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.
Exhibit 3(d)
As of
2/26/97
AMERICAN ELECTRIC POWER COMPANY, INC.
(Formerly American Gas and Electric Company)
BY-LAWS
Section 1. The annual meeting of the stockholders of the
Company shall be held on the fourth Wednesday of April in each
year, at an hour and place within or without the State of New
York designated by the Board of Directors, or if not so fixed, at
twelve o'clock noon at the office of the Company in the City of
New York. (As amended October 30, 1963.)
Section 2. Special meetings of the stockholders of the
Company may be held upon call of the Board of Directors or of the
Executive Committee, or of stockholders holding one-fourth of the
capital stock, at such time and at such place within or without
the State of New York as may be stated in the call and notice.
(As amended July 26, 1989.)
Section 3. Notice of time and place of every meeting of
stockholders shall be mailed at least ten days previous thereto
to each stockholder of record who shall have furnished a written
address to the Secretary of the Company for the purpose. Such
further notice shall be given as may be required by law. But
meetings may be held without notice if all stockholders are
present, or if notice is waived by those not present.
Section 4. Except as otherwise provided by law, the holders
of a majority of the outstanding capital stock of the Company
entitled to vote at any meeting of the stockholders of the
Company must be present in person or by proxy at such meeting of
the stockholders of the Company to constitute a quorum. If,
however, such majority shall not be represented at any meeting of
the stockholders of the Company regularly called, the holders of
a majority of the shares present or represented and entitled to
vote thereat shall have power to adjourn such meeting to another
time without notice other than announcement of adjournment at the
meeting, and there may be successive adjournments for like cause
and in like manner until the requisite amount of shares entitled
to vote at such meeting shall be represented. (As amended May
20, 1952.)
Section 5. As soon as may be after their election in each
year, the Board of Directors or the Executive Committee shall
appoint three inspectors of stockholders' votes and elections to
serve until the final adjournment of the next annual
stockholders' meeting. If they fail to make such appointment, or
if their appointees, or any of them, fail to appear at any
meeting of stockholders, the Chairman of the meeting may appoint
inspectors, or an inspector, to act at that meeting.
Section 6. Meetings of the stockholders shall be presided
over by the Chairman of the Board, or if he is not present, by
the President, or, if neither the Chairman of the Board nor the
President is present, by a Vice President, and in his absence, by
a Chairman to be elected at the meeting. The Secretary of the
Company shall act as Secretary of such meetings, if present. (As
amended January 23, 1979.)
Section 7. The Board of Directors shall consist of such
number of directors, within the limits prescribed in the
Certificate of Consolidation forming the Company, as amended, as
shall be determined from time to time as herein provided.
Directors shall be elected at each annual meeting of stockholders
and each director so elected shall hold office until the next
annual meeting of stockholders and until his successor is elected
and qualified. The number of directors to be elected at any
annual meeting of stockholders shall, except as otherwise
provided herein, be the number fixed in the latest resolution of
the Board of Directors adopted pursuant to the authority
contained in the next succeeding sentence and not subsequently
rescinded. The Board of Directors shall have power from time to
time and at any time when the stockholders are not assembled as
such in an annual or special meeting, by resolution adopted by a
majority of the directors then in office, to fix, within the
limits prescribed by the Certificate of Consolidation forming the
Company, as amended, the number of directors of the Company. If
the number of directors is increased, the additional directors
may, to the extent permitted by law, be elected by a majority of
the directors in office at the time of the increase, or, if not
so elected prior to the next annual meeting of stockholders, such
additional directors shall be elected at such annual meeting. If
the number of directors is decreased, then to the extent that the
decrease does not exceed the number of vacancies in the Board
then existing, such resolution may provide that it shall become
effective forthwith, and to the extent that the decrease exceeds
such number of vacancies such resolution shall provide that it
shall not become effective until the next election of directors
by the stockholders. If the Board of Directors shall fail to
adopt a resolution which fixes initially the number of directors,
the number of directors shall be twelve (12). If, after the
number of directors shall have been fixed by such resolution,
such resolution shall cease to be in effect other than by being
superseded by another such resolution, or it shall become
necessary that the number of directors be fixed by these By-Laws,
the number of directors shall be that number specified in the
latest of such resolutions, whether or not such resolution
continues in effect. (As amended May 1, 1959.)
