-volt line. In an interim order issued on December 13, 1995, the
Virginia SCC found that major additional transmission capacity was needed to
serve APCo's native load customers. The Virginia SCC further asked that APCo
provide additional information on possible routing modifications and
utilization of the additional transmission capacity prior to a final ruling.
On July 25, 1996, the Virginia SCC issued an order extending indefinitely
the date for filing comments and suspending its proceeding on the transmission
line due to the findings of the Draft EIS. However, the Virginia SCC ordered
APCo to file, on or before December 1, 1996, a proposal detailing its
intentions with regard to meeting the need for major additional transmission
capacity identified in the Virginia SCC's interim order of December 13, 1995.
In APCo's December 1996 filing with the Virginia SCC, APCo reviewed the need
for the project, taking into account the additional transmission improvements
completed after August 1991, and improvements projected to be in service prior
to completion of the proposed project. As part of the review, APCo also
considered the implications of electric utility industry restructuring. Based
on the review and after considering all possible alternatives, APCo concluded
that the need for reinforcement of the transmission system serving its central
and eastern areas remains compelling and that the proposed Wyoming-Cloverdale
project is the most proper alternative for addressing that need. APCo intends
to file an amended application in Virginia.
APCo refiled with the West Virginia PSC in February 1993 its application
for certification. An application filed in June 1992 was withdrawn at the
request of the West Virginia PSC to permit additional time for review by the
West Virginia PSC. The West Virginia PSC rejected APCo's application for
certification in May 1993, directing APCo to supplement its line siting
information. APCo intends to refile its application with the West Virginia
PSC.
Given the findings set forth in the Draft EIS and the preliminary
position of the Forest Service, 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 $5,115,000 and $84,184,000,
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 1994, 1995 and 1996 and their current estimate of 1997
construction expenditures, in each case including AFUDC but excluding nuclear
fuel and other assets acquired under leases. The construction expenditures for
the years 1994-1996 were, and it is anticipated that the estimated construction
expenditures for 1997 will be, approximately:
<TABLE>
<CAPTION>
1994 1995 1996 1997
Actual Actual Actual Estimate
-------- -------- -------- --------
(in thousands)
<S> <C> <C> <C> <C>
AEGCo. . . . . . . . . $ 3,900 $ 4,000 $ 2,200 $ 4,000
APCo . . . . . . . . . 230,300 217,600 192,900 205,000
CSPCo. . . . . . . . . 81,500 99,500 93,600 124,000
I&M. . . . . . . . . . 114,500 113,000 90,500 106,000
KEPCo. . . . . . . . . 53,200 39,300 75,800 72,000
OPCo (a) . . . . . . . 149,000 116,900 113,800 151,800
-------- -------- -------- --------
AEP System (b). . . $642,100 $601,200 $578,000 $672,000
======== ======== ======== ========
</TABLE>
- ----------------
(a) Excludes expenditures associated with flue-gas desulfurization system
which was constructed by a non-affiliate at the Gavin Plant and is being
leased by OPCo. Actual expenditures for such system for 1994, 1995 and
1996 and the current estimate for 1997 are $176,220,000, $48,804,000,
$6,400,000 and $14,000,000, respectively.
(b) 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,
environmental 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 1994, 1995 and 1996 and the current estimate for 1997 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>
1994 1995 1996 1997
Actual Actual Actual Estimate
-------- -------- -------- --------
(in thousands)
<S> <C> <C> <C> <C>
AEGCo. . . . . . . . . $ 0 $ 0 $ 0 $ 0
APCo . . . . . . . . . 32,000 7,800 10,500 6,800
CSPCo. . . . . . . . . 13,700 10,000 1,800 1,900
I&M. . . . . . . . . . 0 0 0 300
KEPCo. . . . . . . . . 9,500 600 0 800
OPCo (a) . . . . . . . 22,400 3,100 1,600 5,900
------- ------- ------- -------
AEP System (a) . . . . $77,600 $21,500 $13,900 $15,700
======= ======= ======= =======
</TABLE>
- ------------------
(a) Excludes expenditures associated with flue-gas desulfurization system
which was constructed by a non-affiliate at the Gavin Plant and is being
leased by OPCo. Actual expenditures for such system for 1994, 1995 and
1996 and the current estimate for 1997 are $176,220,000, $48,804,000,
$6,400,000 and $14,000,000, respectively.
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
purpose of retiring the short-term debt previously incurred. In 1996, AEP
issued 1,600,000 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 1994-1996, external funds from financings and capital
contributions by AEP amounted, with respect to APCo and KEPCo to approximately
40% and 61%, 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, 1997, 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(b) CSPCo I&M(c) KEPCo OPCo(c) System(a)
--------------- ----- ----- ------- ----- ------ ----- ------- ---------
(in millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Amount authorized ...... $150 $80 $227 $175 $175 $150 $223 $1,260
Amount outstanding:
Notes payable ....... $ -- $10 $ -- $ 20 $ 4 $ 34 $ 4 $ 92
Commercial paper .... 42 -- 61 32 40 18 37 228
---- --- ---- ---- ---- ---- ---- ------
$ 42 $10 $ 61 $ 52 $ 44 $ 52 $ 41 $ 320
==== === ==== ==== ==== ==== ==== ======
</TABLE>
- -------------------------
(a) Includes short-term debt of other subsidiaries not shown.
(b) On February 28, 1997, APCo shareholders approved an amendment to APCo's
charter removing a provision limiting APCo's ability to issue
indebtedness. Without this provision, APCo would have been authorized to
issue up to $250 million of short-term debt.
(c) On February 28, 1997, I&M and OPCo shareholders approved amendments to
their respective charters removing provisions limiting their ability to
issue unsecured indebtedness. Without this provision, OPCo would have
been authorized to issue up to $250 million of short-term debt.
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 the respective
short-term debt of the companies at those dates were to remain outstanding for
a twelve-month period at the respective rates of interest prevailing at those
dates, were at least those stated in the following table:
December 31,
--------------------
1994 1995 1996
---- ---- ----
APCo
Mortgage coverage . . . . . . . 3.12 3.47 3.98
Preferred stock coverage . . . 1.65 1.78 1.99
CSPCo
Mortgage coverage . . . . . . . 3.64 3.90 4.44
I&M
Mortgage coverage . . . . . . . 6.23 6.25 6.66
Preferred stock coverage . . . 2.74 2.63 3.07
KEPCo
Mortgage coverage . . . . . . . 2.60 2.86 3.22
OPCo
Mortgage coverage . . . . . . . 5.04 6.17 6.62
Preferred stock coverage . . . 2.58 3.04 3.63
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 use of alternative financing arrangements, if
available, which may be more costly or the curtailment of construction and
other outlays.
AEP's subsidiaries have also utilized, and expect to continue to utilize,
additional financing arrangements, such as leasing arrangements, including the
leasing of utility assets, coal mining and transportation equipment and
facilities and nuclear fuel. Pollution control revenue bonds have been used in
the past and may be used in the future in connection with the construction of
pollution control facilities; however, Federal tax law has limited the
utilization of this type of financing except for purposes of certain financing
of solid waste disposal facilities and of certain refunding of outstanding
pollution control revenue bonds issued before August 16, 1986.
Shares of AEP Common Stock may be sold by AEP from time to time at prices
below the then current book value per share and repurchased by AEP at prices
above book value. Such sales or purchases, if any, would have a dilutive
effect on the book value of then outstanding shares but are not expected to
have a material adverse effect on AEP's business including its future financing
plans or capabilities and pending construction projects.
RATES
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 post-retirement
benefits other than pensions under SFAS 106. FERC action on APCo's
applications is pending.
Virginia: On December 20, 1996, APCo filed an application with the
Virginia SCC to increase its annual fuel factor revenues by approximately
$17,000,000. On January 31, 1997, the Virginia SCC approved APCo's request,
effective February 1, 1997.
West Virginia: Under the terms of a 1993 settlement agreement in the
West Virginia jurisdiction, APCo agreed to a three-year base rate freeze and
suspension of the West Virginia PSC Expanded Net Energy Cost (ENEC) recovery
mechanism until October 31, 1996. 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 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 overrecoveries 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%).
Zimmer Plant -- Rate Recovery: In May 1992, the PUCO issued an order
providing for a phased-in rate increase of $123,000,000 for the Zimmer Plant to
be implemented in three steps over a two-year period and disallowed
$165,000,000 of Zimmer Plant investment. CSPCo appealed the PUCO ordered
Zimmer disallowance and phase-in plan to the Ohio Supreme Court. In November
1993, the Supreme Court issued a decision on CSPCo's appeal affirming the
disallowance and finding that the PUCO did not have statutory authority to
order phased-in rates. The court instructed the PUCO to fix rates to provide
gross annual revenues in accordance with the law and to provide a mechanism to
recover the amounts deferred as regulatory assets under the phase-in
order.
As a result of the Supreme Court decision, in January 1994 the PUCO
approved a 7.11% or $57,167,000 rate increase effective February 1, 1994. The
increase is comprised of a 3.72% base rate increase to complete the rate
increase phase-in and a temporary 3.39% surcharge, which will be in effect
until the phase-in plan deferrals are recovered, estimated to be June 1997. In
1996, 1995 and 1994, $31,500,000, $28,500,000 and $18,500,000, respectively, of
net phase-in deferrals were collected through the surcharge. The deferral
balance was $15,400,000 at December 31, 1996 and $46,900,000 at December 31,
1995. The recovery of amounts deferred under the phase-in plan and the
increase in rates to the full rate level did affect net income since the
deferred costs are amortized commensurate with their recovery.
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.
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 (less Ohio jurisdictional emission allowance gains
currently set at .043 cents per kwh which, commencing on December 1, 1996, are
being returned to customers). After November 2009, the price that OPCo can
recover for coal from its affiliated Meigs mine which supplies the Gavin Plant
will be limited to the lower of cost or the then-current market price. The
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
predetermined 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
$90,000,000 for Meigs, $55,000,000 for Muskingum and $35,000,000 for Windsor,
after tax at December 31, 1996.
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 - Clean Air Act). 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.
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:
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Coal . . . . . . . . . . . . 93% 86% 91% 88% 87%
Nuclear. . . . . . . . . . . 6% 13% 8% 11% 12%
Hydroelectric and other. . . 1% 1% 1% 1% 1%
Variations in the generation of nuclear power are primarily related to
refueling outages and, in 1992, a forced outage at Cook Plant Unit 2. See Cook
Nuclear Plant.
Coal
The Clean Air Act Amendments of 1990 provide for the issuance of annual
allowance allocations covering sulfur dioxide emissions at levels below
historic emission levels for many coal-fired generating units of the AEP
System. Phase I of this program 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 - Clean Air Act 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
3,464 coal hopper cars to be used in unit train movements, as well as 14
towboats, 295 jumbo barges and 184 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>
1992 1993 1994 1995 1996
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Total coal delivered to
AEP operated plants
(thousands of tons) . . . . . 44,738 40,561 49,024 46,867 51,030
Sources (percentage):
Subsidiaries. . . . . . . . . 25% 20% 15% 14% 13%
Long-term contracts . . . . . 65% 66% 65% 75% 71%
Spot or short-term
purchases. . . . . . . . . 10% 14% 20% 11% 16%
Average price per ton of
spot-purchased coal . . . . . $23.88 $23.55 $23.00 $25.15 $23.85
</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>
1992 1993 1994 1995 1996
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Dollars per ton
AEP System Companies . . . . . $34.31 $33.57 $33.95 $32.52 $31.70
AEGCo . . . . . . . . . . . . 20.11 17.74 18.59 18.80 18.22
APCo . . . . . . . . . . . . . 43.00 42.65 39.89 38.86 37.60
CSPCo . . . . . . . . . . . . 33.87 33.87 32.80 33.23 31.70
I&M . . . . . . . . . . . . . 24.23 23.80 22.85 23.25 22.99
KEPCo. . . . . . . . . . . . . 30.24 27.08 26.83 26.91 27.25
OPCo . . . . . . . . . . . . . 38.36 38.12 41.10 37.58 35.96
Cents per Million Btu's
AEP System Companies . . . . . 154.41 150.89 152.41 145.26 140.48
<cents> <cents> <cents> <cents> <cents>
AEGCo. . . . . . . . . . . . . 120.90 107.71 112.06 112.87 109.25
<cents> <cents> <cents> <cents> <cents>
APCo . . . . . . . . . . . . . 173.05 173.32 161.37 156.96 152.54
<cents> <cents> <cents> <cents> <cents>
CSPCo. . . . . . . . . . . . . 143.94 143.66 140.45 140.79 134.60
<cents> <cents> <cents> <cents> <cents>
I&M. . . . . . . . . . . . . . 135.11 129.39 123.62 125.50 121.16
<cents> <cents> <cents> <cents> <cents>
KEPCo. . . . . . . . . . . . . 126.92 113.90 113.40 114.77 114.42
<cents> <cents> <cents> <cents> <cents>
OPCo . . . . . . . . . . . . . 163.89 161.25 173.51 157.62 151.55
<cents> <cents> <cents> <cents> <cents>
</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, 1996, the
System's coal inventory was approximately 45 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 1996 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 1996 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
Estimated Require- of Delivered Coal
Total Consumption ments for Remainder ----------------------------
During 1996 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) . . . . . 5,091 257 0.3% 0.8
APCo. . . . . . . . 10,743 434 0.8% 1.3
CSPCo (b) . . . . . 5,859 226 2.8% 4.8
I&M (c) . . . . . . 6,975 296 0.8% 1.6
KEPCo . . . . . . . 2,425 89 1.2% 1.9
OPCo . . . . . . . 20,473 658 2.3% 3.8
</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 ofthe 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 1996, 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 3,500,000 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 55,335,543 tons expires
on December 31, 2014 and another contract with remaining deliveries of
49,005,000 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 2,500,000 tons of
coal in 1997. 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 205,000,000 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 105,000,000
tons of clean recoverable coal ranging in sulfur content between 1.4% and 3.3%
sulfur by weight (weighted average, 2.0%) of which approximately 28,000,000
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 currently are
being taken, based upon the planned fuel cycles for the Cook Plant, to review
and evaluate I&M's requirements for the supply of nuclear fuel. 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
$71,124,000, exclusive of interest of $100,622,000 at December 31, 1996. 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 debt 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
disposal 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.
Studies completed in 1994 estimate decommissioning and low-level
radioactive waste disposal costs for the Cook Plant to range from $634,000,000
to $988,000,000 in 1993 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 $27,000,000 in 1996, $30,000,000 in 1995 (including $4,000,000
in special deposits) and $26,000,000 in 1994. At December 31, 1996, I&M had
recognized a decommissioning liability of $313,845,000. 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 and (e) the technology available
at the time of decommissioning differing significantly from that assumed in
these studies. Accordingly, management is unable to provide assurance that the
ultimate cost of decommissioning the Cook Plant will not be significantly
greater than current projections.
In February 1996, the Financial Accounting Standards Board (FASB) issued
an exposure draft entitled Accounting for Certain Liabilities Related to
Closure or Removal of Long-Lived Assets. I&M generally records such
liabilities over the life of its plant commensurate with rate recovery. The
exposure draft proposes that the present value of decommissioning and certain
other closure or removal obligations be recorded as a liability when the
obligation is incurred. A corresponding asset would be recorded in the plant
investment account and recovered through depreciation charges over the asset's
life. A proposed transition rule would require that an entity report in income
the cumulative effect of initially applying the new standard. However, as a
cost-based rate-regulated entity, I&M would expect to record a corresponding
regulatory asset for the cumulative effect of initially applying the new
standard. The FASB is reconsidering several aspects of the exposure draft. It
is unclear at this time what, if any, changes the FASB will make to the
proposal. Until it becomes apparent what the FASB will decide and how certain
questions raised by the exposure draft are resolved, I&M cannot determine its
ultimate impact.
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. The bill is expected to be reintroduced in
1997. Development of required legislation and progress 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. Currently, the
Cook Plant produces less than 1,500 cubic feet of low-level waste annually.
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 $42,743,000, subject to inflation adjustments,
and is payable in annual assessments over the next 10 years. I&M recorded a
regulatory asset concurrent with the recording of the liability. The payments
are being recorded and recovered as fuel expense.
In a case involving an unaffiliated utility, the U.S. Court of Federal
Claims decided in June 1995 that these assessments are unlawful. On November
13, 1995, the Federal Government appealed this decision to the U.S. Court of
Appeals for the Federal Circuit. I&M has filed with DOE claims for refunds
under certain of its enrichment services contracts based on this decision. I&M
also intends to pursue refund claims on other enrichment services contracts
directly to the U.S. Court of Federal Claims.
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, in the long term, 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
Clean Air Act: For the AEP System, compliance with the Clean Air Act
(CAA) is requiring substantial expenditures which generally are being recovered
through increases in the rates of AEP's operating subsidiaries. OPCo is
incurring a major portion of such costs. There can be no assurance that all
such costs will be recovered. See Construction Program of Operating Companies
- -- Construction Expenditures.
The Acid Rain Program (Title IV) provisions of the Clean Air Act
Amendments of 1990 (CAAA) create an emission allowance program pursuant to
which utilities are authorized to emit a designated quantity of sulfur dioxide,
measured in tons per year, on a system wide or aggregate basis. Emission
reductions are required by virtue of the establishment of annual allowance
allocations at a level below historical emission levels for many utility units.
Effective January 1, 1995, Title IV of the CAAA established Phase I sulfur
dioxide allowance limitations (caps or ceilings on emissions) for certain units
that emitted sulfur dioxide above a rate of 2.5 pounds per million Btu heat
input in 1985, premised upon sulfur dioxide emissions at a rate of 2.5 pounds
per million Btu heat input at 1985 utilization levels. The following AEP
System units are Phase I-affected units: I&M's Tanners Creek Unit 4; CSPCo's
Beckjord Unit 6, Conesville Units 1-4, Picway Unit 5 and Stuart Units 1-4; and
OPCo's Gavin Units 1-2, Muskingum River Units 1-5, Cardinal Unit 1, Mitchell
Units 1-2 and Kammer Units 1-3. Phase I permits have been issued for all Phase
I-affected units in the AEP System.
All fossil fuel-fired steam generating units with capacity greater than
25 megawatts are affected in Phase II of the Acid Rain program. All Phase
II-affected units are allocated allowances with which compliance must be
accomplished beginning January 1, 2000. The basis for Phase II allowance
allocation depends on 1985 sulfur dioxide emission rates -- if a unit emitted
sulfur dioxide in 1985 at a rate in excess of 1.2 pounds per million Btu heat
input, the allowance allocation is premised upon an emission rate of 1.2 pounds
at 1985 utilization levels. If a unit emitted sulfur dioxide in 1985 at a rate
of less than 1.2 pounds, the allowance allocation is in most instances premised
upon the actual 1985 emission rate.
Title IV also contains provisions governing nitrogen oxides (NOx)
emissions. 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 in the Federal Register for wet bottom wall-fired
boilers, cyclone boilers, units applying cell burner technology and all other
types of boilers. These emission limitations are to be achieved by January 1,
2000. A petition for review of the regulations was filed by a number of
utilities, including AEP System operating companies, in the U.S. Court of
Appeals for the District of Columbia Circuit on December 26, 1996.
The CAA contains additional provisions, other than the Acid Rain Program,
which could require reductions in emissions of nitrogen oxides from fossil
fuel-fired power plants. Title I, dealing generally with attainment of
federally set National Ambient Air Quality Standards, establishes a tiered
system for classifying degrees of non-attainment with the air quality standard
for ozone. Depending upon the severity of non-attainment within a given
non-attainment area, reductions in nitrogen oxides emissions from fossil
fuel-fired power plants may be required as part of a state's plan for achieving
attainment with the ozone air quality standard. While ozone non-attainment is
largely restricted to urban areas, AEP System generating units could be
determined to be affecting ozone concentrations and may therefore, eventually
be required to reduce nitrogen oxides emissions pursuant to Title I.
In addition, certain environmental organizations and states have taken
the position that nitrogen oxides emissions from the midwest must be reduced in
order to achieve the air quality standard for ozone in the northeast as well as
the Lake Michigan and Atlanta, Georgia areas. All AEP coal-fired plants are
potentially subject to the imposition of additional emission controls resulting
from these initiatives. The Environmental Council of States formed the Ozone
Transport Assessment Group (OTAG) in early 1995 to develop estimates of levels
of reduction in volatile organic compound and/or nitrogen oxides emissions
required for significant reductions in ozone concentrations in the eastern
United States. OTAG, consisting of the environmental commissioners and air
directors of 37 eastern states, Federal EPA and representatives from
environmental and industry groups, is currently scheduled to complete modeling
and technical work by the spring of 1997 with evaluation of technical findings
and recommendations on regional emission controls to be submitted to Federal
EPA in the summer of 1997. Federal EPA published a notice of intent in the
January 10, 1997 Federal Register proposing the specification of ranges or
amounts of nitrogen oxides and volatile organic compounds reductions required
by states to reduce downwind concentrations of ozone. Federal EPA will direct
states to revise their state implementation plans (SIPs) to provide for
specified emission reductions within a set time period. Federal EPA's proposal
for reductions of nitrogen oxides and volatile organic compounds is scheduled
to be issued in March 1997 and final SIP calls requiring revisions in state
plans will be issued in the summer of 1997. The cost of meeting Nox emissions
reduction requirements which might be imposed to achieve the ozone ambient air
quality standard cannot be precisely predicted but could be substantial.
Utility boilers are potentially subject to additional control
requirements under Title III of the CAAA governing hazardous air pollutant
emissions. Federal EPA is directed to conduct studies concerning the potential
public health impacts of pollutants identified by the legislation as hazardous
in connection with their emission from electric utility steam generating units.
Federal EPA was required to report the results of this study to Congress by
November 1993 and is required to regulate emissions of these pollutants from
electric utility steam generating units if it is determined that such
regulation is necessary and appropriate, based on the results of the study. In
October 1996, Federal EPA submitted to Congress an interim report that did not
make any determinations regarding additional regulation of electric utilities.
Additionally, Federal EPA is directed to study the deposition of hazardous
pollutants to the Great Lakes, the Chesapeake Bay, Lake Champlain and other
coastal waters. As part of this assessment, Federal EPA is authorized to adopt
regulations to prevent serious adverse effects to public health and serious or
widespread environmental effects. It is possible that emissions from electric
utility steam generating units may be regulated under this water body
deposition assessment program.
The CAAA expand the enforcement authority of the Federal government by
increasing the range of civil and criminal penalties for violations of the
Clean Air Act and enhancing administrative civil provisions, adding a citizen
suit provision and imposing a national operating permit system, emission fee
program and enhanced monitoring, record keeping and reporting requirements for
existing and new sources. On February 13, 1997, Federal EPA issued a
regulation providing for the use of any credible evidence or information in
lieu of, or in addition to, test methods prescribed by regulation to determine
the compliance status of permitted sources of air pollution. This rule may
effectively make emission limits previously adopted for many air emission
sources including those of the AEP System's operating subsidiaries more
stringent. On March 10, 1997, a group of utilities, including AEP System
operating companies, filed a petition for review of these regulations in the
U.S. Court of Appeals for the District of Columbia Circuit.