Section 8. Vacancies in the Board of Directors may be
filled by the Board at any meeting.
Section 9. Meetings of the Board of Directors shall be held
at times fixed by resolution of the Board, or upon the call of
the Executive Committee, the Chairman of the Board, or the
President, and the Secretary or officer performing his duties
shall give reasonable notice of all meetings of directors;
provided, that a meeting may be held without notice immediately
after the annual election at the same place, and notice need not
be given of regular meetings held at times fixed by resolution of
the Board. Meetings may be held at any time without notice if
all the directors are present, or if those not present waive
notice either before or after the meeting. The number of
directors necessary to constitute a quorum for the transaction of
business shall be any number, which may be less than a majority
of the Board but not less than one-third of its number, duly
assembled at a meeting of such directors. Any one or more
members of the Board or of any committee thereof may participate
in a meeting of the Board or such committee by means of a
conference telephone or similar communications equipment allowing
all persons participating in the meeting to hear each other at
the same time. Participation by such means constitute presence
in person at a meeting. (As amended February 26, 1997.)
Section 10. The Board of Directors, by resolution adopted
by a majority of the entire Board, may designate among its
members an Executive Committee and one or more other committees,
each consisting of three (3) or more directors, and each of
which, to the extent provided in such resolution, shall have all
the authority of the Board. However, no such committee shall
have authority as to any of the following matters:
(a) The submission to shareholders of any action as to
which shareholders' authorization is required by law;
(b) The filling of vacancies in the Board of Directors
or in any committee;
(c) The fixing of compensation of any director for
serving on the Board or on any committee;
(d) The amendment or repeal of these By-Laws or the
adoption of new By-Laws; or
(e) The amendment or repeal of any resolution of the
Board which by its terms shall not be so amendable or
repealable.
The Board of Directors shall have the power at any time to
increase or decrease the number of members of any committee
(provided that no such decrease shall reduce the number of
members to less than three), to fill vacancies on it, to remove
any member of it, and to change its functions or terminate its
existence. Each committee may make such rules for the conduct of
its business as it may deem necessary. A majority of the members
of a committee shall constitute a quorum.
The Board of Directors shall also have the power to
designate or appoint at any time and from time to time one or
more individuals who have acquired as a former director or
officer of the Company substantial experience with the Company's
affairs as an Honorary Director, such individual or individuals
to meet with the Board of Directors, or certain of the directors,
at the invitation of the Chairman of the Board, from time to time
for the purpose of rendering advice to the Board of Directors or
such directors with respect to the Company's affairs for such
compensation as shall be payable to directors of the Company who
are not serving, at the time in question, as officers or
employees of the Company or of American Electric Power Service
Corporation; provided, however, that under no circumstances shall
such individual or individuals be authorized or empowered to
participate in the management or direction of the affairs of the
Company or to perform the functions of a director or officer of
the Company (as each such term is defined by the provisions of
Rule 70 promulgated by the Securities and Exchange Commission
under the provisions of Section 17(c) of the Public Utility
Holding Company Act of 1935, as such definition shall be in
effect at any time in question) or any similar function. (As
amended April 26, 1978.)
Section 11. The Board of Directors, as soon as may be after
the election each year, shall appoint one of their number
Chairman of the Board and one of their number President of the
Company, and shall appoint one or more Vice Presidents, a
Secretary and a Treasurer, and from time to time shall appoint
such other officers as they deem proper. The same person may be
appointed to more than one office. (As amended January 23,
1979.)
Section 12. The term of office of all officers shall be one
year, or until their respective successors are elected but any
officer may be removed from office at any time by the Board of
Directors, unless otherwise agreed by agreement in writing duly
authorized by the Board of Directors; and no agreement for the
employment of any officer for a longer period than one year shall
be so authorized.
Section 13. The officers of the Company shall have such
powers and duties as generally pertain to their offices,
respectively, as well as such powers and duties as from time to
time shall be conferred by the Board of Directors or the
Executive Committee.
Section 14. The stock of the Company shall be transferable
or assignable only on the books of the Company by the holders, in
person or by attorney, on the surrender of the certificate
therefor. The Board of Directors may appoint such Transfer
Agents and Registrars of stock as to them may seem expedient.