Global Climate Change: Increasing concentrations of "greenhouse gases,"
including carbon dioxide (CO2), in the atmosphere have led to concerns about
the potential for the earth's climate to change in ways that could result in
adverse human health effects, destruction of sensitive ecosystems, inundated
low-lying areas caused by sea-level rise, shifts in agricultural production and
other serious environmental consequences. The proponents of this view maintain
that rising levels of greenhouse gas emissions will cause some of the sun's
energy that is normally radiated back into space to be trapped in the
atmosphere, warming the biosphere and triggering these detrimental effects.
At the Earth Summit in Rio de Janeiro, Brazil in June 1992, 165 nations,
including the United States, signed a global climate change treaty. Each
country that ratifies the treaty commits itself to a process of achieving the
aim of reducing greenhouse gas emissions, including CO2, to their 1990 level by
the year 2000. On October 7, 1992, the U.S. Senate ratified the treaty. The
treaty went into effect on March 21, 1994. In April 1995, the first meeting of
the nations that have ratified was held. The parties declared that the
existing commitments under the treaty are not adequate to address the threat of
global climate change and authorized the immediate commencement of negotiations
on a protocol or other legal instrument for emission controls in the post-2000
period. The protocol or other legal instrument is required to set forth
"policies and measures," and "quantified limitation and reduction objectives
within specified time frames, such as 2005, 2010 and 2020" to be adopted by
signatory nations. The parties will meet in December 1997 in Kyoto, Japan to
finalize the agreement.
On January 17, 1997, the U.S. government submitted text for a proposed
treaty that would establish a future system of legally binding emission budgets
with trading of emission credits between nations that are parties to the new
agreement and which have emission control obligations. Although the U.S.
proposal does not specify either the level of emission reductions or timeframe
in which they must be achieved, it is expected to result in at least a cap on
greenhouse gas emissions at the level emitted in the year 1990.
In accordance with the obligations set forth in the global climate change
treaty, on April 21, 1993, President Clinton committed the United States to
reducing greenhouse gas emissions to 1990 levels by the year 2000. On October
19, 1993, the President unveiled the Administration's Climate Change Action
Plan for meeting this emission reduction target. The plan emphasizes
reductions in fossil fuel use, the largest source of CO2 emissions, primarily
through reliance on voluntary energy efficiency programs and partnerships
between the Federal government and U.S. industry. One such collaboration is
between the electric utility industry and DOE. Known as the Climate Challenge,
this initiative has identified flexible, cost-effective measures to reduce,
avoid or sequester future greenhouse gas emissions. AEP System companies
joined with nearly 800 investor-owned, municipal, rural electric cooperative
and Federal utilities in a voluntary agreement signed with DOE on April 20,
1994 that has led to individual utility Participation Accords resulting in
substantial reductions in future greenhouse gas emissions. On February 3,
1995, the AEP System entered into its Climate Challenge Participation Accord
with DOE. The Accord contains a diverse portfolio of supply-side, demand-side
and forest management/tree planting activities that will be undertaken on the
AEP System between now and the year 2000 with a projected reduction in CO2
emissions of 9,550,000 tons from what would have otherwise been emitted but for
these actions.
As a result of the AEP System's historical practice of using low-cost
indigenous coal supplies to produce electricity, AEP System power plants are
significant sources of CO2 emissions. Management is working to support further
efforts to properly study the issue of global climate change to define the
extent, if any, to which it poses a threat to the environment. Management is
concerned that new laws may be passed or new regulations promulgated without
sufficient scientific study and support.
Since the AEP System is a major emitter of carbon dioxide, its financial
condition and results of operations could be materially adversely affected by
the imposition of limitations on CO2 emissions if the compliance costs incurred
are not fully recovered from ratepayers. In addition, any such severe program
to stabilize or reduce CO2 emissions could impose substantial costs on industry
and society and seriously erode the economic base that AEP's operations serve.
West Virginia: West Virginia promulgated sulfur dioxide limitations
which Federal EPA approved in February 1978. The emission limitations for the
Mitchell Plant have been approved by Federal EPA for primary ambient air
quality (health-related) standards only. West Virginia is obliged to reanalyze
sulfur dioxide emission limits for the Mitchell Plant with respect to secondary
ambient air quality (welfare-related) standards. Because the Clean Air Act
provides no specific deadline for approval of emission limits to achieve
secondary ambient air quality standards, it is not certain when Federal EPA
will take dispositive action regarding the Mitchell Plant.
West Virginia has had a request to increase the sulfur dioxide emission
limitation for Kammer pending before Federal EPA for many years, although the
change has not been acted upon by Federal EPA. On August 4, 1994, however,
Federal EPA issued a Notice of Violation to OPCo alleging that Kammer Plant was
operating in violation of the applicable federally enforceable sulfur dioxide
emission limit. 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 sulfur dioxide per million Btu actual heat input on a three-hour
basis and 5.8 pounds of sulfur dioxide 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 sulfur
dioxide 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.
Stack Height Regulations: On June 27, 1985, Federal EPA issued stack
height regulations pursuant to an order of the United States Court of Appeals
for the District of Columbia Circuit. These regulations were appealed by a
number of states, environmental groups and investor-owned electric utilities
(including APCo, CSPCo, I&M, KEPCo and OPCo), along with three electric utility
trade associations. OPCo also filed a separate petition for review to raise
issues unique to its Kammer Plant. Various petitions for reconsideration filed
with and denied by Federal EPA were also appealed. This litigation was
consolidated into a single case.
On January 22, 1988, the U.S. Court of Appeals for the District of
Columbia Circuit issued a decision in part upholding the June 1985 stack height
rules and remanding certain of the June 1985 rules to Federal EPA for further
consideration. With respect to Kammer Plant, the January 1988 court decision
rejected OPCo's appeal, holding that Federal EPA acted lawfully in revoking
stack height credit previously granted for Kammer Plant in October 1982. OPCo
has also commenced administrative proceedings with the State of West Virginia
and Federal EPA in an effort to preserve stack height credit for Kammer Plant.
While it is not possible to state with particularity the ultimate impact
of the final rules on AEP System operations, at present it appears that the
most likely AEP System plants at which the final rules could possibly result in
more stringent emission limitations are CSPCo's Conesville Plant, AEGCo's and
I&M's Rockport Plant, I&M's Tanners Creek Plant and OPCo's Gavin and Kammer
plants. Gavin and Rockport plants were not affected by Federal EPA's stack
height rules as issued in June 1985. However, the provision exempting these
plants was remanded to Federal EPA in the January 1988 court decision.
Accordingly, the ultimate impact of the stack height rules on Gavin and
Rockport plants will not be known until Federal EPA completes administrative
proceedings on remand and reissues final stack height rules. OPCo and AEGCo
and I&M intend to participate in the remand rulemaking affecting Gavin and
Rockport plants, respectively.
State air pollution control agencies are required to implement the stack
height rules by revising emission limitations for sources subject to the rules
and submitting such revisions to Federal EPA.
On June 1, 1989, Ohio EPA adopted a rule concerning CSPCo's Conesville
Plant in response to Federal EPA's stack height rules adopted in 1985. Under
Federal EPA policy published in January 1988, emission reductions required by
the stack height rules may be obtained at plants other than the plant directly
affected by the rules, and thereafter credited to the directly affected plant.
Under Ohio EPA's June 1, 1989 rule, the sulfur dioxide emission limitations for
Conesville Units 5 and 6 remain at 1.2 pounds sulfur dioxide per million Btu
heat input as long as the emission rate at CSPCo's retired Poston Units 1-4
remains at 0.0 pounds sulfur dioxide per million Btu heat input. Federal EPA
has yet to take action concerning Ohio EPA's June 1, 1989 rule.
Administrative Developments Regarding Sulfur Dioxide: On November 15,
1994, Federal EPA published a notice in the Federal Register proposing to
retain the present 24-hour national ambient air quality standard for sulfur
dioxide. Federal EPA also sought comment on the need to adopt additional
regulations to address short-term peak exposures to sulfur dioxide. On January
2, 1997, Federal EPA proposed a new intervention level program under the
authority of Section 303 of the Clean Air Act to address high five-minute peak
SO2 concentrations. The proposal calls for regulatory intervention to reduce
emissions from a source or group of sources responsible for five-minute peak
SO2 concentrations above prescribed levels. The effect on AEP operations of
Federal EPA's proposed intervention level program for further regulating sulfur
dioxide emissions, if finalized, cannot be predicted, but may be significant.
Life Extension: On July 21, 1992, Federal EPA published final
regulations in the Federal Register governing application of new source rules
to generating plant repairs and pollution control projects undertaken to comply
with the Clean Air Act Amendments of 1990. Generally, the rule provides that
plants undertaking pollution control projects will not trigger new source
review requirements. The Natural 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.
National Ambient Air Quality Standards: Federal EPA proposed revisions
to the National Ambient Air Quality Standard for ozone on December 13, 1996.
The proposed standard is significantly more stringent than the current standard
and, if adopted, would result in redesignation of many areas currently
designated attainment. The proposal, if adopted, could lead to substantial
reductions in allowable nitrogen oxide emissions from System power plants.
Federal EPA also proposed revision of the National Ambient Air Quality
Standard for particulate matter (PM) on December 13, 1996. Federal EPA's
proposed revision would add a standard for particulate matter below 2.5 microns
in size (PM2.5). Federal EPA is required by court order to make a final
determination on this issue by July 19, 1997. The new PM2.5 standard, if
finalized, could lead to substantial reductions in allowable emissions of SO2,
nitrogen oxides and particulate matter from System power plants.
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
applications are being prepared or have been filed for renewal of NPDES permits
which expire in 1997.
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 curtailment
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, antidegradation 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.
Hazardous Substances and Wastes
Section 311 of the Clean Water Act imposes substantial penalties for
spills of Federal EPA-listed hazardous substances into water and for failure to
report such spills. The Comprehensive Environmental Response, Compensation,
and Liability Act (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 PCB's 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
environmental 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. Seven AEP System companies are identified as Potentially Responsible
Parties (PRPs) for six additional federal sites, including CSPCo, KEPCo and
Wheeling Power Company at one site each, I&M at two 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 1998. Until that
time, these low volume wastes are provisionally excluded from regulation under
the hazardous waste provisions of RCRA. All presently generated hazardous
waste is being disposed of at permitted off-site facilities in compliance with
applicable Federal and state laws and regulations. For System facilities which
generate such wastes, System companies have filed the requisite notices and are
complying with RCRA and applicable state regulations for generators. Nuclear
waste produced at the Cook Plant 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, or being used in household
wiring and appliances.
A number of studies in the past several years have examined the
possibility of adverse health effects from EMF. While some of the
epidemiological studies have indicated some association between exposure to EMF
and health effects, the majority of studies have indicated no such association.
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 conclusion of the
committee is that the current body of evidence does not show that exposure to
these fields presents a human health hazard..." The epidemiological 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.
Federal EPA is currently studying whether exposure to EMF is associated
with cancer in humans. In 1990, Federal EPA issued a draft report on EMF,
received interagency review and public comment, and is in the process of
preparing its final report. A December 1992 brochure from Federal EPA,
Questions And Answers About Electric And Magnetic Fields (EMFs), states at page
3, "The bottom line is that there is no established cause and effect
relationship between EMF exposure and cancer or other disease."
The Energy Policy Act of 1992 established a coordinated Federal EMF
research program. The program funding is $65,000,000 over five years, half of
which is to be provided by private parties including utilities. AEP has
committed to contribute $446,571 over the five-year period. AEP 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 1996. 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. The trial date has been set at August 18, 1997.
Some states have enacted regulations to limit the strength of magnetic
fields at the edge of transmission line rights-of-way. No state which the AEP
System serves has done so. In March 1993, The Ohio Power Siting Board issued
its amended rules providing for additional consideration of the possible
effects of EMF in the certification of electric transmission facilities. Under
the amended EMF rules, persons seeking approval to build electric transmission
lines have to provide estimates of EMF from transmission lines under a variety
of conditions. In addition, applicants are required to address possible health
effects and discuss the consideration of design alternatives with respect to
EMF.
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,
including load management.
AEP System operating companies are members of the Electric Power Research
Institute (EPRI), a nonprofit organization that manages research and
development on behalf of the U.S. electric utility industry. EPRI, founded in
1973, manages technical research and development programs for its members to
improve power production, delivery and use. Approximately 700 utilities are
members. Total AEP dues to EPRI were $9,900,000 for 1996, $9,600,000 for 1995
and $3,200,000 for 1994.
Total research and development expenditures by AEP and its subsidiaries,
including EPRI dues, were approximately $16,400,000 for the year ended December
31, 1996, $13,600,000 for the year ended December 31, 1995 and $7,600,000 for
the year ended December 31, 1994. This includes expenditures of $3,300,000 for
1996, $1,100,000 for 1995 and $2,200,000 for 1994 related to pressurized
fluidized-bed combustion, a process in which sulfur is removed during coal
combustion and nitrogen oxide formation is minimized.
Item 2. PROPERTIES
- ------------------------------------------------------------------------------
At December 31, 1996, subsidiaries of AEP owned (or leased where
indicated) generating plants with the net power capabilities (winter rating)
shown in the following table:
<TABLE>
<CAPTION>
Net Kilowatt
Owner, Plant Type and Name Location (Near) Capability
-------------------------- --------------- ------------
<S> <C> <C>
AEP Generating Company:
Steam -- Coal-Fired:
Rockport Plant (AEGCo share) Rockport, Indiana 1,300,000(a)
Appalachian Power Company:
Steam -- Coal-Fired:
John E. Amos, Units 1 & 2 St. Albans, West Virginia 1,600,000
John E. Amos, Unit 3 (APCo share) St. Albans, West Virginia 433,000(b)
Clinch River Carbo, Virginia 705,000
Glen Lyn Glen Lyn, Virginia 335,000
Kanawha River Glasgow, West Virginia 400,000
Mountaineer New Haven, West Virginia 1,300,000
Philip Sporn, Units 1 & 3 New Haven, West Virginia 308,000
Hydroelectric -- Conventional:
Buck Ivanhoe, Virginia 10,000
Byllesby Byllesby, Virginia 20,000
Claytor Radford, Virginia 76,000
Leesville Leesville, Virginia 40,000
London Montgomery, West Virginia 16,000
Marmet Marmet, West Virginia 16,000
Niagara Roanoke, Virginia 3,000
Reusens Lynchburg, Virginia 12,000
Winfield Winfield, West Virginia 19,000
Hydroelectric -- Pumped Storage:
Smith Mountain Penhook, Virginia 565,000
---------
5,858,000
---------
Columbus Southern Power Company:
Steam -- Coal-Fired:
Beckjord, Unit 6 New Richmond, Ohio 53,000(c)
Conesville, Units 1-3, 5 & 6 Coshocton, Ohio 1,165,000
Conesville, Unit 4 Coshocton, Ohio 339,000(c)
Picway, Unit 5 Columbus, Ohio 100,000
Stuart, Units 1-4 Aberdeen, Ohio 608,000(c)
Zimmer Moscow, Ohio 330,000(c)
---------
2,595,000
---------
Indiana Michigan Power Company:
Steam -- Coal-Fired:
Rockport Plant (I&M share) Rockport, Indiana 1,300,000(a)
Tanners Creek Lawrenceburg, Indiana 995,000
Steam -- Nuclear:
Donald C. Cook Bridgman, Michigan 2,110,000
Gas Turbine:
Fourth Street Fort Wayne, Indiana 18,000(d)
Hydroelectric -- Conventional:
Berrien Springs Berrien Springs, Michigan 3,000
Buchanan Buchanan, Michigan 2,000
Constantine Constantine, Michigan 1,000
Elkhart Elkhart, Indiana 1,000
Mottville Mottville, Michigan 1,000
Twin Branch Mishawaka, Indiana 3,000
---------
4,434,000
---------
Kentucky Power Company:
Steam -- Coal-Fired:
Big Sandy Louisa, Kentucky 1,060,000
---------
Ohio Power Company:
Steam -- Coal-Fired:
John E. Amos, Unit 3 (OPCo share) St. Albans, West Virginia 867,000(b)
Cardinal, Unit 1 Brilliant, Ohio 600,000
General James M. Gavin Cheshire, Ohio 2,600,000(e)
Kammer Captina, West Virginia 630,000
Mitchell Captina, West Virginia 1,600,000
Muskingum River Beverly, Ohio 1,425,000
Philip Sporn, Units 2, 4 & 5 New Haven, West Virginia 742,000
Hydroelectric -- Conventional:
Racine Racine, Ohio 48,000
----------
8,512,000
----------
Total Generating Capability . . . . . . . 23,759,000
==========
Summary:
Total Steam --
Coal-Fired . . . . . . . . . . . . . . . . . . . . . . . . . 20,795,000
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . 2,110,000
Total Hydroelectric --
Conventional . . . . . . . . . . . . . . . . . . . . . . . . 271,000
Pumped Storage . . . . . . . . . . . . . . . . . . . . . . . 565,000
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,000
----------
Total Generating Capability . . . . . . . 23,759,000
- ----------------- ==========
</TABLE>
(a) Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by
I&M. Unit 2 of the Rockport Plant is leased one-half by AEGCo and
one-half by I&M. The leases terminate in 2022 unless extended.
(b) Unit 3 of the John E. Amos Plant is owned one-third by APCo and
two-thirds by OPCo.
(c) Represents CSPCo's ownership interest in generating units owned in common
with CG&E and DP&L.
(d) Leased from the City of Fort Wayne, Indiana. Since 1975, I&M has leased
and operated the assets of the municipal system of the City of Fort
Wayne, Indiana under a 35-year lease with a provision for an additional
15-year extension at the election of I&M.
(e) The scrubber facilities at the Gavin Plant are leased. The lease
terminates in 2010 unless extended.
See Item 1 under Fuel Supply, for information concerning coal reserves
owned or controlled by subsidiaries of AEP.
The following table sets forth the total circuit miles of transmission
and distribution lines of the AEP System, APCo, CSPCo, I&M, KEPCo and OPCo and
that portion of the total representing 765,000-volt lines:
Total Circuit Miles
of Transmission and Circuit Miles of
Distribution Lines 765,000-volt Lines
------------------- ------------------
AEP System (a) . . . . . . 127,376(b) 2,022
APCo . . . . . . . . . . . 49,282 641
CSPCo (a). . . . . . . . . 15,000 ---
I&M. . . . . . . . . . . . 20,795 614
KEPCo. . . . . . . . . . . 10,025 258
OPCo . . . . . . . . . . . 28,826 509
- ------------------
(a) Includes 766 miles of 345,000-volt jointly owned lines.
(b) Includes lines of other AEP System companies not shown.
TITLES
The AEP System's electric generating stations are generally located on
lands owned in fee simple. The greater portion of the transmission and
distribution lines of the System has been constructed over lands of private
owners pursuant to easements or along public highways and streets pursuant to
appropriate statutory authority. The rights of the System in the realty on
which its facilities are located are considered by it to be adequate for its
use in the conduct of its business. Minor defects and irregularities
customarily found in title to properties of like size and character may exist,
but such defects and irregularities do not materially impair the use of the
properties affected thereby. System companies generally have the right of
eminent domain whereby they may, if necessary, acquire, perfect or secure
titles to or easements on privately-held lands used or to be used in their
utility operations.
Substantially all the physical properties of APCo, CSPCo, I&M, KEPCo and
OPCo are subject to the lien of the mortgage and deed of trust securing the
first mortgage bonds of each such company.
SYSTEM TRANSMISSION LINES AND FACILITY SITING
Legislation in the states of Indiana, Kentucky, Michigan, Ohio, Virginia,
and West Virginia requires prior approval of sites of generating facilities
and/or routes of high-voltage transmission lines. Delays and additional costs
in constructing facilities have been experienced as a result of proceedings
conducted pursuant to such statutes, as well as in proceedings in which
operating companies have sought to acquire rights-of-way through condemnation,
and such proceedings may result in additional delays and costs in future years.
PEAK DEMAND
The AEP System is interconnected through 120 high-voltage transmission
interconnections with 29 neighboring electric utility systems. The all-time
and 1996 one-hour peak System demands were 25,940,000 and 24,373,000 kilowatts,
respectively (which included 7,314,000 and 4,136,000 kilowatts, respectively,
of scheduled deliveries to unaffiliated systems which the System might, on
appropriate notice, have elected not to schedule for delivery) and occurred on
June 17, 1994 and February 5, 1996, respectively. The net dependable capacity
to serve the System load on such date, including power available under
contractual obligations, was 23,457,000 and 23,765,000 kilowatts, respectively.
The all-time and 1996 one-hour internal peak demand was 19,557,000, and
occurred on February 5, 1996. The net dependable capacity to serve the System
load on such date, including power dedicated under contractual arrangements,
was 23,765,000 kilowatts. The all-time one-hour integrated and internal net
system peak demands and 1996 peak demands for AEP's generating subsidiaries are
shown in the following tabulation:
All-time one-hour integrated 1996 one-hour integrated
net system peak demand net system peak demand
---------------------------- --------------------------
(in thousands)
Number of Number of
Kilowatts Date Kilowatts Date
--------- ---------------- --------- ----------------
APCo 8,303 January 17, 1997 8,214 February 5, 1996
CSPCo 4,172 June 17, 1994 4,045 July 19, 1996
I&M 5,027 June 17, 1994 4,899 July 19, 1996
KEPCo 1,711 January 17, 1997 1,686 February 5, 1996
OPCo 7,291 June 17, 1994 6,766 May 17, 1996
All-time one-hour integrated 1996 one-hour integrated
net internal peak demand net internal peak demand
---------------------------- --------------------------
(in thousands)
Number of Number of
Kilowatts Date Kilowatts Date
--------- ---------------- --------- ----------------
APCo 6,908 February 5, 1996 6,908 February 5, 1996
CSPCo 3,378 August 14, 1995 3,335 August 7, 1996
I&M 3,879 August 7, 1996 3,879 August 7, 1996
KEPCo 1,418 February 5, 1996 1,418 February 5, 1996
OPCo 5,641 August 14, 1995 5,547 August 7, 1996
HYDROELECTRIC PLANTS
Licenses for hydroelectric plants, issued under the Federal Power Act,
reserve to the United States the right to take over the project at the
expiration of the license term, to issue a new license to another entity, or to
relicense the project to the existing licensee. In the event that a project is
taken over by the United States or licensed to a new licensee, the Federal
Power Act provides for payment to the existing licensee of its "net investment"
plus severance damages. Licenses for six System hydroelectric plants expired
in 1993. Four new licenses were issued in 1994 and two were issued in 1996.
The license for the hydroelectric plant at Elkhart, Indiana expires in 2000.
In 1995, a notice of intent to relicense the Elkhart project was filed.
COOK NUCLEAR PLANT
Unit 1 of the Cook Plant, which was placed in commercial operation in
1975, has a nominal net electric rating of 1,020,000 kilowatts. Unit 1's
availability factor was 97.6% during 1996 and 66.3% during 1995. Unit 2, of
slightly different design, has a nominal net electrical rating of 1,090,000
kilowatts and was placed in commercial operation in 1978. Unit 2's
availability factor was 87.0% during 1996 and 94.4% during 1995. Outages to
refuel affected the availability of Unit 1 in 1995 and Unit 2 in 1996.
Units 1 and 2 are licensed by the NRC to operate at 100% of rated thermal
power to October 25, 2014 and December 23, 2017, respectively.
Costs associated with the operation, maintenance and retirement of
nuclear plants continue to be significant and less predictable than costs
associated with other sources of generation, in large part due to changing
regulatory requirements and safety standards and experience gained in the
construction and operation of nuclear facilities. I&M may also incur costs and
experience reduced output at its Cook Plant because of the design criteria
prevailing at the time of construction and the age of the plant's systems and
equipment. In addition, for economic or other reasons, operation of the Cook
Plant for the full term of its now assumed life cannot be assured. Nuclear
industry-wide and Cook Plant initiatives have contributed to slowing the growth
of operating and maintenance costs. However, the ability of I&M to obtain
adequate and timely recovery of costs associated with the Cook Plant, including
replacement power and retirement costs, is not assured.
Nuclear Incident Liability
The Price-Anderson Act limits public liability for a nuclear incident at
any licensed reactor in the United States to $8.9 billion. I&M has insurance
coverage for liability from a nuclear incident at its Cook Plant. Such
coverage is provided through a combination of private liability insurance, with
the maximum amount available of $200,000,000, and mandatory participation for
the remainder of the $8.9 billion liability, in an industry retrospective
deferred premium plan which would, in case of a nuclear incident, assess all
licensees of nuclear plants in the U.S. Under the deferred premium plan, I&M
could be assessed up to $158,600,000 payable in annual installments of
$20,000,000 in the event of a nuclear incident at Cook or any other nuclear
plant in the U.S. There is no limit on the number of incidents for which I&M
could be assessed these sums.
I&M also has property damage, decontamination and decommissioning
insurance for loss resulting from damage to the Cook Plant facilities in the
amount of $3.6 billion. Energy Insurance Bermuda (EIB), Nuclear Mutual Limited
(NML) and Nuclear Electric Insurance Limited (NEIL) provide $2.75 billion of
coverage and nuclear insurance pools provide the remainder. If EIB's, NML's
and NEIL's losses exceed their available resources, I&M would be subject to a
total retrospective premium assessment of up to $26,900,000. NRC regulations
require that, in the event of an accident, whenever the estimated costs of
reactor stabilization and site decontamination exceed $100,000,000, the
insurance proceeds must be used, first, to return the reactor to, and maintain
it in, a safe and stable condition and, second, to decontaminate the reactor
and reactor station site in accordance with a plan approved by the NRC. The
insurers then would indemnify I&M for property damage up to $3.35 billion less
any amounts used for stabilization and decontamination. The remaining
$250,000,000, as provided by NEIL (reduced by any stabilization and
decontamination expenditures over $3.35 billion), would cover decommissioning
costs in excess of funds already collected for decommissioning. See Fuel
Supply -- Nuclear Waste.
NEIL's extra-expense program provides insurance to cover extra costs
resulting from a prolonged accidental outage of a nuclear unit. I&M's policy
insures against such increased costs up to approximately $3,500,000 per week
(starting 21 weeks after the outage) for one year, $2,800,000 per week for the
second and third years, or 80% of those amounts per unit if both units are down
for the same reason. If NEIL's losses exceed its available resources, I&M
would be subject to a total retrospective premium assessment of up to
$8,925,000.
POTENTIAL UNINSURED LOSSES
Some potential losses or liabilities may not be insurable or the amount
of insurance carried may not be sufficient to meet potential losses and
liabilities, including liabilities relating to damage to the Cook Plant and
costs of replacement power in the event of a nuclear incident at the Cook
Plant. Future losses or liabilities which are not completely insured, unless
allowed to be recovered through rates, could have a material adverse effect on
results of operations and the financial condition of AEP, I&M and other AEP
System companies.
Item 3. LEGAL PROCEEDINGS
- ------------------------------------------------------------------------------
On April 4, 1991, then Secretary of Labor Lynn Martin announced that the
U.S. Department of Labor (DOL) had issued a total of 4,710 citations to
operators of 847 coal mines who allegedly submitted respirable dust sampling
cassettes that had been altered so as to remove a portion of the dust. The
cassettes were submitted in compliance with DOL regulations which require
systematic sampling of airborne dust in coal mines and submission of the entire
cassettes (which include filters for collecting dust particulates) to the Mine
Safety and Health Administration (MSHA) for analysis. The amount of dust
contained on the cassette's filter determines an operator's compliance with
respirable dust standards under the law. OPCo's Meigs No. 2, Meigs No. 31,
Martinka, and Windsor Coal mines received 16, 3, 15 and 2 citations,
respectively. MSHA has assessed civil penalties totalling $56,900 for all
these citations. OPCo's samples in question involve about 1 percent of the
2,500 air samples that OPCo submitted over a 20-month period from 1989 through
1991 to the DOL. OPCo is contesting the citations before the Federal Mine
Safety and Health Review Commission. An administrative hearing was held before
an administrative law judge with respect to all affected coal operators. On
July 20, 1993, the administrative law judge rendered a decision in this case
holding that the Secretary of Labor failed to establish that the presence of a
"white center" on the dust sampling filter indicated intentional alteration.
In the case of an unaffiliated mine, the administrative law judge ruled on
April 20, 1994, that there was not an intentional alteration of the dust
sampling filter. The Secretary of Labor appealed to the Federal Mine Safety
and Health Review Commission the July 20, 1993 and April 20, 1994
administrative law judge decisions and in November 1995 the Commission affirmed
these decisions. The Secretary of Labor has appealed the Commission's decision
to the U.S. Court of Appeals for the District of Columbia Circuit. All
remaining cases, including the citations involving OPCo's mines, have been
stayed.
On February 28, 1994, Ormet Corporation filed a complaint in the U.S.
District Court, Northern District of West Virginia, against AEP, OPCo, the
Service Corporation and two of its employees, Federal EPA and the Administrator
of Federal EPA. Ormet is the operator of a major aluminum reduction plant in
Ohio and is a customer of OPCo. See Certain Industrial Customers. Pursuant to
the Clean Air Act Amendments of 1990, OPCo received SO2 Allowances for its
Kammer Plant. See Environmental and Other Matters. Ormet's complaint sought a
declaration that it is the owner of approximately 89% of the Phase I and Phase
II SO2 allowances issued for use by the Kammer Plant. On March 31, 1995, the
District Court issued an opinion and order dismissing Ormet's claims based on a
lack of jurisdiction. On April 11, 1995, Ormet appealed the District Court's
decision to the U.S. Court of Appeals for the Fourth Circuit with respect to
the Service Corporation and OPCo only. On October 23, 1996, the Court of
Appeals issued an opinion reversing the District Court. On January 10, 1997,
OPCo and the Service Corporation filed their answer and counterclaims in the
District Court.
See Item 1 for a discussion of certain environmental and rate matters.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- ------------------------------------------------------------------------------
AEP, APCo, I&M and OPCo. None.
AEGCo, CSPCo and KEPCo. Omitted pursuant to Instruction I(2)(c).
------------
EXECUTIVE OFFICERS OF THE REGISTRANTS
AEP
The following persons are, or may be deemed, executive officers of AEP.
Their ages are given as of March 15, 1997.
<TABLE>
<CAPTION>
Name Age Office (a)
- ---- --- ----------
<S> <C> <C>
E. Linn Draper, Jr. .55 Chairman of the Board, President and Chief Executive Officer of
AEP and of the Service Corporation
Peter J. DeMaria . .62 Controller of AEP; Executive Vice President-Administration and
Chief Accounting Officer of the Service Corporation
William J. Lhota . .57 Executive Vice President of the Service Corporation
Gerald P. Maloney . .64 Vice President and Secretary of AEP; Executive Vice
President-Chief Financial Officer of the Service Corporation
James J. Markowsky .52 Executive Vice President-Power Generation of the Service
Corporation
</TABLE>
- --------------------
(a) All of the executive officers listed above have been employed by the
Service Corporation or System companies in various capacities (AEP, as
such, has no employees) during the past five years, except E. Linn Draper,
Jr. who was Chairman of the Board, President and Chief Executive Officer
of Gulf States Utilities Company from 1987 until 1992 when he joined AEP
and the Service Corporation. All of the above officers are appointed
annually for a one-year term by the board of directors of AEP, the board
of directors of the Service Corporation, or both, as the case may be.
APCo
The names of the executive officers of APCo, the positions they hold with
APCo, their ages as of March 15, 1997, and a brief account of their business
experience during the past five years appears below. The directors and
executive officers of APCo are elected annually to serve a one-year term.
<TABLE>
<CAPTION>
Name Age Position (a) Period
- ---- --- ------------ ------
<S> <C> <C> <C>
E. Linn Draper, Jr. .55 Director 1992-Present
Chairman of the Board and Chief Executive
Officer 1993-Present
Vice President 1992-1993
Chairman of the Board, President and Chief
Executive Officer of AEP and the Service
Corporation 1993-Present
President of AEP 1992-1993
President and Chief Operating Officer of the
Service Corporation 1992-1993
Chairman of the Board, President and Chief
Executive Officer of Gulf States Utilities
Company 1987-1992
Peter J. DeMaria . .62 Director 1988-Present
Vice President 1991-Present
Controller 1995-Present
Treasurer 1978-1995
Controller of AEP 1995-Present
Treasurer of AEP 1978-1995
Executive Vice President-Administration and
Chief Accounting Officer of the Service
Corporation 1984-Present
William J. Lhota . .57 Director 1990-Present
President and Chief Operating Officer 1996-Present
Vice President 1989-1995
Executive Vice President of the Service
Corporation 1993-Present
Executive Vice President-Operations of the
Service Corporation 1989-1993
Gerald P. Maloney . .64 Director and Vice President 1970-Present
Vice President of AEP 1974-Present
Secretary of AEP 1994-Present
Executive Vice President-Chief Financial
Officer of the Service Corporation 1991-Present
James J. Markowsky. .52 Director 1993-Present
Vice President 1995-Present
Executive Vice President-Power Generation
of the Service Corporation 1996-Present
Executive Vice President-Engineering and
Construction of the Service Corporation 1993-1996
Senior Vice President and Chief Engineer
of the Service Corporation 1988-1993
</TABLE>
- --------------------
(a) Positions are with APCo unless otherwise indicated.
OPCo
The names of the executive officers of OPCo, the positions they hold with
OPCo, their ages as of March 15, 1997, and a brief account of their business
experience during the past five years appear below. The directors and
executive officers of OPCo are elected annually to serve a one-year term.
<TABLE>
<CAPTION>
Name Age Position (a) Period
- ---- --- ------------ ------
<S> <C> <C> <C>
E. Linn Draper, Jr. .55 Director 1992-Present
Chairman of the Board and Chief Executive
Officer 1993-Present
Vice President 1992-1993
Chairman of the Board, President and Chief
Executive Officer of AEP and the Service
Corporation 1993-Present
President of AEP 1992-1993
President and Chief Operating Officer of the
Service Corporation 1992-1993
Chairman of the Board, President and Chief
Executive Officer of Gulf States
Utilities Company 1987-1992
Peter J. DeMaria. . .62 Director 1978-Present
Vice President 1991-Present
Controller 1995-Present
Treasurer 1978-1995
Controller of AEP 1995-Present
Treasurer of AEP 1978-1995
Executive Vice President-Administration
and Chief Accounting Officer of the
Service Corporation 1984-Present
William J. Lhota. . .57 Director 1989-Present
President and Chief Operating Officer 1996-Present
Vice President 1989-1995
Executive Vice President of the Service
Corporation 1993-Present
Executive Vice President-Operations of
the Service Corporation 1989-1993
Gerald P. Maloney . .64 Director 1973-Present
Vice President 1970-Present
Vice President of AEP 1974-Present
Secretary of AEP 1994-Present
Executive Vice President-Chief Financial
Officer of the Service Corporation 1991-Present
James J. Markowsky. .52 Director 1989-Present
Vice President 1995-Present
Executive Vice President-Power Generation
of the Service Corporation 1996-Present
Executive Vice President-Engineering and
Construction of the Service Corporation 1993-1996
Senior Vice President and Chief Engineer
of the Service Corporation 1988-1993
</TABLE>
- --------------------
(a) Positions are with OPCo unless otherwise indicated.
PART II
- ------------------------------------------------------------------------
Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
- -------------------------------------------------------------------------------
AEP. AEP Common Stock is traded principally on the New York Stock
Exchange. The following table sets forth for the calendar periods indicated
the high and low sales prices for the Common Stock as reported on the New York
Stock Exchange Composite Tape and the amount of cash dividends paid per share
of Common Stock.
Per Share
------------------
Market Price
------------------
Quarter Ended High Low Dividend(1)
- ------------- ------- ------- -----------
March 1995 . . . . . . . $35-3/4 $31-1/4 $.60
June 1995. . . . . . . . 35-3/8 31-1/2 .60
September 1995 . . . . . 36-1/2 33-5/8 .60
December 1995. . . . . . 40-5/8 35-7/8 .60
March 1996 . . . . . . . 44-3/4 40-1/8 .60
June 1996. . . . . . . . 42-3/4 38-5/8 .60
September 1996 . . . . . 43-1/8 40 .60
December 1996. . . . . . 42-1/2 39-1/2 .60
- --------------------
(1) See Note 5 of the Notes to the Consolidated Financial Statements of AEP
for information regarding restrictions on payment of dividends.
At December 31, 1996, AEP had approximately 158,477 shareholders of
record.
AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo. The information required by this
item is not applicable as the common stock of all these companies is held
solely by AEP.
Item 6. SELECTED FINANCIAL DATA
- -------------------------------------------------------------------------------
AEGCo. Omitted pursuant to Instruction I(2)(a).
AEP. The information required by this item is incorporated herein by
reference to the material under Selected Consolidated Financial Data in the AEP
1996 Annual Report (for the fiscal year ended December 31, 1996).
APCo. The information required by this item is incorporated herein by
reference to the material under Selected Consolidated Financial Data in the
APCo 1996 Annual Report (for the fiscal year ended December 31, 1996).
CSPCo. Omitted pursuant to Instruction I(2)(a).
I&M. The information required by this item is incorporated herein by
reference to the material under Selected Consolidated Financial Data in the I&M
1996 Annual Report (for the fiscal year ended December 31, 1996).
KEPCo. Omitted pursuant to Instruction I(2)(a).
OPCo. The information required by this item is incorporated herein by
reference to the material under Selected Consolidated Financial Data in the
OPCo 1996 Annual Report (for the fiscal year ended December 31, 1996).
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
- -------------------------------------------------------------------------------
AEGCo. Omitted pursuant to Instruction I(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction I(2)(a) is incorporated herein by reference to the material under
Management's Narrative Analysis of Results of Operations in the AEGCo 1996
Annual Report (for the fiscal year ended December 31, 1996).
AEP. The information required by this item is incorporated herein by
reference to the material under Management's Discussion and Analysis of Results
of Operations and Financial Condition in the AEP 1996 Annual Report (for the
fiscal year ended December 31, 1996).
APCo. The information required by this item is incorporated herein by
reference to the material under Management's Discussion and Analysis of Results
of Operations and Financial Condition in the APCo 1996 Annual Report (for the
fiscal year ended December 31, 1996).
CSPCo. Omitted pursuant to Instruction I(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction I(2)(a) is incorporated herein by reference to the material under
Management's Narrative Analysis of Results of Operations in the CSPCo 1996
Annual Report (for the fiscal year ended December 31, 1996).
I&M. The information required by this item is incorporated herein by
reference to the material under Management's Discussion and Analysis of Results
of Operations and Financial Condition in the I&M 1996 Annual Report (for the
fiscal year ended December 31, 1996).
KEPCo. Omitted pursuant to Instruction I(2)(a). Management's narrative
analysis of the results of operations and other information required by
Instruction I(2)(a) is incorporated herein by reference to the material under
Management's Narrative Analysis of Results of Operations in the KEPCo 1996
Annual Report (for the fiscal year ended December 31, 1996).
OPCo. The information required by this item is incorporated herein by
reference to the material under Management's Discussion and Analysis of Results
of Operations and Financial Condition in the OPCo 1996 Annual Report (for the
fiscal year ended December 31, 1996).
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- -------------------------------------------------------------------------------
AEGCo. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
AEP. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
APCo. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
CSPCo. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
I&M. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
KEPCo. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
OPCo. The information required by this item is incorporated herein by
reference to the financial statements and supplementary data described under
Item 14 herein.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
- -------------------------------------------------------------------------------
AEGCo, AEP, APCo, CSPCo, I&M, KEPCo and OPCo. None.
PART III --------------------------------------------------------------------
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
- -------------------------------------------------------------------------------
AEGCo. Omitted pursuant to Instruction I(2)(c).
AEP. The information required by this item is incorporated herein by
reference to the material under Nominees for Director and Section 16(a)
Beneficial Ownership Reporting Compliance of the definitive proxy statement
of AEP, dated March 10, 1997, for the 1997 annual meeting of shareholders.
Reference also is made to the information under the caption Executive Officers
of the Registrants in Part I of this report.
APCo. The information required by this item is incorporated herein by
reference to the material under Election of Directors of the definitive
information statement of APCo for the 1997 annual meeting of stockholders, to
be filed within 120 days after December 31, 1996. Reference also is made to
the information under the caption Executive Officers of the Registrants in Part
I of this report.
CSPCo. Omitted pursuant to Instruction I(2)(c).
I&M. The names of the directors and executive officers of I&M, the
positions they hold with I&M, their ages as of March 15, 1997, and a brief
account of their business experience during the past five years appear below.
The directors and executive officers of I&M are elected annually to serve a
one-year term.
<TABLE>
<CAPTION>
Name Age Position (a)(b)(c) Period
- ---- --- ------------------ ------
<S> <C> <C> <C>
E. Linn Draper, Jr. .55 Director 1992-Present
Chairman of the Board and Chief Executive
Officer 1993-Present
Vice President 1992-1993
Chairman of the Board, President and Chief
Executive Officer of AEP and of the
Service Corporation 1993-Present
President of AEP 1992-1993
President and Chief Operating Officer of
the Service Corporation 1992-1993
Chairman of the Board, President and Chief
Executive Officer of Gulf States
Utilities Company 1987-1992
Peter J. DeMaria. . .62 Director 1992-Present
Vice President 1991-Present
Controller 1995-Present
Treasurer 1978-1995
Controller of AEP 1995-Present
Treasurer of AEP 1978-1995
Executive Vice President-Administration
and Chief Accounting Officer of the
Service Corporation 1984-Present
William N. D'Onofrio.49 Director 1984-Present
Vice President 1984-1995
Director-Regions of the Service Corporation 1996-Present
William J. Lhota. . .57 Director 1989-Present
President and Chief Operating Officer 1996-Present
Vice President 1989-1995
Executive Vice President of the Service
Corporation 1993-Present
Executive Vice President-Operations of the
Service Corporation 1989-1993
Gerald P. Maloney . .64 Director 1978-Present
Vice President 1970-Present
Vice President of AEP 1974-Present
Secretary of AEP 1994-Present
Executive Vice President-Chief Financial
Officer of the Service Corporation 1991-Present
James J. Markowsky. .52 Director 1995-Present
Vice President 1993-Present
Executive Vice President-Power Generation
of the Service Corporation 1996-Present
Executive Vice President-Engineering &
Construction of the Service Corporation 1993-1996
Senior Vice President and Chief Engineer
of the Service Corporation 1988-1993
D. M. Trenary . . . .60 Director 1994-Present
Indiana Region Manager 1994-Present
Division Manager 1989-1994
W. E. Walters . . . .49 Director 1991-Present
Michiana Region Manager 1994-Present
Executive Assistant to President 1987-1994
C. R. Boyle, III. . .49 Director and Vice President 1996-Present
President and Chief Operating Officer of
KEPCo 1990-1995
G. A. Clark . . . . .45 Director 1995-Present
Governmental Affairs Manager 1996-Present
General Counsel 1994-1995
General Attorney 1991-1993
D. B. Synowiec. . . .53 Director 1995-Present
Plant Manager 1990-Present
J. H. Vipperman . . .56 Director and Vice President 1996-Present
Executive Vice President-Energy Delivery
of the Service Corporation 1996-Present
President and Chief Operating Officer of
APCo 1990-1995
E. H. Wittkamper. . .58 Director 1996-Present
Director of System Operations (Fort Wayne) 1996
System Operations Manager (Fort Wayne) 1990-1996
</TABLE>
- --------------------
(a) Positions are with I&M unless otherwise indicated.
(b) Dr. Draper is a director of BCP Management, Inc., which is the general
partner of Borden Chemicals and Plastics L.P., and Mr. Lhota is a director
of Huntington Bancshares Incorporated and State Auto Financial
Corporation.
(c) Drs. Draper and Markowsky and Messrs. DeMaria, Lhota and Maloney are
directors of AEGCo, APCo, CSPCo, KEPCo and OPCo. Dr. Draper and Messrs.
DeMaria and Maloney are also directors of AEP. Mr. Vipperman is a
director of APCo, CSPCo, KEPCo and OPCo.
KEPCo. Omitted pursuant to Instruction I(2)(c).
OPCo. The information required by this item is incorporated herein by
reference to the material under the heading Election of Directors of the
definitive information statement of OPCo for the 1997 annual meeting of
shareholders, to be filed within 120 days after December 31, 1996. Reference
also is made to the information under the caption Executive Officers of the
Registrants in Part I of this report.
Item 11. EXECUTIVE COMPENSATION
- ------------------------------------------------------------------------------
AEGCo. Omitted pursuant to Instruction I(2)(c).
AEP. The information required by this item is incorporated herein by
reference to the material under Compensation of Directors, Executive
Compensation and the performance graph of the definitive proxy statement of
AEP, dated March 10, 1997, for the 1997 annual meeting of shareholders.
APCo. The information required by this item is incorporated herein by
reference to the material under Executive Compensation of the definitive
information statement of APCo for the 1997 annual meeting of stockholders, to
be filed within 120 days after December 31, 1996.
CSPCo. Omitted pursuant to Instruction I(2)(c).
KEPCo. Omitted pursuant to Instruction I(2)(c).
OPCo. The information required by this item is incorporated herein by
reference to the material under Executive Compensation of the definitive
information statement of OPCo for the 1997 annual meeting of shareholders, to
be filed within 120 days after December 31, 1996.
I&M. Certain executive officers of I&M are employees of the Service
Corporation. The salaries of these executive officers are paid by the Service
Corporation and a portion of their salaries has been allocated and charged to
I&M. The following table shows for 1996, 1995 and 1994 the compensation earned
from all AEP System companies by the chief executive officer and four other
most highly compensated executive officers (as defined by regulations of the
SEC) of I&M at December 31, 1996.
Summary Compensation Table
<TABLE>
<CAPTION>
Long-Term
Compensation
Annual Compensation ------------------
------------------- Payouts All Other
Salary Bonus ------------------ Compensation
Name and Principal Position Year ($) ($)(1) LTIP Payouts($)(1) ($)(2)
--------------------------- ---- ------- ------- ------------------ ------------
<S> <C> <C> <C> <C> <C>
E. Linn Draper, Jr. -- Chairman of the board, 1996 720,000 281,664 675,903 31,990
president and chief executive officer of the 1995 685,000 236,325 334,851 30,790
Company and the Service Corporation; chairman 1994 620,000 209,436 137,362 29,385
and chief executive officer of other subsidiaries
Peter J. DeMaria -- Controller and director of the 1996 360,000 140,832 290,825 21,190
Company; executive vice president--administration 1995 330,000 113,850 143,829 20,050
and chief accounting officer and director of the 1994 305,000 103,029 59,032 18,750
Service Corporation; vice president, controller
and director of other subsidiaries
G. P. Maloney -- Vice president, secretary and 1996 360,000 140,832 286,288 21,190
director of the Company; executive vice president 1995 330,000 113,850 141,582 20,060
-- chief financial officer and director of the 1994 300,000 101,340 58,094 19,745
Service Corporation; vice president and director
of other subsidiaries
William J. Lhota -- Executive vice president and 1996 320,000 125,184 263,114 19,690
director of the Service Corporation; president, 1995 300,000 103,500 132,592 19,140
chief operating officer and director of other 1994 280,000 94,584 54,409 19,185
subsidiaries
James J. Markowsky -- Executive vice president 1996 303,000 118,534 254,535 19,480
-- power generation and director of the Service 1995 285,000 98,325 126,599 17,515
Corporation; vice president and director of 1994 267,000 90,193 51,930 14,755
other subsidiaries
</TABLE>
- --------------------
(1) Amounts in the "Bonus" column reflect payments under the Management
Incentive Compensation Plan for performance measured for each of the years
ended December 31, 1994, 1995 and 1996. Payments are made in March of the
subsequent year. Amounts for 1996 are estimates but should not change
significantly.
Amounts in the "Long-Term Compensation" column reflect performance share
unit targets earned under the Performance Share Incentive Plan (which
became effective January 1, 1994) for the one-, two- and three-year
performance periods ending December 31, 1994, 1995 and 1996, respectively.
The one- and two-year performance periods were transition performance
periods.
See below under "Long-Term Incentive Plans -- Awards in 1996" for
additional information.
(2) For 1996, includes (i) employer matching contributions under the AEP
System Employees Savings Plan: Dr. Draper, $3,600; Mr. DeMaria, $3,175;
Mr. Maloney, $4,500; Mr. Lhota, $4,500; and Dr. Markowsky, $3,235; (ii)
employer matching contributions under the AEP System Supplemental Savings
Plan, a non-qualified plan designed to supplement the AEP Savings Plan:
Dr. Draper, $18,000; Mr. DeMaria, $7,625; Mr. Maloney, $6,300; Mr. Lhota,
$4,800; and Dr. Markowsky, $5,855; and (iii) subsidiary companies director
fees: $10,390 for each of the named executive officers.
Long-Term Incentive Plans -- Awards In 1996
Each of the awards set forth below establishes performance share unit
targets, which represent units equivalent to shares of Common Stock, pursuant
to the Company's Performance Share Incentive Plan. Since it is not possible to
predict future dividends and the price of AEP Common Stock, credits of
performance share units in amounts equal to the dividends that would have been
paid if the performance share unit targets were established in the form of
shares of Common Stock are not included in the table.
The ability to earn performance share unit targets is tied to achieving
specified levels of total shareholder return ("TSR") relative to the S&P
Electric Utility Index. Notwithstanding AEP's TSR ranking, no performance
share unit targets are earned unless AEP shareholders realize a positive TSR
over the relevant three-year performance period. The Human Resources Committee
may, at its discretion, reduce the number of performance share unit targets
otherwise earned. In accordance with the performance goals established for the
periods set forth below, the threshold, target and maximum awards are equal to
25%, 100% and 200%, respectively, of the performance share unit targets. No
payment will be made for performance below the threshold.
Payments of earned awards are deferred in the form of restricted stock
units (equivalent to shares of AEP Common Stock) until the officer has met the
equivalent stock ownership target discussed in the Human Resources Committee
Report. Once officers meet and maintain their respective targets, they may
elect either to continue to defer or to receive further earned awards in cash
and/or Common Stock.
<TABLE>
<CAPTION>
Estimated Future Payouts of
Performance Share Units Under
Performance Non-Stock Price-Based Plan
Number of Period Until --------------------------
Performance Maturation Threshold Target Maximum
Name Share Units or Payout (#) (#) (#)
- ----------------- ----------- ----------- --------- ------- -------
<S> <C> <C> <C> <C> <C>
E. L. Draper, Jr. 7,339 1996-1998 1,835 7,339 14,678
P. J. DeMaria 3,211 1996-1998 803 3,211 6,422
G. P. Maloney 3,211 1996-1998 803 3,211 6,422
W. J. Lhota 2,854 1996-1998 714 2,854 5,708
J. J. Markowsky 2,702 1996-1998 676 2,702 5,404
</TABLE>
Retirement Benefits
The American Electric Power System Retirement Plan provides pensions for
all employees of AEP System companies (except for employees covered by certain
collective bargaining agreements), including the executive officers of the
Company. The Retirement Plan is a noncontributory defined benefit plan.
The following table shows the approximate annual annuities under the
Retirement Plan that would be payable to employees in certain higher salary
classifications, assuming retirement at age 65 after various periods of
service.
Pension Plan Table
<TABLE>
<CAPTION>
Years of Accredited Service
Highest Average --------------------------------------------------------------
Annual Earnings 15 20 25 30 35 40 45
- --------------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
$ 300,000 $ 69,795 $ 93,060 $116,325 $139,590 $162,855 $182,805 $202,755
400,000 93,795 125,060 156,325 187,590 218,855 245,455 272,055
500,000 117,795 157,060 196,325 235,590 274,855 308,105 341,355
700,000 165,795 221,060 276,325 331,590 386,855 433,405 479,955
900,000 213,795 285,060 356,325 427,590 498,855 558,705 618,555
1,200,000 285,795 381,060 476,325 571,590 666,855 746,655 826,455
</TABLE>
The amounts shown in the table are the straight life annuities payable
under the Retirement Plan without reduction for the joint and survivor annuity.
Retirement benefits listed in the table are not subject to any deduction for
Social Security or other offset amounts. The retirement annuity is reduced 3%
per year in the case of retirement between ages 60 and 62 and further reduced
6% per year in the case of retirement between ages 55 and 60. If an employee
retires after age 62, there is no reduction in the retirement annuity.
The Company maintains a supplemental retirement plan which provides for
the payment of benefits that are not payable under the Retirement Plan due
primarily to limitations imposed by Federal tax law on benefits paid by
qualified plans. The table includes supplemental retirement benefits.
Compensation upon which retirement benefits are based, for the executive
officers named in the Summary Compensation Table above, consists of the average
of the 36 consecutive months of the officer's highest aggregate salary and
Management Incentive Compensation Plan awards, shown in the "Salary" and
"Bonus" columns, respectively, of the Summary Compensation Table, out of the
officer's most recent 10 years of service. As of December 31, 1996, the number
of full years of service applicable for retirement benefit calculation purposes
for such officers were as follows: Dr. Draper, four years; Mr. DeMaria, 37
years; Mr. Maloney, 41 years; Mr. Lhota, 32 years; and Dr. Markowsky, 25 years.
Dr. Draper has a contract with the Company and AEP Service Corporation
which provides him with a supplemental retirement annuity that credits him with
24 years of service in addition to his years of service credited under the
Retirement Plan less his actual pension entitlement under the Retirement Plan
and any pension entitlement from the Gulf States Utilities Company Trusteed
Retirement Plan, a plan sponsored by his prior employer.
Fourteen AEP System employees (including Messrs. DeMaria, Maloney and
Lhota and Dr. Markowsky) whose pensions may be adversely affected by amendments
to the Retirement Plan made as a result of the Tax Reform Act of 1986 are
eligible for certain supplemental retirement benefits. Such payments, if any,
will be equal to any reduction occurring because of such amendments. Assuming
retirement in 1997 of the executive officers named in the Summary Compensation
Table, only Mr. Maloney would be affected and his annual supplemental benefit
would be $2,361.
The Company made available a voluntary deferred-compensation program in
1982 and 1986, which permitted certain members of AEP System management to
defer receipt of a portion of their salaries. Under this program, a
participant was able to defer up to 10% or 15% annually (depending on the terms
of the program offered), over a four-year period, of his or her salary, and
receive supplemental retirement or survivor benefit payments over a 15-year
period. The amount of supplemental retirement payments received is dependent
upon the amount deferred, age at the time the deferral election was made, and
number of years until the participant retires. The following table sets forth,
for the executive officers named in the Summary Compensation Table, the amounts
of annual deferrals and, assuming retirement at age 65, annual supplemental
retirement payments under the 1982 and 1986 programs.
<TABLE>
<CAPTION>
1982 Program 1986 Program
-------------------------------- --------------------------------
Annual Amount of Annual Amount of
Annual Supplemental Annual Supplemental
Amount Retirement Amount Retirement
Deferred Payment Deferred Payment
Name (4-Year Period) (15-Year Period) (4-Year Period) (15-Year Period)
- ---- --------------- ---------------- --------------- ----------------
<S> <C> <C> <C> <C>
P. J. DeMaria . . . $10,000 $52,000 $13,000 $53,300
G. P. Maloney . . . 15,000 67,500 16,000 56,400
</TABLE>
Directors of I&M receive a fee of $100 for each meeting of the Board of
Directors attended in addition to their salaries.
The AEP System is an integrated electric utility system and, as a result,
the member companies of the AEP System have contractual, financial and other
business relationships with the other member companies, such as participation
in the AEP System savings and retirement plans and tax returns, sales of
electricity, transportation and handling of fuel, sales or rentals of property
and interest or dividend payments on the securities held by the companies'
respective parents.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
- -------------------------------------------------------------------------------
AEGCo. Omitted pursuant to Instruction I(2)(c).
AEP. The information required by this item is incorporated herein by
reference to the material under Share Ownership of Directors and Executive
Officers of the definitive proxy statement of AEP, dated March 10, 1997, for
the 1997 annual meeting of shareholders.
APCo. The information required by this item is incorporated herein by
reference to the material under Share Ownership of Directors and Executive
Officers in the definitive information statement of APCo for the 1997 annual
meeting of stockholders, to be filed within 120 days after December 31, 1996.
CSPCo. Omitted pursuant to Instruction I(2)(c).
I&M. All 1,400,000 outstanding shares of Common Stock, no par value, of
I&M are directly and beneficially held by AEP. Holders of the Cumulative
Preferred Stock of I&M generally have no voting rights, except with respect to
certain corporate actions and in the event of certain defaults in the payment
of dividends on such shares.
The table below shows the number of shares of AEP Common Stock and
stock-based units that were beneficially owned, directly or indirectly, as of
January 1, 1997, by each director and nominee of I&M and each of the executive
officers of I&M named in the summary compensation table, and by all directors
and executive officers of I&M as a group. It is based on information provided
to I&M by such persons. No such person owns any shares of any series of the
Cumulative Preferred Stock of I&M. Unless otherwise noted, each person has
sole voting power and investment power over the number of shares of AEP Common
Stock and stock-based units set forth opposite his name. Fractions of shares
and units have been rounded to the nearest whole number.
<TABLE>
<CAPTION>
Stock
Name Shares Units(a) Total
---- -------- -------- -------
<S> <C> <C> <C>
Coulter R. Boyle, III . . . . . . . 3,454(b) 933 4,387
Gregory A. Clark. . . . . . . . . . 954(b) 346 1,300
Peter J. DeMaria. . . . . . . . . . 7,603(b)(c)(d)(e)12,947 20,550
William N. D'Onofrio. . . . . . . . 3,981(b)(d) 685 4,666
E. Linn Draper, Jr. . . . . . . . . 6,793(b)(d) 35,915 42,708
William J. Lhota. . . . . . . . . . 14,053(b)(c)(d) 5,383 19,436
Gerald P. Maloney . . . . . . . . . 5,512(b)(c)(d) 12,765 18,277
James J. Markowsky. . . . . . . . . 7,123(b)(e) 11,755 18,878
David B. Synowiec . . . . . . . . . 2,335(b) 545 2,880
Dale M. Trenary . . . . . . . . . . 160(b) 568 728
Joseph H. Vipperman . . . . . . . . 5,510(b)(d) 3,972 9,482
William E. Walters. . . . . . . . . 5,200(b) 403 5,603
Earl H. Wittkamper. . . . . . . . . 2,902(b) 420 3,322
All Directors and Executive Officers 150,811(d)(f) 86,637 237,448
</TABLE>
- -----------------
(a) This column includes amounts deferred in stock units and held under the
Management Incentive Compensation Plan and Performance Share Incentive
Plan.
(b) Includes shares and share equivalents held in the following plans in the
amounts listed below:
<TABLE>
<CAPTION>
AEP Employee Stock AEP Performance AEP Employees Savings
Ownership Plan (Shares) Share Incentive Plan (Shares) Plan (Share Equivalents)
----------------------- ----------------------------- ------------------------
<S> <C> <C> <C>
Mr. Boyle . . . . . . . . . . 50 -- 3,404
Mr. Clark . . . . . . . . . . 8 -- 946
Mr. DeMaria . . . . . . . . . 90 881 2,945
Mr. D'Onofrio . . . . . . . . 64 -- 3,917
Dr. Draper. . . . . . . . . . -- 2,050 2,383
Mr. Lhota . . . . . . . . . . 64 812 11,809
Mr. Maloney . . . . . . . . . 92 867 3,053
Dr. Markowsky . . . . . . . . 71 775 6,154
Mr. Synowiec. . . . . . . . . 58 -- 2,277
Mr. Trenary . . . . . . . . . 44 -- 116
Mr. Vipperman . . . . . . . . 86 527 4,766
Mr. Walters . . . . . . . . . 48 -- 5,152
Mr. Wittkamper. . . . . . . . 37 -- 1,628
All Directors and Executive Officers 712 5,912 48,550
With respect to the shares and share equivalents held in these plans, such persons have sole voting power, but the
investment/disposition power is subject to the terms of such plans.
</TABLE>
(c) Does not include, for Messrs. DeMaria, Lhota and Maloney, 85,231 shares
in the American Electric Power System Educational Trust Fund over which
Messrs. DeMaria, Lhota and Maloney share voting and investment power as
trustees (they disclaim beneficial ownership). The amount of shares
shown for all directors and executive officers as a group includes these
shares.
(d) Includes the following numbers of shares held in joint tenancy with a
family member: Mr. DeMaria, 1,232; Mr. D'Onofrio, 500; Dr. Draper,
2,083; Mr. Lhota, 1,368; Mr. Maloney, 1,500; and Mr. Vipperman, 131.
(e) Includes the following numbers of shares held by family members over
which beneficial ownership is disclaimed: Mr. DeMaria, 2,392; and Dr.
Markowsky, 18.
(f) Represents less than 1% of the total number of shares outstanding.
KEPCo. Omitted pursuant to Instruction I(2)(c).
OPCo. The information required by this item is incorporated herein by
reference to the material under Share Ownership of Directors and Executive
Officers in the definitive information statement of OPCo for the 1997 annual
meeting of shareholders, to be filed within 120 days after December 31, 1996.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- ------------------------------------------------------------------------------
AEP, APCo, I&M and OPCo. None.
AEGCo, CSPCo, and KEPCo. Omitted pursuant to Instruction I(2)(c).
PART IV ---------------------------------------------------------------------
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
- ------------------------------------------------------------------------------
(a) The following documents are filed as a part of this report:
1. Financial Statements: Page
----
The following financial statements have been incorporated herein by
reference pursuant to Item 8.
AEGCo:
Independent Auditors' Report; Statements of Income for the
years ended December 31, 1996, 1995 and 1994;
Statements of Retained Earnings for the years ended
December 31, 1996, 1995 and 1994; Statements of Cash
Flows for the years ended December 31, 1996, 1995 and
1994; Balance Sheets as of December 31, 1996 and 1995;
Notes to Financial Statements.
AEP and its subsidiaries consolidated:
Consolidated Statements of Income for the years ended
December 31, 1996, 1995 and 1994; Consolidated
Statements of Retained Earnings for the years ended
December 31, 1996, 1995 and 1994; Consolidated Balance
Sheets as of December 31, 1996 and 1995; Consolidated
Statements of Cash Flows for the years ended December
31, 1996, 1995 and 1994; Notes to Consolidated
Financial Statements; Schedule of Consolidated
Cumulative Preferred Stocks of Subsidiaries at December
31, 1996 and 1995; Schedule of Consolidated Long-term
Debt of Subsidiaries at December 31, 1996 and 1995;
Independent Auditors' Report.
APCo:
Consolidated Statements of Income for the years ended
December 31, 1996, 1995 and 1994; Consolidated Balance
Sheets as of December 31, 1996 and 1995; Consolidated
Statements of Cash Flows for the years ended December
31, 1996, 1995 and 1994; Consolidated Statements of
Retained Earnings for the years ended December 31,
1996, 1995 and 1994; Notes to Consolidated Financial
Statements; Independent Auditors' Report.
CSPCo:
Independent Auditors' Report; Consolidated Statements of
Income for the years ended December 31, 1996, 1995 and
1994; Consolidated Balance Sheets as of December 31,
1996 and 1995; Consolidated Statements of Cash Flows
for the years ended December 31, 1996, 1995 and 1994;
Consolidated Statements of Retained Earnings for the
years ended December 31, 1996, 1995 and 1994; Notes to
Consolidated Financial Statements.
I&M:
Independent Auditors' Report; Consolidated Statements of
Income for the years ended December 31, 1996, 1995 and
1994; Consolidated Statements of Cash Flows for the
years ended December 31, 1996, 1995 and 1994;
Consolidated Balance Sheets as of December 31, 1996 and
1995; Consolidated Statements of Retained Earnings for
the years ended December 31, 1996, 1995 and 1994; Notes
to Consolidated Financial Statements.
KEPCo:
Independent Auditors' Report; Statements of Income for the
years ended December 31, 1996, 1995 and 1994;
Statements of Retained Earnings for the years ended
December 31, 1996, 1995 and 1994; Balance Sheets as of
December 31, 1996 and 1995; Statements of Cash Flows
for the years ended December 31, 1996, 1995 and 1994;
Notes to Financial Statements.
OPCo:
Independent Auditors' Report; Consolidated Statements of
Income for the years ended December 31, 1996, 1995 and
1994; Consolidated Statements of Cash Flows for the
years ended December 31, 1996, 1995 and 1994;
Consolidated Balance Sheets as of December 31, 1996 and
1995; Consolidated Statements of Retained Earnings for
the years ended December 31, 1996, 1995 and 1994; Notes
to Consolidated Financial Statements.
2. Financial Statement Schedules:
Financial Statement Schedules are listed in the Index to
Financial Statement Schedules (Certain schedules have been
omitted because the required information is contained in
the notes to financial statements or because such schedules
are not required or are not applicable.) S-1
Independent Auditors' Report S-2
3. Exhibits:
Exhibits for AEGCo, AEP, APCo, CSPCo, I&M, KEPCo and OPCo are
listed in the Exhibit Index and are incorporated herein
by reference E-1
(b) No Reports on Form 8-K were filed during the quarter ended December 31,
1996.
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
AEP Generating Company
By: /s/ G. P. Maloney
-----------------------------
(G. P. Maloney, Vice President)
Date: March 25, 1997
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
Signature Title Date
--------- ----- ----
(i) Principal Executive Officer:
President,
*E. Linn Draper, Jr. Chief Executive Officer
and Director
(ii) Principal Financial Officer:
/s/ G. P. Maloney Vice President March 25, 1997
------------------------- and Director
(G. P. Maloney)
(iii) Principal Accounting Officer:
/s/ P. J. DeMaria Vice President, Controller March 25, 1997
------------------------- and Director
(P. J. DeMaria)
(iv) A Majority of the Directors:
*Henry Fayne
*John R. Jones, III
*Wm. J. Lhota
*James J. Markowsky
*By: /s/ G. P. Maloney March 25, 1997
- ------------------------------
(G. P. Maloney, Attorney-in-Fact)
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
American Electric Power Company, Inc.
By: /s/ G. P. Maloney
---------------------------------
(G. P. Maloney, Vice President)
Date: March 25, 1997
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
Signature Title Date
--------- ----- ----
(i) Principal Executive Officer:
Chairman of the Board,
*E. Linn Draper, Jr. President,
Chief Executive Officer
and Director
(ii) Principal Financial Officer:
/s/ G. P. Maloney Vice President, Secretary March 25, 1997
-------------------------- and Director
(G. P. Maloney)
(iii) Principal Accounting Officer:
/s/ P. J. DeMaria Controller and Director March 25, 1997
--------------------------
(P. J. DeMaria)
(iv) A Majority of the Directors:
*Robert M. Duncan
*Robert W. Fri
*Arthur G. Hansen
*Lester A. Hudson, Jr.
*Leonard J. Kujawa
*Angus E. Peyton
*Donald G. Smith
*Linda Gillespie Stuntz
*Morris Tanenbaum
*Ann Haymond Zwinger
*By: /s/ G. P. Maloney March 25, 1997
-----------------------------
(G. P. Maloney, Attorney-in-Fact)
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
Appalachian Power Company
By: /s/ G. P. Maloney
----------------------------
(G. P. Maloney, Vice President)
Date: March 25, 1997
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
Signature Title Date
--------- ----- ----
(i) Principal Executive Officer:
Chairman of the Board,
*E. Linn Draper, Jr. Chief Executive Officer
and Director
(ii) Principal Financial Officer:
/s/ G. P. Maloney Vice President March 25, 1997
------------------------- and Director
(G. P. Maloney)
(iii) Principal Accounting Officer:
/s/ P. J. DeMaria Vice President, Controller March 25, 1997
------------------------- and Director
(P. J. DeMaria)
(iv) A Majority of the Directors:
*Henry Fayne
*Wm. J. Lhota
*James J. Markowsky
*J. H. Vipperman
*By: /s/ G. P. Maloney March 25, 1997
----------------------------
(G. P. Maloney, Attorney-in-Fact)
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
Columbus Southern Power Company
By: /s/ G. P. Maloney
--------------------------
(G. P. Maloney, Vice President)
Date: March 25, 1997
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
Signature Title Date
--------- ----- ----
(i) Principal Executive Officer:
Chairman of the Board,
*E. Linn Draper, Jr. Chief Executive Officer
and Director
(ii) Principal Financial Officer:
/s/ G. P. Maloney Vice President March 25, 1997
--------------------------- and Director
(G. P. Maloney)
(iii) Principal Accounting Officer:
/s/ P. J. DeMaria Vice President, Controller March 25, 1997
--------------------------- and Director
(P. J. DeMaria)
(iv) A Majority of the Directors:
*Henry Fayne
*Wm. J. Lhota
*James J. Markowsky
*J. H. Vipperman
*By: /s/ G. P. Maloney March 25, 1997
- ----------------------------------
(G. P. Maloney, Attorney-in-Fact)
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
Indiana Michigan Power Company
By: /s/ G. P. Maloney
------------------------------
(G. P. Maloney, Vice President)
Date: March 25, 1997
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
Signature Title Date
--------- ----- ----
(i) Principal Executive Officer:
Chairman of the Board,
*E. Linn Draper, Jr. Chief Executive Officer
and Director
(ii) Principal Financial Officer:
/s/ G. P. Maloney Vice President March 25, 1997
--------------------------- and Director
(G. P. Maloney)
(iii) Principal Accounting Officer:
/s/ P. J. DeMaria Vice President, Controller March 25, 1997
--------------------------- and Director
(P. J. DeMaria)
(iv) A Majority of the Directors:
*C. R. Boyle, III
*G. A. Clark
*W. N. D'Onofrio
*Wm. J. Lhota
*James J. Markowsky
*D. B. Synowiec
*D. M. Trenary
*J. H. Vipperman
*W. E. Walters
*E. H. Wittkamper
*By: /s/ G. P. Maloney March 25, 1997
---------------------
(G. P. Maloney, Attorney-in-Fact)
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
Kentucky Power Company
By: /s/ G. P. Maloney
-------------------------
G. P. Maloney, Vice President)
Date: March 25, 1997
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
Signature Title Date
--------- ----- ----
(i) Principal Executive Officer:
Chairman of the Board,
*E. Linn Draper, Jr. Chief Executive Officer
and Director
(ii) Principal Financial Officer:
/s/ G. P. Maloney Vice President March 25, 1997
--------------------------- and Director
(G. P. Maloney)
(iii) Principal Accounting Officer:
/s/ P. J. DeMaria Vice President, Controller March 25, 1997
--------------------------- and Director
(P. J. DeMaria)
(iv) A Majority of the Directors:
*Wm. J. Lhota
*James J. Markowsky
*J. H. Vipperman
*By: /s/ G. P. Maloney March 25, 1997
- ----------------------------------
(G. P. Maloney, Attorney-in-Fact)
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF
THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
Ohio Power Company
By: /s/ G. P. Maloney
--------------------------
(G. P. Maloney, Vice President)
Date: March 25, 1997
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
Signature Title Date
--------- ----- ----
(i) Principal Executive Officer:
Chairman of the Board,
*E. Linn Draper, Jr. Chief Executive Officer
and Director
(ii) Principal Financial Officer:
/s/ G. P. Maloney Vice President March 25, 1997
--------------------------- and Director
(G. P. Maloney)
(iii) Principal Accounting Officer:
/s/ P. J. DeMaria Vice President, Controller March 25, 1997
--------------------------- and Director
(P. J. DeMaria)
(iv) A Majority of the Directors:
*Henry Fayne
*Wm. J. Lhota
*James J. Markowsky
*J. H. Vipperman
*By: /s/ G. P. Maloney March 25, 1997
- ----------------------------------
(G. P. Maloney, Attorney-in-Fact)
INDEX TO FINANCIAL STATEMENT SCHEDULES
Page
----
INDEPENDENT AUDITORS' REPORT . . . . . . . . . . . . . . . . . . . . . . . S-2
The following financial statement schedules for the years ended
December 31, 1996, 1995 and 1994 are included in this report on
the pages indicated.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule II -- Valuation and Qualifying Accounts and Reserves . . . S-3
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Schedule II -- Valuation and Qualifying Accounts and Reserves . . . S-3
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Schedule II -- Valuation and Qualifying Accounts and Reserves . . . S-3
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Schedule II -- Valuation and Qualifying Accounts and Reserves . . . S-4
KENTUCKY POWER COMPANY
Schedule II -- Valuation and Qualifying Accounts and Reserves . . . S-4
OHIO POWER COMPANY AND SUBSIDIARIES
Schedule II -- Valuation and Qualifying Accounts and Reserves . . . S-4
INDEPENDENT AUDITORS' REPORT
American Electric Power Company, Inc. and Subsidiaries:
We have audited the consolidated financial statements of American Electric
Power Company, Inc. and its subsidiaries and the financial statements of
certain of its subsidiaries, listed in Item 14 herein, as of December 31, 1996
and 1995, and for each of the three years in the period ended December 31,
1996, and have issued our reports thereon dated February 25, 1997; such
financial statements and reports are included in your respective 1996 Annual
Report and are incorporated herein by reference. Our audits also included the
financial statement schedules of American Electric Power Company, Inc. and its
subsidiaries and of certain of its subsidiaries, listed in Item 14. These
financial statement schedules are the responsibility of the respective
Company's management. Our responsibility is to express an opinion based on our
audits. In our opinion, such financial statement schedules, when considered in
relation to the corresponding basic financial statements taken as a whole,
present fairly in all material respects the information set forth therein.
Deloitte & Touche LLP
Columbus, Ohio
February 25, 1997
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
==============================================================================================
Column A Column B Column C Column D Column E
- ----------------------------------------------------------------------------------------------
Additions
---------------------
Balance atCharged toCharged to Balance at
BeginningCosts and Other End of
Description of Period Expenses Accounts Deductions Period
- ----------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1996 $5,430 $16,382 $ 7,224 (a)$25,344(b) $3,692
Year Ended December 31, 1995 $4,056 $12,907 $ 5,927 (a)$17,460(b) $5,430
Year Ended December 31, 1994 $4,048 $20,265 $(3,556)(a)$16,701(b) $4,056
</TABLE>
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
==============================================================================================
Column A Column B Column C Column D Column E
- ----------------------------------------------------------------------------------------------
Additions
---------------------
Balance atCharged toCharged to Balance at
BeginningCosts and Other End of
Description of Period Expenses Accounts Deductions Period
- ----------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1996 $2,253 $1,748 $779(a) $4,093(b) $ 687
Year Ended December 31, 1995 $ 830 $3,442 $963(a) $2,982(b) $2,253
Year Ended December 31, 1994 $1,344 $2,297 $596(a) $3,407(b) $ 830
</TABLE>
- --------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
==============================================================================================
Column A Column B Column C Column D Column E
- ----------------------------------------------------------------------------------------------
Additions
---------------------
Balance atCharged toCharged to Balance at
BeginningCosts and Other End of
Description of Period Expenses Accounts Deductions Period
- ----------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1996 $1,061 $7,720 $3,978(a)$11,727(b) $1,032
Year Ended December 31, 1995 $1,768 $4,873 $3,531(a)$ 9,111(b) $1,061
Year Ended December 31, 1994 $ 991 $6,181 $2,778(a)$ 8,182(b) $1,768
</TABLE>
- --------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
==============================================================================================
Column A Column B Column C Column D Column E
- ----------------------------------------------------------------------------------------------
Additions
---------------------
Balance atCharged toCharged to Balance at
BeginningCosts and Other End of
Description of Period Expenses Accounts Deductions Period
- ----------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1996 $334 $2,208 $791(a) $3,177(b) $156
Year Ended December 31, 1995 $121 $1,506 $632(a) $1,925(b) $334
Year Ended December 31, 1994 $505 $ 774 $707(a) $1,864(b) $121
</TABLE>
- --------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
<TABLE>
<CAPTION>
KENTUCKY POWER COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
==============================================================================================
Column A Column B Column C Column D Column E
- ----------------------------------------------------------------------------------------------
Additions
---------------------
Balance atCharged toCharged to Balance at
BeginningCosts and Other End of
Description of Period Expenses Accounts Deductions Period
- ----------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1996 $259 $1,507 $311(a) $1,805(b) $272
Year Ended December 31, 1995 $260 $ 925 $234(a) $1,160(b) $259
Year Ended December 31, 1994 $208 $ 600 $ 84(a) $ 632(b) $260
</TABLE>
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
==============================================================================================
Column A Column B Column C Column D Column E
- ----------------------------------------------------------------------------------------------
Additions
---------------------
Balance atCharged toCharged to Balance at
BeginningCosts and Other End of
Description of Period Expenses Accounts Deductions Period
- ----------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
Deducted from Assets:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1996 $1,424 $ 2,874 $ 532 (a)$3,397(b) $1,433
Year Ended December 31, 1995 $1,019 $ 1,952 $ 472 (a)$2,019(b) $1,424
Year Ended December 31, 1994 $ 960 $10,087 $(7,785)(a)$2,243(b) $1,019
</TABLE>
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
<PAGE>
EXHIBIT INDEX
Certain of the following exhibits, designated with an asterisk(*), are
filed herewith. The exhibits not so designated have heretofore been filed with
the Commission and, pursuant to 17 C.F.R. Section 229.10(d) and Section
240.12b-32, are incorporated herein by reference to the documents indicated in
brackets following the descriptions of such exhibits. Exhibits, designated
with a dagger (<dagger>), are management contracts or compensatory plans or
arrangements required to be filed as an exhibit to this form pursuant to Item
14(c) of this report.
Exhibit Number Description
- -------------- -----------
AEGCo
3(a) -- Copy of Articles of Incorporation of AEGCo
[Registration Statement on Form 10 for the Common
Shares of AEGCo, File No. 0-18135, Exhibit 3(a)].
3(b) -- Copy of the Code of Regulations of AEGCo [Registration
Statement on Form 10 for the Common Shares of AEGCo,
File No. 0-18135, Exhibit 3(b)].
10(a) -- Copy of Capital Funds Agreement dated as of December
30, 1988 between AEGCo and AEP [Registration Statement
No. 33-32752, Exhibit 28(a)].
10(b)(1) -- Copy of Unit Power Agreement dated as of March 31, 1982
between AEGCo and I&M, as amended [Registration
Statement No. 33-32752, Exhibits 28(b)(1)(A) and
28(b)(1)(B)].
10(b)(2) -- Copy of Unit Power Agreement, dated as of August 1,
1984, among AEGCo, I&M and KEPCo [Registration
Statement No. 33-32752, Exhibit 28(b)(2)].
10(b)(3) -- Copy of Agreement, dated as of October 1, 1984, among
AEGCo, I&M, APCo and Virginia Electric and Power
Company [Registration Statement No. 33-32752, Exhibit
28(b)(3)].
10(c) -- Copy of Lease Agreements, dated as of December 1, 1989,
between AEGCo and Wilmington Trust Company, as amended
[Registration Statement No. 33-32752, Exhibits
28(c)(1)(C), 28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C),
28(c)(5)(C) and 28(c)(6)(C); Annual Report on Form 10-K
of AEGCo for the fiscal year ended December 31, 1993,
File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B),
10(c)(3)(B), 10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B)].
*13 -- Copy of those portions of the AEGCo 1996 Annual Report
(for the fiscal year ended December 31, 1996) which are
incorporated by reference in this filing.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
AEP<double-dagger>
3(a) -- Copy of Restated Certificate of Incorporation of AEP,
dated April 26, 1978 [Registration Statement No.
2-62778, Exhibit 2(a)].
3(b)(1) -- Copy of Certificate of Amendment of the Restated
Certificate of Incorporation of AEP, dated April 23,
1980 [Registration Statement No. 33-1052, Exhibit
4(b)].
3(b)(2) -- Copy of Certificate of Amendment of the Restated
Certificate of Incorporation of AEP, dated April 28,
1982 [Registration Statement No. 33-1052, Exhibit
4(c)].
3(b)(3) -- Copy of Certificate of Amendment of the Restated
Certificate of Incorporation of AEP, dated April 25,
1984 [Registration Statement No. 33-1052, Exhibit
4(d)].
3(b)(4) -- Copy of Certificate of Change of the Restated
Certificate of Incorporation of AEP, dated July 5, 1984
[Registration Statement No. 33-1052, Exhibit 4(e)].
3(b)(5) -- Copy of Certificate of Amendment of the Restated
Certificate of Incorporation of AEP, dated April 27,
1988 [Registration Statement No. 33-1052, Exhibit
4(f)].
3(c) -- Composite copy of the Restated Certificate of
Incorporation of AEP, as amended [Registration
Statement No. 33-1052, Exhibit 4(g)].
*3(d) -- Copy of By-Laws of AEP, as amended through February 26,
1997.
10(a) -- Interconnection Agreement, dated July 6, 1951, among
APCo, CSPCo, KEPCo, OPCo and I&M and with the Service
Corporation, as amended [Registration Statement No.
2-52910, Exhibit 5(a); Registration Statement No.
2-61009, Exhibit 5(b); and Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 1990,
File No. 1-3525, Exhibit 10(a)(3)].
10(b) -- Copy of Transmission Agreement, dated April 1, 1984,
among APCo, CSPCo, I&M, KEPCo, OPCo and with the
Service Corporation as agent, as amended [Annual Report
on Form 10-K of AEP for the fiscal year ended December
31, 1985, File No. 1-3525, Exhibit 10(b); and Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
<dagger>10(c)(1) -- AEP Deferred Compensation Agreement for certain
executive officers [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1985, File No.
1-3525, Exhibit 10(e)].
<dagger>10(c)(2) -- Amendment to AEP Deferred Compensation Agreement for
certain executive officers [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 1986,
File No. 1-3525, Exhibit 10(d)(2)].
<dagger>10(d) -- AEP Deferred Compensation Agreement for directors, as
amended, effective October 24, 1984 [Annual Report on
Form 10-K of AEP for the fiscal year ended December 31,
1984, File No. 1-3525, Exhibit 10(e)].
<dagger>10(e) -- AEP Accident Coverage Insurance Plan for directors
[Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1985, File No. 1-3525, Exhibit
10(g)].
*<dagger>10(f)(1) -- AEP Deferred Compensation and Stock Plan for
Non-Employee Directors.
*<dagger>10(f)(2) -- AEP Stock Unit Accumulation Plan for Non-Employee
Directors.
<dagger>10(g)(1)(A) -- AEP Excess Benefit Plan, as amended through January 4,
1996 [Annual Report on Form 10-K of AEP for the fiscal
year ended December 31, 1995, File No. 1-3525, Exhibit
10(g)(1)(A)].
<dagger>10(g)(1)(B) -- Guaranty by AEP of the Service Corporation Excess
Benefits Plan [Annual Report on Form 10-K of AEP for
the fiscal year ended December 31, 1990, File No.
1-3525, Exhibit 10(h)(1)(B)].
*<dagger>10(g)(2) -- AEP System Supplemental Savings Plan, as amended
through November 15, 1995 (Non-Qualified).
<dagger>10(g)(3) -- Service Corporation Umbrella Trust<trade-mark> for
Executives [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1993, File No. 1-3525,
Exhibit 10(g)(3)].
<dagger>10(h)(1) -- Employment Agreement between E. Linn Draper, Jr. and
AEP and the Service Corporation [Annual Report on Form
10-K of AEGCo for the fiscal year ended December 31,
1991, File No. 0-18135, Exhibit 10(g)(3)].
*<dagger>10(i)(1) -- AEP System Senior Officer Annual Incentive Compensation
Plan.
*<dagger>10(i)(2) -- American Electric Power System Performance Share
Incentive Plan, as Amended and Restated through
February 26, 1997.
10(j) -- Copy of Lease Agreements, dated as of December 1, 1989,
between AEGCo or I&M and Wilmington Trust Company, as
amended [Registration Statement No. 33-32752, Exhibits
28(c)(1)(C), 28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C),
28(c)(5)(C) and 28(c)(6)(C); Registration Statement No.
33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C),
28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C);
and Annual Report on Form 10-K of AEGCo for the fiscal
year ended December 31, 1993, File No. 0-18135,
Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B),
10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B); Annual Report
on Form 10-K of I&M for the fiscal year ended December
31, 1993, File No. 1-3570, Exhibits 10(e)(1)(B),
10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and
10(e)(6)(B)].
10(k) -- Lease Agreement dated January 20, 1995 between OPCo and
JMG Funding, Limited Partnership, and amendment thereto
(confidential treatment requested) [Annual Report on
Form 10-K of OPCo for the fiscal year ended December
31, 1994, File No. 1-6543, Exhibit 10(l)(2)].
*10(l) -- Modification No. 1 to the AEP System Interim Allowance
Agreement, dated July 28, 1994, among APCo, CSPCo, I&M,
KEPCo, OPCo and the Service Corporation.
*13 -- Copy of those portions of the AEP 1996 Annual Report
(for the fiscal year ended December 31, 1996) which are
incorporated by reference in this filing.
*21 -- List of subsidiaries of AEP.
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
APCo<double-dagger>
3(a) -- Copy of Restated Articles of Incorporation of APCo, and
amendments thereto to November 4, 1993 [Registration
Statement No. 33-50163, Exhibit 4(a); Registration
Statement No. 33-53805, Exhibits 4(b) and 4(c)].
3(b) -- Copy of Articles of Amendment to the Restated Articles
of Incorporation of APCo, dated June 6, 1994 [Annual
Report on Form 10-K of APCo for the fiscal year ended
December 31, 1994, File No. 1-3457, Exhibit 3(b)].
*3(c) -- Copy of Articles of Amendment to the Restated Articles
of Incorporation of APCo, dated March 6, 1997.
*3(d) -- Composite copy of the Restated Articles of
Incorporation of APCo (amended as of March 7, 1997).
3(e) -- Copy of By-Laws of APCo (amended as of January 1, 1996)
[Annual Report on Form 10-K of APCo for the fiscal year
ended December 31, 1995, File No. 1-3457, Exhibit
3(d)].
4(a) -- Copy of Mortgage and Deed of Trust, dated as of
December 1, 1940, between APCo and Bankers Trust
Company and R. Gregory Page, as Trustees, as amended
and supplemented [Registration Statement No. 2-7289,
Exhibit 7(b); Registration Statement No. 2-19884,
Exhibit 2(1); Registration Statement No. 2-24453,
Exhibit 2(n); Registration Statement No. 2-60015,
Exhibits 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), 2(b)(6),
2(b)(7), 2(b)(8), 2(b)(9), 2(b)(10), 2(b)(12),
2(b)(14), 2(b)(15), 2(b)(16), 2(b)(17), 2(b)(18),
2(b)(19), 2(b)(20), 2(b)(21), 2(b)(22), 2(b)(23),
2(b)(24), 2(b)(25), 2(b)(26), 2(b)(27) and 2(b)(28);
Registration Statement No. 2-64102, Exhibit 2(b)(29);
Registration Statement No. 2-66457, Exhibits (2)(b)(30)
and 2(b)(31); Registration Statement No. 2-69217,
Exhibit 2(b)(32); Registration Statement No. 2-86237,
Exhibit 4(b); Registration Statement No. 33-11723,
Exhibit 4(b); Registration Statement No. 33-17003,
Exhibit 4(a)(ii), Registration Statement No. 33-30964,
Exhibit 4(b); Registration Statement No. 33-40720,
Exhibit 4(b); Registration Statement No. 33-45219,
Exhibit 4(b); Registration Statement No. 33-46128,
Exhibits 4(b) and 4(c); Registration Statement No.
33-53410, Exhibit 4(b); Registration Statement No.
33-59834, Exhibit 4(b); Registration Statement No.
33-50229, Exhibits 4(b) and 4(c); Registration
Statement No. 33-58431, Exhibits 4(b), 4(c), 4(d) and
4(e); Registration Statement No. 333-01049, Exhibits
4(b) and 4(c); Registration Statement No. 333-20305,
Exhibits 4(b) and 4(c)].
*4(b) -- Copy of Indenture Supplemental, dated as of February 1,
1997, to Mortgage and Deed of Trust.
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952,
between OVEC and United States of America, acting by
and through the United States Atomic Energy Commission,
and, subsequent to January 18, 1975, the Administrator
of the Energy Research and Development Administration,
as amended [Registration Statement No. 2-60015, Exhibit
5(a); Registration Statement No. 2-63234, Exhibit
5(a)(1)(B); Registration Statement No. 2-66301, Exhibit
5(a)(1)(C); Registration Statement No. 2-67728, Exhibit
5(a)(1)(D); Annual Report on Form 10-K of APCo for the
fiscal year ended December 31, 1989, File No. 1-3457,
Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1992, File
No. 1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated as of July
10, 1953, among OVEC and the Sponsoring Companies, as
amended [Registration Statement No. 2-60015, Exhibit
5(c); Registration Statement No. 2-67728, Exhibit
5(a)(3)(B); and Annual Report on Form 10-K of APCo for
the fiscal year ended December 31, 1992, File No.
1-3457, Exhibit 10(a)(2)(B)].
10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between
OVEC and Indiana-Kentucky Electric Corporation, as
amended [Registration Statement No. 2-60015, Exhibit
5(e)].
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951,
among APCo, CSPCo, KEPCo, OPCo and I&M and with the
Service Corporation, as amended [Registration Statement
No. 2-52910, Exhibit 5(a); Registration Statement No.
2-61009, Exhibit 5(b); Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 1990, File
No. 1-3525, Exhibit 10(a)(3)].
10(c) -- Copy of Transmission Agreement, dated April 1, 1984,
among APCo, CSPCo, I&M, KEPCo, OPCo and with the
Service Corporation as agent, as amended [Annual Report
on Form 10-K of AEP for the fiscal year ended December
31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report
on Form 10-K of AEP for the fiscal year ended December
31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
10(d) -- Copy of Modification No. 1 to the AEP System Interim
Allowance Agreement, dated July 28, 1994, among APCo,
CSPCo, I&M, KEPCo, OPCo and the Service Corporation
[Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1996, File No. 1-3525, Exhibit
10(l)].
<dagger>10(e)(1) -- AEP Deferred Compensation Agreement for certain
executive officers [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1985, File No.
1-3525, Exhibit 10(e)].
<dagger>10(e)(2) -- Amendment to AEP Deferred Compensation Agreement for
certain executive officers [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 1986,
File No. 1-3525, Exhibit 10(d)(2)].
<dagger>10(f)(1) -- AEP System Senior Officer Annual Incentive Compensation
Plan [Annual Report on Form 10-K of AEP for the fiscal
year ended December 31, 1996, File No. 1-3525, Exhibit
10(i)(1)].
<dagger>10(f)(2) -- American Electric Power System Performance Share
Incentive Plan as Amended and Restated through February
26, 1997 [Annual Report on Form 10-K of AEP for the
fiscal year ended December 31, 1996, File No. 1-3525,
Exhibit 10(i)(2)].
<dagger>10(g)(1) -- Excess Benefits Plan [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1995, File No.
1-3525, Exhibit 10(g)(1)(A)].
<dagger>10(g)(2) -- AEP System Supplemental Savings Plan (Non-Qualified)
[Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1996, File No. 1-3525, Exhibit
10(g)(2)].
<dagger>10(g)(3) -- Umbrella Trust<trade-mark> for Executives [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)].
<dagger>10(h)(1) -- Employment Agreement between E. Linn Draper, Jr. and
AEP and the Service Corporation [Annual Report on Form
10-K of AEGCo for the fiscal year ended December 31,
1991, File No. 0-18135, Exhibit 10(g)(3)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the APCo 1996 Annual Report
(for the fiscal year ended December 31, 1996) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of APCo [Annual Report on Form
10-K of AEP for the fiscal year ended December 31,
1996, File No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
CSPCo<double-dagger>
3(a) -- Copy of Amended Articles of Incorporation of CSPCo, as
amended to March 6, 1992 [Registration Statement No.
33-53377, Exhibit 4(a)].
3(b) -- Copy of Certificate of Amendment to Amended Articles of
Incorporation of CSPCo, dated May 19, 1994 [Annual
Report on Form 10-K of CSPCo for the fiscal year ended
December 31, 1994, File No. 1-2680, Exhibit 3(b)].
3(c) -- Composite copy of Amended Articles of Incorporation of
CSPCo, as amended [Annual Report on Form 10-K of CSPCo
for the fiscal year ended December 31, 1994, File No.
1-2680, Exhibit 3(c)].
3(d) -- Copy of Code of Regulations and By-Laws of CSPCo
[Annual Report on Form 10-K of CSPCo for the fiscal
year ended December 31, 1987, File No. 1-2680, Exhibit
3(d)].
4(a) -- Copy of Indenture of Mortgage and Deed of Trust, dated
September 1, 1940, between CSPCo and City Bank Farmers
Trust Company (now Citibank, N.A.), as trustee, as
supplemented and amended [Registration Statement No.
2-59411, Exhibits 2(B) and 2(C); Registration Statement
No. 2-80535, Exhibit 4(b); Registration Statement No.
2-87091, Exhibit 4(b); Registration Statement No.
2-93208, Exhibit 4(b); Registration Statement No.
2-97652, Exhibit 4(b); Registration Statement No.
33-7081, Exhibit 4(b); Registration Statement No.
33-12389, Exhibit 4(b); Registration Statement No.
33-19227, Exhibits 4(b), 4(e), 4(f), 4(g) and 4(h);
Registration Statement No. 33-35651, Exhibit 4(b);
Registration Statement No. 33-46859, Exhibits 4(b) and
4(c); Registration Statement No. 33-50316, Exhibits
4(b) and 4(c); Registration Statement No. 33-60336,
Exhibits 4(b), 4(c) and 4(d); Registration Statement
No. 33-50447, Exhibits 4(b) and 4(c); Annual Report on
Form 10-K of CSPCo for the fiscal year ended December
31, 1993, File No. 1-2680, Exhibit 4(b)].
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952,
between OVEC and United States of America, acting by
and through the United States Atomic Energy Commission,
and, subsequent to January 18, 1975, the Administrator
of the Energy Research and Development Administration,
as amended [Registration Statement No. 2-60015, Exhibit
5(a); Registration Statement No. 2-63234, Exhibit
5(a)(1)(B); Registration Statement No. 2-66301, Exhibit
5(a)(1)(C); Registration Statement No. 2-67728, Exhibit
5(a)(1)(B); Annual Report on Form 10-K of APCo for the
fiscal year ended December 31, 1989, File No. 1-3457,
Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1992, File
No. 1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10,
1953, among OVEC and the Sponsoring Companies, as
amended [Registration Statement No. 2-60015, Exhibit
5(c); Registration Statement No. 2-67728, Exhibit
5(a)(3)(B); and Annual Report on Form 10-K of APCo for
the fiscal year ended December 31, 1992, File No.
1-3457, Exhibit 10(a)(2)(B)].
10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between
OVEC and Indiana-Kentucky Electric Corporation, as
amended [Registration Statement No. 2-60015, Exhibit
5(e)].
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951,
among APCo, CSPCo, KEPCo, OPCo and I&M and the Service
Corporation, as amended [Registration Statement No.
2-52910, Exhibit 5(a); Registration Statement No.
2-61009, Exhibit 5(b); and Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 1990,
File No. 1-3525, Exhibit 10(a)(3)].
10(c) -- Copy of Transmission Agreement, dated April 1, 1984,
among APCo, CSPCo, I&M, KEPCo, OPCo, and with the
Service Corporation as agent, as amended [Annual Report
on Form 10-K of AEP for the fiscal year ended December
31, 1985, File No. 1-3525, Exhibit 10(b); and Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
10(d) -- Copy of Modification No. 1 to the AEP System Interim
Allowance Agreement, dated July 28, 1994, among APCo,
CSPCo, I&M, KEPCo, OPCo and the Service Corporation
[Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1996, File No. 1-3525, Exhibit
10(l)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the CSPCo 1996 Annual Report
(for the fiscal year ended December 31, 1996) which are
incorporated by reference in this filing.
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
I&M<double-dagger>
3(a) -- Copy of the Amended Articles of Acceptance of I&M and
amendments thereto [Annual Report on Form 10-K of I&M
for fiscal year ended December 31, 1993, File No.
1-3570, Exhibit 3(a)].
*3(b) -- Copy of Articles of Amendment to the Amended Articles
of Acceptance of I&M, dated March 6, 1997.
*3(c) -- Composite Copy of the Amended Articles of Acceptance of
I&M (amended as of March 7, 1997).
3(d) -- Copy of the By-Laws of I&M (amended as of January 1,
1996) [Annual Report on Form 10-K of I&M for fiscal
year ended December 31, 1995, File No. 1-3570, Exhibit
3(c)].
4(a) -- Copy of Mortgage and Deed of Trust, dated as of June 1,
1939, between I&M and Irving Trust Company (now The
Bank of New York) and various individuals, as Trustees,
as amended and supplemented [Registration Statement No.
2-7597, Exhibit 7(a); Registration Statement No.
2-60665, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5),
2(c)(6), 2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11),
2(c)(12), 2(c)(13), 2(c)(14), 2(c)(15), (2)(c)(16), and
2(c)(17); Registration Statement No. 2-63234, Exhibit
2(b)(18); Registration Statement No. 2-65389, Exhibit
2(a)(19); Registration Statement No. 2-67728, Exhibit
2(b)(20); Registration Statement No. 2-85016, Exhibit
4(b); Registration Statement No. 33-5728, Exhibit 4(c);
Registration Statement No. 33-9280, Exhibit 4(b);
Registration Statement No. 33-11230, Exhibit 4(b);
Registration Statement No. 33-19620, Exhibits 4(a)(ii),
4(a)(iii), 4(a)(iv) and 4(a)(v); Registration Statement
No. 33-46851, Exhibits 4(b)(i), 4(b)(ii) and 4(b)(iii);
Registration Statement No. 33-54480, Exhibits 4(b)(i)
and 4(b)(ii); Registration Statement No. 33-60886,
Exhibit 4(b)(i); Registration Statement No. 33-50521,
Exhibits 4(b)(i), 4(b)(ii) and 4(b)(iii); Annual Report
on Form 10-K of I&M for fiscal year ended December 31,
1993, File No. 1-3570, Exhibit 4(b); Annual Report on
Form 10-K of I&M for fiscal year ended December 31,
1994, File No. 1-3570, Exhibit 4(b)].
*4(b) -- Copy of Indenture Supplemental, dated as of February 1,
1997, to Mortgage and Deed of Trust.
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952,
between OVEC and United States of America, acting by
and through the United States Atomic Energy Commission,
and, subsequent to January 18, 1975, the Administrator
of the Energy Research and Development Administration,
as amended [Registration Statement No. 2-60015, Exhibit
5(a); Registration Statement No. 2-63234, Exhibit
5(a)(1)(B); Registration Statement No. 2-66301, Exhibit
5(a)(1)(C); Registration Statement No. 2-67728, Exhibit
5(a)(1)(D); Annual Report on Form 10-K of APCo for the
fiscal year ended December 31, 1989, File No. 1-3457,
Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of
APCo for the fiscal year ended December 31, 1992, File
No. 1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated as of July
10, 1953, among OVEC and the Sponsoring Companies, as
amended [Registration Statement No. 2-60015, Exhibit
5(c); Registration Statement No. 2-67728, Exhibit
5(a)(3)(B); Annual Report on Form 10-K of APCo for the
fiscal year ended December 31, 1992, File No. 1-3457,
Exhibit 10(a)(2)(B)].
10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between
OVEC and Indiana-Kentucky Electric Corporation, as
amended [Registration Statement No. 2-60015, Exhibit
5(e)].
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951,
between APCo, CSPCo, KEPCo, I&M, and OPCo and with the
Service Corporation, as amended [Registration Statement
No. 2-52910, Exhibit 5(a); Registration Statement No.
2-61009, Exhibit 5(b); and Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 1990,
File No. 1-3525, Exhibit 10(a)(3)].
10(c) -- Copy of Transmission Agreement, dated April 1, 1984,
among APCo, CSPCo, I&M, KEPCo, OPCo and with the
Service Corporation as agent, as amended [Annual Report
on Form 10-K of AEP for the fiscal year ended December
31, 1985, File No. 1-3525, Exhibit 10(b); and Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
10(d) -- Copy of Modification No. 1 to the AEP System Interim
Allowance Agreement, dated July 28, 1994, among APCo,
CSPCo, I&M, KEPCo, OPCo and the Service Corporation
[Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1996, File No. 1-3525, Exhibit
10(l)].
10(e) -- Copy of Nuclear Material Lease Agreement, dated as of
December 1, 1990, between I&M and DCC Fuel Corporation
[Annual Report on Form 10-K of I&M for the fiscal year
ended December 31, 1993, File No. 1-3570, Exhibit
10(d)].
10(f) -- Copy of Lease Agreements, dated as of December 1, 1989,
between I&M and Wilmington Trust Company, as amended
[Registration Statement No. 33-32753, Exhibits
28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C),
28(a)(5)(C) and 28(a)(6)(C); Annual Report on Form 10-K
of I&M for the fiscal year ended December 31, 1993,
File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B),
10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)].
*12 -- Statement re: Computation of Ratios
*13 -- Copy of those portions of the I&M 1996 Annual Report
(for the fiscal year ended December 31, 1996) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of I&M [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 1996,
File No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
KEPCo<double-dagger>
3(a) -- Copy of Restated Articles of Incorporation of KEPCo
[Annual Report on Form 10-K of KEPCo for the fiscal
year ended December 31, 1991, File No. 1-6858, Exhibit
3(a)].
3(b) -- Copy of By-Laws of KEPCo (amended as of January 1,
1996) [Annual Report on Form 10-K of KEPCo for the
fiscal year ended December 31, 1995, File No. 1-6858,
Exhibit 3(b)].
4(a) -- Copy of Mortgage and Deed of Trust, dated May 1, 1949,
between KEPCo and Bankers Trust Company, as
supplemented and amended [Registration Statement No.
2-65820, Exhibits 2(b)(1), 2(b)(2), 2(b)(3), 2(b)(4),
2(b)(5), and 2(b)(6); Registration Statement No.
33-39394, Exhibits 4(b) and 4(c); Registration
Statement No. 33-53226, Exhibits 4(b) and 4(c);
Registration Statement No. 33-61808, Exhibits 4(b) and
4(c), Registration Statement No. 33-53007, Exhibits
4(b), 4(c) and 4(d)].
10(a) -- Copy of Interconnection Agreement, dated July 6, 1951,
among APCo, CSPCo, KEPCo, I&M and OPCo and with the
Service Corporation, as amended [Registration Statement
No. 2-52910, Exhibit 5(a); Registration Statement No.
2-61009, Exhibit 5(b); and Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 1990,
File No. 1-3525, Exhibit 10(a)(3)].
10(b) -- Copy of Transmission Agreement, dated April 1, 1984,
among APCo, CSPCo, I&M, KEPCo, OPCo and with the
Service Corporation as agent, as amended [Annual Report
on Form 10-K of AEP for the fiscal year ended December
31, 1985, File No. 1-3525, Exhibit 10(b); and Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].
10(c) -- Copy of Modification No. 1 to the AEP System Interim
Allowance Agreement, dated July 28, 1994, among APCo,
CSPCo, I&M, KEPCo, OPCo and the Service Corporation
[Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1996, File No. 1-3525, Exhibit
10(l)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy those portions of the KEPCo 1996 Annual Report
(for the fiscal year ended December 31, 1996) which are
incorporated by reference in this filing.
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
OPCo<double-dagger>
3(a) -- Copy of Amended Articles of Incorporation of OPCo, and
amendments thereto to December 31, 1993 [Registration
Statement No. 33-50139, Exhibit 4(a); Annual Report on
Form 10-K of OPCo for the fiscal year ended December
31, 1993, File No. 1-6543, Exhibit 3(b)].
3(b) -- Certificate of Amendment to Amended Articles of
Incorporation of OPCo, dated May 3, 1994 [Annual Report
on Form 10-K of OPCo for the fiscal year ended December
31, 1994, File No. 1-6543, Exhibit 3(b)].
*3(c) -- Copy of Certificate of Amendment to Amended Articles of
Incorporation of OPCo, dated March 6, 1997.
*3(d) -- Composite copy of the Amended Articles of Incorporation
of OPCo (amended as of March 7, 1997).
3(e) -- Copy of Code of Regulations of OPCo [Annual Report on
Form 10-K of OPCo for the fiscal year ended December
31, 1990, File No. 1-6543, Exhibit 3(d)].
4(a) -- Copy of Mortgage and Deed of Trust, dated as of October
1, 1938, between OPCo and Manufacturers Hanover Trust
Company (now Chemical Bank), as Trustee, as amended and
supplemented [Registration Statement No. 2-3828,
Exhibit B-4; Registration Statement No. 2-60721,
Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6),
2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11),
2(c)(12), 2(c)(13), 2(c)(14), 2(c)(15), 2(c)(16),
2(c)(17), 2(c)(18), 2(c)(19), 2(c)(20), 2(c)(21),
2(c)(22), 2(c)(23), 2(c)(24), 2(c)(25), 2(c)(26),
2(c)(27), 2(c)(28), 2(c)(29), 2(c)(30), and 2(c)(31);
Registration Statement No. 2-83591, Exhibit 4(b);
Registration Statement No. 33-21208, Exhibits 4(a)(ii),
4(a)(iii) and 4(a)(vi); Registration Statement No.
33-31069, Exhibit 4(a)(ii); Registration Statement No.
33-44995, Exhibit 4(a)(ii); Registration Statement No.
33-59006, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv);
Registration Statement No. 33-50373, Exhibits 4(a)(ii),
4(a)(iii) and 4(a)(iv); Annual Report on Form 10-K of
OPCo for the fiscal year ended December 31, 1993, File
No. 1-6543, Exhibit 4(b)].
10(a)(1) -- Copy of Power Agreement, dated October 15, 1952,
between OVEC and United States of America, acting by
and through the United States Atomic Energy Commission,
and, subsequent to January 18, 1975, the Administrator
of the Energy Research and Development Administration,
as amended [Registration Statement No. 2-60015, Exhibit
5(a); Registration Statement No. 2-63234, Exhibit
5(a)(1)(B); Registration Statement No. 2-66301, Exhibit
5(a)(1)(C); Registration Statement No. 2-67728, Exhibit
5(a)(1)(D); Annual Report on Form 10-K of APCo for the
fiscal year ended December 31, 1989, File No. 1-3457,
Exhibit 10(a)(1)(F); Annual Report on Form 10-K of APCo
for the fiscal year ended December 31, 1992, File No.
1-3457, Exhibit 10(a)(1)(B)].
10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10,
1953, among OVEC and the Sponsoring Companies, as
amended [Registration Statement No. 2-60015, Exhibit
5(c); Registration Statement No. 2-67728, Exhibit
5(a)(3)(B); Annual Report on Form 10-K of APCo for the
fiscal year ended December 31, 1992, File No. 1-3457,
Exhibit 10(a)(2)(B)].
10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between
OVEC and Indiana-Kentucky Electric Corporation, as
amended [Registration Statement No. 2-60015, Exhibit
5(e)].
10(b) -- Copy of Interconnection Agreement, dated July 6, 1951,
between APCo, CSPCo, KEPCo, I&M and OPCo and with the
Service Corporation, as amended [Registration Statement
No. 2-52910, Exhibit 5(a); Registration Statement No.
2-61009, Exhibit 5(b); Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 1990, File
1-3525, Exhibit 10(a)(3)].
10(c) -- Copy of Transmission Agreement, dated April 1, 1984,
among APCo, CSPCo, I&M, KEPCo, OPCo and with the
Service Corporation as agent [Annual Report on Form
10-K of AEP for the fiscal year ended December 31,
1985, File No. 1-3525, Exhibit 10(b); Annual Report on
Form 10-K of AEP for the fiscal year ended December 31,
1988, File No. 1-3525, Exhibit 10(b)(2)].
10(d) -- Copy of Modification No. 1 to the AEP System Interim
Allowance Agreement, dated July 28, 1994, among APCo,
CSPCo, I&M, KEPCo, OPCo and the Service Corporation
[Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1996, File No. 1-3525, Exhibit
10(l)].
10(e) -- Copy of Amendment No. 1, dated October 1, 1973, to
Station Agreement dated January 1, 1968, among OPCo,
Buckeye and Cardinal Operating Company, and amendments
thereto [Annual Report on Form 10-K of OPCo for the
fiscal year ended December 31, 1993, File No. 1-6543,
Exhibit 10(f)].
<dagger>10(f)(1) -- AEP Deferred Compensation Agreement for certain
executive officers [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1985, File No.
1-3525, Exhibit 10(e)].
<dagger>10(f)(2) -- Amendment to AEP Deferred Compensation Agreement for
certain executive officers [Annual Report on Form 10-K
of AEP for the fiscal year ended December 31, 1986,
File No. 1-3525, Exhibit 10(d)(2)].
<dagger>10(g)(1) -- AEP System Senior Officer Annual Incentive Compensation
Plan [Annual Report on Form 10-K of AEP for the fiscal
year ended December 31, 1996, File No. 1-3525, Exhibit
10(i)(1)].
<dagger>10(g)(2) -- American Electric Power System Performance Share
Incentive Plan, as Amended and Restated through
February 26, 1997 [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1996, File No.
1-3525, Exhibit 10(i)(2)].
<dagger>10(h)(1) -- Excess Benefits Plan [Annual Report on Form 10-K of AEP
for the fiscal year ended December 31, 1995, File No.
1-3525, Exhibit 10(g)(1)(A)].
<dagger>10(h)(2) -- AEP System Supplemental Savings Plan (Non-Qualified)
[Annual Report on Form 10-K of AEP for the fiscal year
ended December 31, 1996, File No. 1-3525, Exhibit
10(g)(2)].
<dagger>10(h)(3) -- Umbrella Trust<trade-mark> for Executives [Annual
Report on Form 10-K of AEP for the fiscal year ended
December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)].
<dagger>10(i)(1) -- Employment Agreement between E. Linn Draper, Jr. and
AEP and the Service Corporation [Annual Report on Form
10-K of AEGCo for the fiscal year ended December 31,
1991, File No. 0-18135, Exhibit 10(g)(2)].
10(j) -- Lease Agreement dated January 20, 1995 between OPCo and
JMG Funding, Limited Partnership, and amendment thereto
(confidential treatment requested) [Annual Report on
Form 10-K of OPCo for the fiscal year ended December
31, 1994, File No. 1-6543, Exhibit 10(l)(2)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the OPCo 1996 Annual Report
(for the fiscal year ended December 31, 1996) which are
incorporated by reference in this filing.
21 -- List of subsidiaries of OPCo [Annual Report on Form
10-K of AEP for the fiscal year ended December 31,
1996, File No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
<double-dagger>Certain instruments defining the rights of holders of long-term
debt of the registrants included in the financial statements of registrants
filed herewith have been omitted because the total amount of securities
authorized thereunder does not exceed 10% of the total assets of registrants.
The registrants hereby agree to furnish a copy of any such omitted instrument
to the SEC upon request.
<PAGE>
<TABLE>
EXHIBIT 12
COLUMBUS SOUTHERN POWER COMPANY
Computation of Consolidated Ratios of Earnings to Fixed Charges
(in thousands except ratio data)
<CAPTION>
Year Ended December 31,
1992 1993 1994 1995 1996
<S> <C> <C> <C> <C> <C>
Fixed Charges:
Interest on First Mortgage Bonds. . . . . . . . $75,866 $74,119 $68,471 $ 66,811 $59,711
Interest on Other Long-term Debt. . . . . . . . 11,430 10,436 10,221 8,829 12,125
Interest on Short-term Debt . . . . . . . . . . 3,282 1,305 817 1,328 2,400
Miscellaneous Interest Charges. . . . . . . . . 3,158 4,036 4,566 4,657 4,374
Estimated Interest Element in Lease Rentals . . 4,100 3,700 3,700 4,100 4,600
Total Fixed Charges. . . . . . . . . . . . $97,836 $93,596 $87,775 $ 85,725 $83,210
Earnings:
Net Income (Loss) . . . . . . . . . . . . . . . $ 76,244 $(55,898) $109,845 $110,616 $107,108
Plus Federal Income Taxes . . . . . . . . . . . 27,389 34,154 49,838 58,648 60,302
Plus State Income Taxes . . . . . . . . . . . . - - 1 7 11
Plus Fixed Charges (as above) . . . . . . . . . 97,836 93,596 87,775 85,725 83,210
Total Earnings . . . . . . . . . . . . . . $201,469 $ 71,852 $247,459 $254,996 $250,631
Ratio of Earnings to Fixed Charges. . . . . . . . 2.05 0.76(a) 2.81 2.97 3.01
(a) Ratio includes the effect of the Loss from Zimmer Plant Disallowance of $144,533,000 (net of applicable
income taxes of $14,534,000). As a result, earnings for the twelve months ended December 31, 1993 were
inadequate to cover fixed charges by $21,744,000. If the effect of the Loss from Zimmer Plant Disallowance
were excluded, the ratio would be 2.46 for the twelve months ended December 31, 1993.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
Selected Consolidated Financial Data
<CAPTION>
Year Ended December 31,
1996 1995 1994 1993 1992
(in thousands)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENTS DATA:
Operating Revenues $1,105,683 $1,071,862 $1,031,151 $953,652 $843,996
Operating Expenses 920,136 886,054 845,283 803,436 721,681
Operating Income 185,547 185,808 185,868 150,216 122,315
Nonoperating Income (Loss) (970) 5,202 7,030 27,343 47,170
Loss from Zimmer Plant Disallowance
(net of tax) - - - 144,533 -
Income Before Interest Charges 184,577 191,010 192,898 33,026 169,485
Interest Charges (net) 77,469 80,394 83,053 88,924 93,241
Net Income (Loss) 107,108 110,616 109,845 (55,898) 76,244
Preferred Stock Dividend Requirements 6,029 11,907 12,084 11,062 10,220
Earnings (Loss) Applicable
to Common Stock $ 101,079 $ 98,709 $ 97,761 $ (66,960) $ 66,024
<CAPTION>
December 31,
1996 1995 1994 1993 1992
(in thousands)
<S> <C> <C> <C> <C> <C>
BALANCE SHEETS DATA:
Electric Utility Plant $2,899,893 $2,820,208 $2,729,577 $2,645,055 $2,724,506
Accumulated Depreciation 1,016,909 953,170 884,237 811,817 754,367
Net Electric Utility Plant $1,882,984 $1,867,038 $1,845,340 $1,833,238 $1,970,139
Total Assets $2,541,586 $2,594,126 $2,594,342 $2,582,671 $2,371,370
Common Stock and
Paid-in Capital $ 615,735 $ 615,453 $ 606,668 $ 607,072 $ 607,072
Retained Earnings 99,582 74,320 46,976 18,288 127,562
Total Common Shareholder's Equity $ 715,317 $ 689,773 $ 653,644 $ 625,360 $ 734,634
Cumulative Preferred Stock - Subject
to Mandatory Redemption (a) $ 75,000 $ 82,500 $ 150,000 $ 125,000 $ 125,000
Long-term Debt (a) $ 897,281 $ 990,796 $ 997,608 $1,017,713 $ 977,921
Obligations Under Capital Leases (a) $ 36,134 $ 27,816 $ 24,452 $ 15,237 $ 9,951
Total Capitalization and Liabilities $ 2,541,586 $2,594,126 $2,594,342 $2,582,671 $2,371,370
(a) Including portion due within one year.
</TABLE>
<PAGE>
<PAGE>
MANAGEMENT'S NARRATIVE ANALYSIS OF
RESULTS OF OPERATIONS
Net Income Decreases
Net income declined 3% in 1996 compared with 1995 primarily due to a
decline in nonoperating income partially offset by a reduction in interest
charges. Operating income remained relatively unchanged as increased energy
sales were offset by corresponding increases in operating expenses.
Operating revenues increased $34 million or 3% in 1996 reflecting
increased energy usage by wholesale and to a lesser extent by retail
customers and increased fuel costs recoveries as shown in the following price
volume analysis:
Increase (Decrease)
(dollars in millions) From Previous Year
Amount %
Retail:
Price Variance . . . . . . . . $ (8.3)
Volume Variance. . . . . . . . 9.3
Fuel Cost Recoveries . . . . . 11.0
12.0 1.2
Wholesale:
Price Variance . . . . . . . . (31.3)
Volume Variance. . . . . . . . 49.3
18.0 23.9
Other Operating Revenues. . . . . 3.8
Total . . . . . . . . . . . . . $ 33.8 3.2
The increase in retail operating revenues in 1996 was due to increased
energy sales to commercial and industrial customers and increased fuel clause
revenues from retail customers. Growth in the number of commercial customers
and increased usage by industrial customers accounted for the increased retail
demand. Sales to weather sensitive residential customers were steady as the
effect of cold winter weather in early 1996 was offset by mild summer and
December temperatures. The Public Utilities Commission of Ohio fuel clause
adjustment mechanism permits the recovery of previously deferred underrecovered
fuel costs. The increase in fuel clause revenues did not affect net income
since it was offset by the amortization of underrecovered deferred fuel costs.
Wholesale revenues increased significantly primarily due to increased
energy sales to unaffiliated utilities and new wholesale transactions. During
1996 the Company, through the Power Pool, shared in sales of a new product, coal
conversion services, which resulted in 1.1 billion kilowatthours of electricity
being provided to power marketers and certain non-affiliated utilities under a
new Federal Energy Regula-
tory Commission approved interruptible tariff. Since these new sales are for
the service of converting the customers' coal to electricity and do not include
recovery of a fuel cost, the average wholesale price per kilowatthour was
significantly less in 1996 than in 1995.
<PAGE>
Operating Expenses Increase
Operating expenses increased $34 million or 3.8% in 1996. Changes in the
components of operating expenses were as follows:
Increase (Decrease)
(dollars in millions) From Previous Year
Amount %
Fuel. . . . . . . . . . . . . . . $19.0 11.2
Purchased Power . . . . . . . . . 1.4 0.8
Other Operation . . . . . . . . . 6.2 3.3
Maintenance . . . . . . . . . . . (5.6) (7.9)
Depreciation and Amortization . . 3.3 2.8
Taxes Other Than Federal
Income Taxes. . . . . . . . . . 5.8 5.3
Federal Income Taxes. . . . . . . 4.0 6.8
Total . . . . . . . . . . . . . $34.1 3.8
Fuel expense increased 11% primarily due to the operation of the fuel
clause adjustment mechanism whereby the amortization of previously deferred
underrecovered fuel costs resulted in increased fuel expense commensurate
with recovery in rates. A 5% increase in net generation to meet increased
demand also contributed to the increased fuel expense.
The increase in other operation expense was due to increased marketing
expenses and uncollectible accounts expense.
Maintenance expense decreased by 8% due mainly to the effect of
workforce reductions at the Company's power plants and reduced plant
maintenance work. Maintenance expense in 1995 included expenditures
associated with outages at the Conesville and Picway plants while in 1996
these plants experienced less extensive maintenance outages.
The increase in taxes other than federal income taxes was due primarily
to higher gross receipts taxes as a result of increased revenues during the
assessment period and increased property taxes due to increases in assessed
property values and tax rates.
Federal income taxes attributable to operations increased primarily due
to an increase in pre-tax operating income and changes in certain book/tax
differences accounted for on a flow-through basis for rate-making purposes.
Nonoperating Income and Interest Charges Decrease
Nonoperating income declined by $6 million during 1996 due to losses
from certain deferred demand side management programs; costs for the clean-up
of underground fuel storage tanks at one of the Company's facilities; a
decline in the return on unrecovered Zimmer Plant deferrals due to a
declining balance of unamortized Zimmer Plant phase-in deferrals; reduced
interest income; and expenses of AEP's branding campaign. The recordation in
1995 of interest income relating to the settlement of the Internal Revenue
Service audit for the years 1988-1990 accounted for the decrease in interest
income. The AEP branding campaign is an advertising program to inform
customers that the Company is operating under the name American Electric
Power and to identify the Company as more than just a supplier of
electricity; AEP: America's Energy Partner.
Interest charges decreased as the Company continued a refinancing
program that reduced the average interest rate and the amount of long-term
debt outstanding. The redemption of the 9.50% series of preferred stock in
late 1995 and early 1996 accounted for the decrease in preferred stock
dividends.
<PAGE>
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Columbus Southern
Power Company:
We have audited the accompanying consolidated balance sheets of Columbus
Southern Power Company and its subsidiaries as of December 31, 1996 and 1995,
and the related consolidated statements of income, retained earnings, and
cash flows for each of the three years in the period ended December 31, 1996.
These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Columbus Southern Power Company
and its subsidiaries as of December 31, 1996 and 1995, and the results of
their operations and their cash flows for each of the three years in the
period ended December 31, 1996 in conformity with generally accepted
accounting principles.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 25, 1997
<PAGE>
<PAGE>
<TABLE>
Consolidated Statements of Income
<CAPTION>
Year Ended December 31,
1996 1995 1994
(in thousands)
<S> <C> <C> <C>
OPERATING REVENUES $1,105,683 $1,071,862 $1,031,151
OPERATING EXPENSES:
Fuel 188,746 169,791 204,210
Purchased Power 168,894 167,517 134,540
Other Operation 196,762 190,542 175,102
Maintenance 65,414 71,022 71,629
Depreciation 88,070 85,448 83,180
Amortization (Deferral) of Zimmer Plant
Phase-in Costs 33,937 33,268 27,144
Taxes Other Than Federal Income Taxes 115,518 109,680 102,672
Federal Income Taxes 62,795 58,786 46,806
TOTAL OPERATING EXPENSES 920,136 886,054 845,283
OPERATING INCOME 185,547 185,808 185,868
NONOPERATING INCOME (LOSS) (970) 5,202 7,030
INCOME BEFORE INTEREST CHARGES 184,577 191,010 192,898
INTEREST CHARGES 77,469 80,394 83,053
NET INCOME 107,108 110,616 109,845
PREFERRED STOCK DIVIDEND REQUIREMENTS 6,029 11,907 12,084
EARNINGS APPLICABLE TO COMMON STOCK $ 101,079 $ 98,709 $ 97,761
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
Consolidated Balance Sheets
<CAPTION>
December 31,
1996 1995
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production $1,503,371 $1,481,309
Transmission 326,247 314,413
Distribution 885,267 843,228
General 130,946 117,185
Construction Work in Progress 54,062 64,073
Total Electric Utility Plant 2,899,893 2,820,208
Accumulated Depreciation 1,016,909 953,170
NET ELECTRIC UTILITY PLANT 1,882,984 1,867,038
OTHER PROPERTY AND INVESTMENTS 24,069 25,950
CURRENT ASSETS:
Cash and Cash Equivalents 9,134 10,577
Accounts Receivable:
Customers 50,557 52,390
Affiliated Companies 4,446 4,465
Miscellaneous 9,032 10,059
Allowance for Uncollectible Accounts (1,032) (1,061)
Fuel - at average cost 18,278 24,316
Materials and Supplies - at average cost 23,999 23,519
Accrued Utility Revenues 31,826 40,389
Prepayments 32,330 32,116
TOTAL CURRENT ASSETS 178,570 196,770
REGULATORY ASSETS 385,689 438,005
DEFERRED CHARGES 70,274 66,363
TOTAL $2,541,586 $2,594,126
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
December 31,
1996 1995
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares $ 41,026 $ 41,026
Paid-in Capital 574,709 574,427
Retained Earnings 99,582 74,320
Total Common Shareholder's Equity 715,317 689,773
Cumulative Preferred Stock -
Subject to Mandatory Redemption 25,000 75,000
Long-term Debt 882,641 990,796
TOTAL CAPITALIZATION 1,622,958 1,755,569
OTHER NONCURRENT LIABILITIES 40,068 34,571
CURRENT LIABILITIES:
Preferred Stock Due Within One Year 50,000 7,500
Long-term Debt Due Within One Year 14,640 -
Short-term Debt 51,800 34,325
Accounts Payable - General 34,619 31,276
Accounts Payable - Affiliated Companies 20,209 20,753
Taxes Accrued 129,429 120,093
Interest Accrued 13,605 17,016
Other 32,314 30,955
TOTAL CURRENT LIABILITIES 346,616 261,918
DEFERRED INCOME TAXES 441,477 464,413
DEFERRED INVESTMENT TAX CREDITS 57,101 61,010
DEFERRED CREDITS 33,366 16,645
COMMITMENTS AND CONTINGENCIES (Note 3)
TOTAL $2,541,586 $2,594,126
</TABLE>
<PAGE>
<PAGE>
<TABLE>
Consolidated Statements of Cash Flows
<CAPTION>
Year Ended December 31,
1996 1995 1994
(in thousands)
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net Income $107,108 $ 110,616 $ 109,845
Adjustments for Noncash Items:
Depreciation 87,697 85,071 82,795
Deferred Federal Income Taxes (12,771) 2,914 (2,132)
Deferred Investment Tax Credits (3,909) (3,483) (3,929)
Deferred Fuel Costs (net) 4,519 (11,377) 2,247
Deferred Zimmer Plant Operating Expenses and
Carrying Charges 32,152 29,150 19,156
Changes in Certain Currrent Assets and Liabilities:
Accounts Receivable (net) 2,850 (11,916) (2,840)
Fuel, Materials and Supplies 5,558 5,148 5,046
Accrued Utility Revenues 8,563 (8,794) (2,706)
Accounts Payable 2,799 3,038 (1,556)
Other (net) 24,522 6,212 (11,382)
Net Cash Flows From Operating Activities 259,088 206,579 194,544
INVESTING ACTIVITIES:
Construction Expenditures (92,667) (98,356) (80,973)
Proceeds from Sale and Leaseback
Transactions and Other 2,956 2,923 2,606
Net Cash Flows Used For Investing Activities (89,711) (95,433) (78,367)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company - 15,000 -
Issuance of Cumulative Preferred Stock - - 24,596
Issuance of Long-term Debt - 72,526 198,298
Retirement of Preferred Stock (7,500) (71,773) -
Retirement of Long-term Debt (99,053) (80,000) (225,834)
Change in Short-term Debt (net) 17,475 34,325 (25,225)
Dividends Paid on Common Stock (75,876) (71,900) (68,788)
Dividends Paid on Cumulative Preferred Stock (5,866) (12,812) (11,792)
Net Cash Flows Used For Financing Activities (170,820) (114,634) (108,745)
Net Increase (Decrease) in Cash and Cash Equivalents (1,443) (3,488) 7,432
Cash and Cash Equivalents January 1 10,577 14,065 6,633
Cash and Cash Equivalents December 31 $ 9,134 $ 10,577 $ 14,065
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
Consolidated Statements of Retained Earnings
<CAPTION>
Year Ended December 31,
1996 1995 1994
(in thousands)
<S> <C> <C> <C>
Retained Earnings January 1 $ 74,320 $ 46,976 $ 18,288
Net Income 107,108 110,616 109,845
181,428 157,592 128,133
Deductions:
Cash Dividends Declared:
Common Stock 75,876 71,900 68,788
Cumulative Preferred Stock:
7% Series 1,750 1,750 1,167
7-7/8% Series 3,938 3,937 3,938
9.50% Series - 5,522 7,125
Total Cash Dividends Declared 81,564 83,109 81,018
Capital Stock Expense 282 163 139
Total Deductions 81,846 83,272 81,157
Retained Earnings December 31 $ 99,582 $ 74,320 $ 46,976
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Organization
Columbus Southern Power Company (the Company or CSPCo) is a wholly-owned
subsidiary of American Electric Power Company, Inc. (AEP Co., Inc.), a public
utility holding company. The Company is engaged in the generation, purchase,
transmission and distribution of electric power serving 609,000 retail
customers in its service territory in central and southern Ohio. Wholesale
electric power is supplied to neighboring utility systems, power marketers
and the American Electric Power (AEP) System Power Pool (Power Pool). As a
member of the Power Pool and a signatory company to the AEP Transmission
Equalization Agreement, CSPCo's facilities are operated in conjunction with
the facilities of certain other AEP affiliated utilities as an integrated
utility system.
The Company's three wholly-owned subsidiaries, which are consolidated in
these financial statements, are: Conesville Coal Preparation Company (CCPC)
which provides coal washing services for one of the Company's generating
stations; Simco Inc. which is engaged in leasing a coal conveyor system to
CCPC; and Colomet, Inc. which is engaged in real estate activities for its
parent.
Regulation
As a subsidiary of AEP Co., Inc., CSPCo is subject to the regulation of
the Securities and Exchange Commission (SEC) under the Public Utility Holding
Company Act of 1935 (1935 Act). Retail rates are regulated by the Public
Utilities Commission of Ohio (PUCO). The Federal Energy Regulatory
Commission (FERC) regulates wholesale rates.
Principles of Consolidation
The consolidated financial statements include CSPCo and its wholly-owned
subsidiaries. Significant intercompany items are eliminated in consol-
idation.
Basis of Accounting
As a cost-based rate-regulated entity, CSPCo's financial statements
reflect the actions of regulators that result in the recognition of revenues
and expenses in different time periods than enterprises that are not rate
regulated. In accordance with Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation,"
regulatory assets (deferred expenses) and regulatory liabilities (deferred
income) are recorded to reflect the economic effects of regulation.
Use of Estimates
The preparation of these financial statements in conformity with
generally accepted accounting principles requires in certain instances the
use of management's estimates. Actual results could differ from those
estimates.
<PAGE>
Utility Plant
Electric utility plant is stated at original cost and is generally
subject to first mortgage liens. Additions, major replacements and
betterments are added to the plant accounts. Retirements from the plant ac-
counts and associated removal costs, net of salvage, are deducted from
accumulated depreciation.
The costs of labor, materials and overheads incurred to operate and
maintain utility plant are included in operating expenses.
Allowance for Funds Used During Construction (AFUDC)
AFUDC is a noncash nonoperating income item that is recovered with
regulator approval over the service life of utility plant through
depreciation and represents the estimated cost of borrowed and equity funds
used to finance construction projects. The amounts of AFUDC in 1996, 1995
and 1994 were not significant.
Depreciation
Depreciation of electric utility plant is provided on a straight-line
basis over the estimated useful lives of utility plant and is calculated
largely through the use of composite rates by functional class as follows:
Composite
Functional Class Depreciation
of Property Annual Rates
Production 3.2%
Transmission 2.3%
Distribution 3.7%
General 3.5%
Amounts to be used for removal of plant are recovered through
depreciation charges included in rates.
Cash and Cash Equivalents
Cash and cash equivalents include temporary cash investments with
original maturities of three months or less.
Sale of Receivables
Under an agreement that was terminated in January 1997, CSPCo sold $50
million of undivided interests in designated pools of accounts receivable and
accrued utility revenues with limited recourse. As collections reduced
previously sold pools, interests in new pools were sold. At December 31,
1996, 1995 and 1994, $50 million remained to be collected and remitted to the
buyer.
Operating Revenues
Revenues include the accrual of electricity consumed but unbilled at
month-end as well as billed revenues.
<PAGE>
Fuel Costs
Changes in retail jurisdictional fuel cost are deferred until reflected
in revenues in later months through a PUCO fuel cost recovery mechanism. As
a result the Company practices deferral accounting for changes in retail fuel
costs. The deferral will be amortized to fuel expense as it is recovered in
rates. Wholesale jurisdictional fuel cost changes are expensed and billed as
incurred.
Income Taxes
The Company follows the liability method of accounting for income taxes
as prescribed by SFAS 109, "Accounting for Income Taxes." Under the
liability method, deferred income taxes are provided for all temporary
differences between book cost and tax basis of assets and liabilities which
will result in a future tax consequence. Where the flow-through method of
accounting for temporary differences is reflected in rates, deferred income
taxes are recorded with related regulatory assets and liabilities in
accordance with SFAS 71.
Investment Tax Credits
The Company's policy was to account for investment tax credits under the
flow-through method except where regulatory commissions reflected investment
tax credits in the rate-making process on a deferral basis. Deferred
investment tax credits, which represent a regulatory liability, are being
amortized over the life of the related plant investment commensurate with
recovery in rates.
Debt and Preferred Stock
Gains and losses on reacquired debt are deferred and amortized over the
remaining term of the reacquired debt in accordance with rate-making
treatment. If the debt is refinanced the reacquisition costs are deferred
and amortized over the term of the replacement debt commensurate with their
recovery in rates.
In accordance with rate-making treatment debt discount or premium and
debt issuance expenses are amortized over the term of the related debt, with
the amortization included in interest charges.
Redemption premiums paid to reacquire preferred stock are included in
paid-in capital and amortized to retained earnings in accordance with rate-
making treatment.
Other Property and Investments
Other property and investments are stated at cost.
2. EFFECTS OF REGULATION AND THE ZIMMER PHASE-IN PLAN:
In accordance with SFAS 71 the consolidated financial statements include
assets (deferred expenses) and liabilities (deferred income) recorded in
accordance with regulatory actions in order to match expenses and revenues in
cost-based rates. Regulatory assets are expected to be recovered in future
periods through the rate-making process and regulatory liabilities are
expected to reduce future cost recoveries. Among other things application
of SFAS 71 requires that the Company's rates be cost-based regulated. The
Company has reviewed all the evidence currently available and concluded that
it continues to meet the requirements to apply SFAS 71. In the event a
portion of the Company's business no longer met these requirements regulatory
assets and liabilities would have to be written off for that portion of the
business and assets would have to be tested for possible impairment.
Regulatory assets and liabilities are comprised of the following:
December 31,
1996 1995
(in thousands)
Regulatory Assets:
Amounts Due From Customers For
Future Income Taxes $269,820 $279,984
Zimmer Plant Phase-in Plan
Deferrals 15,379 46,887
Deferred Zimmer Plant
Carrying Charges 43,003 43,003
Unamortized Loss On
Reacquired Debt 32,740 31,025
Other 24,747 37,106
Total Regulatory Assets $385,689 $438,005
Regulatory Liabilities:
Deferred Investment Tax Credits $57,101 $61,010
Other* 24,741 12,351
Total Regulatory Liabilities $81,842 $73,361
* Included in Deferred Credits on the Consolidated Balance Sheets.
The rate phase-in plan deferrals are applicable to the Zimmer Plant, a
1,300 mw coal-fired plant which commenced commercial operation in 1991.
CSPCo owns 25.4% of the plant with the remainder owned by two unaffiliated
companies. In May 1992 the PUCO issued an order providing for a phased in
rate increase of $123 million to be implemented in three steps over a two-year
period and disallowed $165 million of Zimmer Plant investment. CSPCo
appealed the PUCO ordered Zimmer disallowance and phase-in plan to the Ohio
Supreme Court. In November 1993 the Supreme Court issued a decision on
CSPCo's appeal affirming the PUCO disallowance but finding that the PUCO did
not have statutory authority to order phased-in rates. The Court instructed
the PUCO to fix rates to provide gross annual revenues in accordance with the
law and to provide a mechanism to recover the amounts deferred as regulatory
assets under the phase-in order.
As a result of the Supreme Court decision, in January 1994 the PUCO
approved a 7.11% rate increase effective February 1, 1994. The increase is
comprised of a 3.72% base rate increase to complete the rate increase phase-in
and a temporary 3.39% surcharge, which will be in effect until the
deferrals are recovered, estimated to be in 1997. In 1996, 1995 and 1994
$31.5 million, $28.5 million and $18.5 million, respectively, of net phase-in
deferrals were collected through the surcharge. The deferral balance was
$15.4 million at December 31, 1996 and $46.9 million at December 31, 1995.
The recovery of amounts deferred under the phase-in plan and the increase in
rates to the full rate level did not affect net income since the deferred
costs are amortized commensurate with their recovery. From the in-service
date of March 1991 until rates went into effect in May 1992 deferred carrying
charges of $43 million were recorded on the Zimmer Plant investment.
Recovery of the deferred carrying charges will be sought in the next PUCO
base rate proceeding in accordance with the PUCO accounting order that
authorized the deferral.
<PAGE>
3. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Substantial construction commitments have been made. Such commitments
do not include any expenditures for new generating capacity. The aggregate
construction program expenditures for 1997-1999 are estimated to be $346
million.
Long-term fuel supply contracts contain clauses that provide for
periodic price adjustments. The PUCO has a fuel clause mechanism that
provides for deferral and subsequent recovery or refund of changes in the
cost of fuel with commission review and approval. The contracts are for
various terms, the longest of which extends to 2007, and contain various
clauses that would release the Company from its obligation under certain
force majeure conditions.
Litigation
The Company is involved in a number of legal proceedings and claims.
While management is unable to predict the outcome of litigation, it is not
expected that the resolution of these matters will have a material adverse
effect on the results of operations or financial condition.
4. RELATED PARTY TRANSACTIONS:
Benefits and costs of the AEP System's generating plants are shared by
members of the Power Pool. The Company is a member of the Power Pool. Under
the terms of the System Interconnection Agreement, capacity charges and
credits are designed to allocate the cost of the System's capacity among the
Power Pool members based on their relative peak demands and generating re-
serves. Power Pool members are also compensated for the out-of-pocket costs
of energy delivered to the Power Pool and charged for energy received from
the Power Pool.
Operating revenues include $15.4 million in 1996, $14.8 million in 1995
and $15.8 million in 1994 for energy supplied to the Power Pool.
Since the Company's internal peak demand exceeds its generating capacity
charges for Power Pool capacity reservation and energy received were included
in purchased power expense as follows:
Year Ended December 31,
1996 1995 1994
(in thousands)
Capacity Charges $ 83,723 $ 83,318 $ 74,936
Energy Charges 76,758 74,100 46,164
Total $160,481 $157,418 $121,100
Power Pool members share in wholesale sales to unaffiliated entities
made by the Power Pool. The Company's share of these wholesale Power Pool
sales included in operating revenues were $63.6 million in 1996, $45.8
million in 1995 and $48.7 million in 1994.
In addition, the Power Pool purchases power from unaffiliated companies
for immediate resale to other unaffiliated utilities. The Company's share of
these purchases was included in purchased power expense and totaled $7.1
million in 1996, $10 million in 1995 and $13.4 million in 1994. Revenues
from these transactions including a transmission fee are included in the
above Power Pool wholesale operating revenues.
AEP System companies participate in a transmission equalization agree-
ment. This agreement combines certain AEP System companies' investments in
transmission facilities and shares the costs of ownership in proportion to
the System companies' respective peak demands. Pursuant to the terms of the
agreement, other operation expense includes equalization charges of $30.6
million, $31.1 million and $30.1 million in 1996, 1995 and 1994, respective-
ly.
American Electric Power Service Corporation (AEPSC) provides certain
managerial and professional services to AEP System companies. The costs of
the services are billed by AEPSC on a direct-charge basis to the extent
practicable and on reasonable bases of proration for indirect costs. The
charges for services are made at cost and include no compensation for the use
of equity capital, which is furnished to AEPSC by AEP Co., Inc. Billings
from AEPSC are capitalized or expensed depending on the nature of the
services rendered. AEPSC and its billings are subject to the regulation of
the SEC under the 1935 Act.
5. BENEFIT PLANS:
The Company and its subsidiaries participate in the AEP System pension
plan, a trusteed, noncontributory defined benefit plan covering all employees
meeting eligibility requirements. Benefits are based on service years and
compensation levels. Pension costs are allocated by first charging each
System company with its service cost and then allocating the remaining
pension cost in proportion to its share of the projected benefit obligation.
The funding policy is to make annual trust fund contributions equal to the
net periodic pension cost up to the maximum amount deductible for federal
income taxes, but not less than the minimum required contribution in
accordance with the Employee Retirement Income Security Act of 1974. Net
pension costs for the years ended December 31, 1996, 1995 and 1994 were $1.5
million, $0.8 million and $2.2 million, respectively.
An employee savings plan is offered which allows participants to
contribute up to 17% of their salaries into various investment alternatives,
including AEP Co., Inc. common stock. An employer matching contribution,
equaling one-half of the employees' contribution to the plan up to a maximum
of 3% of the employees' base salary, is invested in AEP Co., Inc. common
stock. The Company's annual contributions totaled $1.9 million in 1996 and
$2.1 million in both 1995 and 1994.
Postretirement benefits other than pensions (OPEB) are provided for
retired employees under an AEP System plan. Substantially all employees are
eligible for postretirement health care and life insurance if they retire
from active service after reaching age 55 and have at least 10 service years.
OPEB costs are determined by the application of AEP System actuarial
assumptions to each operating company's employee complement. The annual
accrued costs, which includes the recognition of one-twentieth of the prior
service transition obligation, were $13.6 million in 1996, $11.3 million in
1995 and $10.4 million in 1994. The funding policy for AEP's OPEB plan is to
make contributions to an external Voluntary Employees Beneficiary Association
trust fund equal to the incremental OPEB costs (i.e., the amount that the
total postretirement benefits cost under SFAS 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions," exceeds the pay-as-you-go
amount). Contributions were $8.2 million in 1996 and $14.3 million in 1995.
<PAGE>
6. COMMON OWNERSHIP OF GENERATING AND TRANSMISSION FACILITIES:
The Company jointly owns, as tenants in common, four generating units
and transmission facilities with two unaffiliated companies. Each of the
participating companies is obligated to pay its share of the costs of any
such jointly owned facilities in the same proportion as its ownership
interest. The Company's proportionate share of the operating costs
associated with such facilities is included in the Consolidated Statements of
Income and the amounts reflected in the accompanying Consolidated Balance
Sheets under utility plant include such costs as follows:
<TABLE>
<CAPTION>
Company's Share
December 31,
1996 1995
Percent Utility Construction Utility Construction
of Plant Work Plant Work
Ownership in Service in Progress in Service in Progress
(in thousands)
<S> <C> <C> <C> <C> <C>
Production:
W.C. Beckjord Generating Station (Unit No. 6) 12.5 $ 13,628 $ 46 $ 13,876 $ 13
Conesville Generating Station (Unit No. 4) 43.5 79,484 268 78,193 555
J.M. Stuart Generating Station 26.0 179,633 2,973 181,362 2,127
Wm. H. Zimmer Generating Station 25.4 698,765 1,349 696,661 2,403
$971,510 $4,636 $970,092 $5,098
Transmission (a) $59,105 $ 324 $ 59,208 $ -0-
(a) Varying percentages of ownership.
</TABLE>
At December 31, 1996 and 1995, the accumulated depreciation with respect
to the Company's share of jointly owned facilities amounted to $271.2 million
and $247.6 million, respectively.
<PAGE>
7. CUMULATIVE PREFERRED STOCK:
At December 31, 1996, authorized shares of cumulative preferred stock were
as follows:
Par Value Shares Authorized
$100 2,500,000
25 7,000,000
The cumulative preferred stock outstanding shown below is subject to
mandatory redemption and has an involuntary liquidation preference of par
value.
<TABLE>
<CAPTION>
Call Price Shares Amount
December 31, Par Outstanding December 31,
Series (a) 1996 Value December 31, 1996 1996 1995
(in thousands)
<S> <C> <C> <C> <C> <C>
7% (b) (b) $100 250,000 $25,000 $25,000
7-7/8% (c) (c) 100 500,000 50,000 50,000
9.50% (d) (d) 100 - - 7,500
$75,000 $82,500
(a) The sinking fund provisions of the 7% and 7-7/8% series aggregate $2,500,000, $2,500,000 and $7,500,000 and
$7,500,000 in 1998, 1999, 2000 and 2001, respectively.
(b) Shares issued June 1994. Commencing in 2000, a sinking fund will require the redemption of 50,000 shares at $100
a share on or before August 1 of each year. The Company has the right, on each sinking fund date, to redeem an
additional 50,000 shares. Redemption of this series is prohibited prior to August 1, 2000.
(c) Called for redemption in March 1997.
(d) Redeemed 675,000 shares of 9.5% series in November 1995 and the remaining 75,000 shares in February 1996.
</TABLE>
<PAGE>
8. FEDERAL INCOME TAXES:
<TABLE>
The details of federal income taxes as reported are as follows:
<CAPTION>
Year Ended December 31,
1996 1995 1994
(in thousands)
<S> <C> <C> <C>
Charged (Credited) to Operating Expenses (net):
Current $ 78,262 $60,091 $56,424
Deferred (11,842) 2,028 (5,916)
Deferred Investment Tax Credits (3,625) (3,333) (3,702)
Total 62,795 58,786 46,806
Charged (Credited) to Nonoperating Income (net):
Current (1,280) (874) (525)
Deferred (929) 886 3,784
Deferred Investment Tax Credits (284) (150) (227)
Total (2,493) (138) 3,032
Total Federal Income Taxes as Reported $ 60,302 $58,648 $49,838
<CAPTION>
The following is a reconciliation of the difference between the amount of
federal income taxes computed by multiplying book income before federal
income taxes by the statutory tax rate, and the amount of federal income
taxes reported.
Year Ended December 31,
1996 1995 1994
(in thousands)
<S> <C> <C> <C>
Net Income $107,108 $110,616 $109,845
Federal Income Taxes 60,302 58,648 49,838
Pre-tax Book Income $167,410 $169,264 $159,683
Federal Income Taxes on Pre-tax Book Income at
Statutory Rate (35%) $58,594 $59,242 $55,889
Increase (Decrease) in Federal Income Taxes
Resulting From the Following Items:
Depreciation 7,861 7,959 7,335
Corporate Owned Life Insurance (1,697) (2,882) (2,787)
Federal Income Tax Accrual Adjustments - - (3,300)
Investment Tax Credits (net) (3,909) (3,848) (3,929)
Other (547) (1,823) (3,370)
Total Federal Income Taxes as Reported $60,302 $58,648 $49,838
Effective Federal Income Tax Rate 36.0% 34.6% 31.2%
</TABLE>
<PAGE>
The following tables show the elements of the net deferred tax liability
and the significant temporary differences giving rise to such deferrals:
December 31,
1996 1995
(in thousands)
Deferred Tax Assets $ 77,978 $ 69,503
Deferred Tax Liabilities (519,455) (533,916)
Net Deferred Tax Liabilities $(441,477) $(464,413)
Property Related Temporary
Differences $(341,669) $(337,349)
Amounts Due From Customers For
Future Federal Income Taxes (94,413) (97,973)
All Other (net) (5,395) (29,091)
Total Net Deferred
Tax Liabilities $(441,477) $(464,413)
The Company and its subsidiaries join in the filing of a consolidated
federal income tax return with their affiliates in the AEP System. The
allocation of the AEP System's current consolidated federal income tax to the
System companies is in accordance with SEC rules under the 1935 Act. These
rules permit the allocation of the benefit of current tax losses to the
System companies giving rise to them in determining their current tax
expense. The tax loss of the System parent company, AEP Co., Inc., is
allocated to its subsidiaries with taxable income. With the exception of the
loss of the parent company, the method of allocation approximates a separate
return result for each company in the consolidated group.
The AEP System has settled with the Internal Revenue Service (IRS) all
issues from the audits of the consolidated federal income tax returns for the
years prior to 1991. Returns for the years 1991 through 1993 are presently
being audited by the IRS. During the audit the IRS agents requested a ruling
from their National Office that certain interest deductions relating to
corporate owned life insurance (COLI) claimed by the Company for 1991 through
1993 should not be allowed. The COLI program was established in 1990 as part
of the Company's strategy to fund and reduce the cost of medical benefits for
retired employees. AEP filed a brief with the IRS National Office refuting
the agents' position. Although no adjustments have been proposed, a
disallowance of the COLI interest deductions through December 31, 1996 would
reduce earnings by approximately $34 million (including interest).
Management believes it will ultimately prevail on this issue and will
vigorously contest any adjustments that may be assessed. Accordingly, no
provision for this amount has been recorded. In the opinion of management,
the final settlement of open years will not have a material effect on results
of operations.
9. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1996 1995 1994
(in thousands)
Cash was paid for:
Interest (net of
capitalized amounts) $77,021 $78,046 $83,251
Income Taxes 76,298 57,896 59,218
Noncash Acquisitions under
Capital Leases were 14,247 9,094 14,899
<PAGE>
10. LEASES:
Leases of property, plant and equipment are for periods of up to 31 years
and require payments of related property taxes, maintenance and operating
costs. The majority of the leases have purchase or renewal options and will
be renewed or replaced by other leases.
Lease rentals for both operating and capital leases are generally charged to
operating expenses in accordance with rate-making treatment. The components of
rental costs are as follows:
Year Ended December 31,
1996 1995 1994
(in thousands)
Operating Leases $ 7,544 $ 7,684 $ 7,850
Amortization of Capital
Leases 5,169 4,971 4,050
Interest on Capital Leases 2,094 1,547 1,092
Total Rental Costs $14,807 $14,202 $12,992
Properties under capital leases and related obligations recorded on the
Consolidated Balance Sheets are as follows:
December 31,
1996 1995
(in thousands)
Electric Utility Plant:
Production $ 1,952 $1,952
General 48,030 38,632
Total Electric Utility Plant 49,982 40,584
Other Property 2,189 1,838
Total Properties 52,171 42,422
Accumulated Amortization 16,037 14,606
Net Properties under
Capital Leases $36,134 $27,816
Obligations under Capital Leases:*
Noncurrent Liability $30,520 $22,981
Liability Due Within One Year 5,614 4,835
Total Capital Lease
Obligations $36,134 $27,816
* Represents the present value of future minumum lease payments.
Capital lease obligations are included in other noncurrent liabilities and
other current liabilities on the Consolidated Balance Sheets. Properties under
operating leases and related obligations are not included in the Consolidated
Balance Sheets.
<PAGE>
Future minimum lease payments consisted of the following at December 31,
1996:
Non-
cancelable
Capital Operating
Leases Leases
(in thousands)
1997 $ 7,715 $ 5,609
1998 6,779 5,382
1999 6,133 5,046
2000 5,490 4,837
2001 4,284 4,513
Later Years 13,482 7,012
Total Future Minimum Lease
Payments 43,883 $32,399
Less Estimated Interest Element 7,749
Estimated Present Value of
Future Minimum Lease Payments $36,134
11. COMMON SHAREHOLDER'S EQUITY:
The Company received from AEP Co., Inc. a cash capital contribution of $15
million in 1995 which was credited to paid-in capital. In 1996, 1995 and 1994
net charges to paid-in capital of $282,000, $6,215,000 and $404,000,
respectively, represented expenses of issuing and retiring cumulative preferred
stock. There were no other material transactions affecting the common stock and
paid-in capital accounts in 1996, 1995 and 1994.
12. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1996 1995
(in thousands)
First Mortgage Bonds $733,522 $827,167
Debentures 72,810 72,734
Installment Purchase Contracts 90,949 90,895
897,281 990,796
Less Portion Due Within
One Year 14,640 -
Total $882,641 $990,796
<PAGE>
First mortgage bonds outstanding were as follows:
December 31,
1996 1995
(in thousands)
% Rate Due
6-1/4 1997 - October 1 $ 14,640 $ 14,640
9.15 1998 - February 2 57,000 57,000
7 1998 - June 1 24,750 24,750
9.31 2001 - August 1 - 30,000
7.95 2002 - July 1 40,000 40,000
7.25 2002 - October 1 75,000 75,000
7.15 2002 - November 1 20,000 20,000
6.80 2003 - May 1 50,000 50,000
6.60 2003 - August 1 40,000 40,000
6.10 2003 - November 1 20,000 20,000
6.55 2004 - March 1 50,000 50,000
6.75 2004 - May 1 50,000 50,000
9.625 2021 - June 1 - 50,000
8.70 2022 - July 1 35,000 35,000
8.40 2022 - August 1 15,000 15,000
8.55 2022 - August 1 15,000 15,000
8.40 2022 - August 15 25,500 40,000
8.40 2022 - October 15 15,000 15,000
7.90 2023 - May 1 50,000 50,000
7.75 2023 - August 1 40,000 40,000
7.45 2024 - March 1 50,000 50,000
7.60 2024 - May 1 50,000 50,000
Unamortized Discount (net) (3,368) (4,223)
733,522 827,167
Less Portion Due Within
One year 14,640 -
Total $718,882 $827,767
Certain indentures relating to the first mortgage bonds contain improvement,
maintenance and replacement provisions requiring the deposit of cash or bonds
with the trustee, or in lieu thereof, certification of unfunded property
additions.
Debentures represent $75 million of 8-3/8% Series A Junior Subordinated
Deferrable Interest Debentures due in September 2025.
Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by the Ohio Air Quality Development
Authority as follows:
December 31,
1996 1995
(in thousands)
% Rate Due
6-3/8 2020 - December 1 $48,550 $48,550
6-1/4 2020 - December 1 43,695 43,695
Unamortized Discount (1,296) (1,350)
Total $90,949 $90,895
Under the terms of the installment purchase contracts, the Company is
required to pay amounts sufficient to enable the payment of interest on and the
principal of related pollution control revenue bonds issued to finance the
Company's share of construction of pollution control facilities at the Zimmer
Plant.
<PAGE>
At December 31, 1996 future annual long-term debt payments, excluding
premium or discount, are as follows:
Principal Amount
(in thousands)
1997 $ 14,640
1998 81,750
1999 -
2000 -
2001 -
Later Years 807,745
Total $904,135
Short-term debt borrowings are limited by provisions of the 1935 Act to $175
million. Lines of credit are shared with AEP System companies and at
December 31, 1996 and 1995 were available in the amounts of $409 million and
$372 million, respectively. Commitment fees of approximately 1/8 of 1% of the
unused short-term lines of credit are required to maintain the lines of credit.
Outstanding short-term debt consisted of:
Year-end
Balance Weighted
Outstanding Average
(in thousands) Interest Rate
December 31, 1996:
Notes Payable $20,000 6.4%
Commercial Paper 31,800 7.4
Total $51,800 7.0
December 31, 1995:
Notes Payable $13,125 6.0%
Commercial Paper 21,200 6.1
Total $34,325 6.1
<PAGE>
13. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The carrying amounts of cash and cash equivalents, accounts receivable,
short-term debt and accounts payable approximate fair value because of the
short-term maturity of these instruments. At December 31, 1996 and 1995 fair
values for preferred stock subject to mandatory redemption were $79.5 million
and $88.8 million, and for long-term debt were $910 million and $1,032 million,
respectively. The carrying amounts for preferred stock subject to mandatory
redemption were $75 million and $82.5 million, and for long-term debt were $897
million and $991 million at December 31, 1996 and 1995, respectively. Fair
values are based on quoted market prices for the same or similar issues and the
current dividend or interest rates offered for instruments of the same remaining
maturities.
14. UNAUDITED QUARTERLY FINANCIAL
INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
1996
March 31 $271,040 $48,426 $25,126
June 30 269,023 47,173 27,496
September 30 303,270 52,405 34,759
December 31 262,350 37,543 19,727
1995
March 31 257,005 44,437 25,525
June 30 246,165 39,179 20,550
September 30 310,141 66,542 47,132
December 31 258,551 35,650 17,409
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration
Statement No. 33-50447 of Columbus Southern Power Company on Form
S-3 of our reports dated February 25, 1997, appearing in and
incorporated by reference in this Annual Report on Form 10-K of
Columbus Southern Power Company for the year ended December 31,
1996.
Deloitte & Touche LLP
Columbus, Ohio
March 25, 1997
Exhibit 24
POWER OF ATTORNEY
COLUMBUS SOUTHERN POWER COMPANY
Annual Report on Form lO-K for the Fiscal Year Ended
December 31, 1996
The undersigned directors of COLUMBUS SOUTHERN POWER COMPANY,
an Ohio corporation (the "Company"), do hereby constitute and
appoint E. LINN DRAPER, JR., G. P. MALONEY and P. J. DeMARIA, and
each of them, their attorneys-in-fact and agents, to execute for
them, and in their names, and in any and all of their capacities,
the Annual Report of the Company on Form lO-K, pursuant to Section
13 of the Securities Exchange Act of 1934, for the fiscal year
ended December 31, 1996, and any and all amendments thereto, and to
file the same, with all exhibits thereto and other documents in
connection therewith, with the Securities and Exchange Commission,
granting unto said attorneys-in-fact and agents, and each of them,
full power and authority to do and perform every act and thing
required or necessary to be done, as fully to all intents and
purposes as the undersigned might or could do in person, hereby
ratifying and confirming all that said attorneys-in-fact and
agents, or any of them, may lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned have signed these presents
this 26th day of February, 1997.
/s/ P. J. DeMaria /s/ G. P. Maloney
- ------------------------------ -------------------------------
P. J. DeMaria G. P. Maloney
/s/ E. Linn Draper, Jr. /s/ James J. Markowsky
- ------------------------------ --------------------------------
E. Linn Draper, Jr. James J. Markowsky
/s/ Henry W. Fayne /s/ J. H. Vipperman
- ------------------------------ --------------------------------
Henry W. Fayne J. H. Vipperman
/s/ Wm. J. Lhota
- ------------------------------
Wm. J. Lhota
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000022198
<NAME> COLUMBUS SOUTHERN POWER COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,882,984
<OTHER-PROPERTY-AND-INVEST> 24,069
<TOTAL-CURRENT-ASSETS> 178,570
<TOTAL-DEFERRED-CHARGES> 70,274
<OTHER-ASSETS> 385,689
<TOTAL-ASSETS> 2,541,586
<COMMON> 41,026
<CAPITAL-SURPLUS-PAID-IN> 574,709
<RETAINED-EARNINGS> 99,582
<TOTAL-COMMON-STOCKHOLDERS-EQ> 715,317
25,000
0
<LONG-TERM-DEBT-NET> 882,641
<SHORT-TERM-NOTES> 20,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 31,800
<LONG-TERM-DEBT-CURRENT-PORT> 14,640
50,000
<CAPITAL-LEASE-OBLIGATIONS> 30,520
<LEASES-CURRENT> 5,614
<OTHER-ITEMS-CAPITAL-AND-LIAB> 766,054
<TOT-CAPITALIZATION-AND-LIAB> 2,541,586
<GROSS-OPERATING-REVENUE> 1,105,683
<INCOME-TAX-EXPENSE> 62,806
<OTHER-OPERATING-EXPENSES> 857,330
<TOTAL-OPERATING-EXPENSES> 920,136
<OPERATING-INCOME-LOSS> 185,547
<OTHER-INCOME-NET> (970)
<INCOME-BEFORE-INTEREST-EXPEN> 184,577
<TOTAL-INTEREST-EXPENSE> 77,469
<NET-INCOME> 107,108
6,029
<EARNINGS-AVAILABLE-FOR-COMM> 101,079
<COMMON-STOCK-DIVIDENDS> 75,876
<TOTAL-INTEREST-ON-BONDS> 59,711
<CASH-FLOW-OPERATIONS> 259,088
<EPS-PRIMARY> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1> All common stock owned by parent company; no EPS required.
</FN>
</TABLE>