Section 15. To the fullest extent permitted by law, the
Company shall indemnify any person made, or threatened to be
made, a party to any action or proceeding (formal or informal),
whether civil, criminal, administrative or investigative and
whether by or in the right of the Company or otherwise, by reason
of the fact that such person, such person's testator or
intestate, is or was a director, officer or employee of the
Company, or of any subsidiary or affiliate of the Company, or
served any other corporation, partnership, joint venture, trust,
employee benefit plan or other enterprise in any capacity at the
request of the Company, against all loss and expense including,
without limiting the generality of the foregoing, judgments,
fines (including excise taxes), amounts paid in settlement and
attorneys' fees and disbursements actually and necessarily
incurred as a result of such action or proceeding, or any appeal
therefrom, and all legal fees and expenses incurred in
successfully asserting a claim for indemnification pursuant to
this Section 15; provided, however, that no indemnification may
be made to or on behalf of any director, officer or employee if a
judgment or other final adjudication adverse to the director,
officer or employee establishes that such person's acts were
committed in bad faith or were the result of active and
deliberate dishonesty and were material to the cause of action so
adjudicated, or that such person personally gained in fact a
financial profit or other advantage to which such person was not
legally entitled.
In any case in which a director, officer or employee of the
Company (or a representative of the estate of such director,
officer or employee) requests indemnification, upon such person's
request the Board of Directors shall meet within sixty days
thereof to determine whether such person is eligible for
indemnification in accordance with the standard set forth above.
Such a person claiming indemnification shall be entitled to
indemnification upon a determination that no judgment or other
final adjudication adverse to such person has established that
such person's acts were committed in bad faith or were the result
of active and deliberate dishonesty and were material to the
cause of action so adjudicated, or that such person personally
gained in fact a financial profit or other advantage to which
such person was not legally entitled. Such determination shall
be made:
(a) by the Board of Directors acting by a quorum
consisting of directors who are not parties to the action or
proceeding in respect of which indemnification is sought; or
(b) if such quorum is unobtainable or if directed by
such quorum, then by either (i) the Board of Directors upon
the opinion in writing of independent legal counsel that
indemnification is proper in the circumstances because such
person is eligible for indemnification in accordance with
the standard set forth above, or (ii) by the stockholders
upon a finding that such person is eligible for
indemnification in accordance with the standard set forth
above. Notwithstanding the foregoing, a determination of
eligibility for indemnification may be made in any manner
permitted by law.
To the fullest extent permitted by law, the Company shall
promptly advance to any person made, or threatened to be made, a
party to any action or proceeding (formal or informal), whether
civil, criminal, administrative or investigative and whether by
or in the right of the Company or otherwise, by reason of the
fact that such person, such person's testator or intestate, is or
was a director, officer or employee of the Company, or of any
subsidiary or affiliate of the Company, or served any other
corporation or any partnership, joint venture, trust, employee
benefit plan or other enterprise in any capacity at the request
of the Company, expenses incurred in defending such actions or
proceedings, upon request of such person and receipt of an
undertaking by or on behalf of such director, officer or employee
to repay amounts advanced to the extent that it is ultimately
determined that such person was not eligible for indemnification
in accordance with the standard set forth above.
The foregoing provisions of this Section 15 shall be deemed
to be a contract between the Company and each director, officer
or employee of the Company, or its subsidiaries or affiliates,
and any modification or repeal of this Section 15 or such
provisions of the New York Business Corporation Law shall not
diminish any rights or obligations existing prior to such
modification or repeal with respect to any action or proceeding
theretofore or thereafter brought; provided, however, that the
right of indemnification provided in this Section 15 shall not be
deemed exclusive of any other rights to which any director,
officer or employee of the Company may now be or hereafter become
entitled apart from this Section 15, under any applicable law
including the New York Business Corporation Law. Irrespective of
the provisions of this Section 15, the Board of Directors may, at
any time or from time to time, approve indemnification of
directors, officers, employees or agents to the full extent
permitted by the New York Business Corporation Law at the time in
effect, whether on account of past or future actions or
transactions. Notwithstanding the foregoing, the Company shall
enter into such additional contracts providing for
indemnification and advancement of expenses with directors,
officers or employees of the Company or its subsidiaries or
affiliates as the Board of Directors shall authorize, provided
that the terms of any such contract shall be consistent with the
provisions of the New York Business Corporation Law.
As used in this Section 15, the term "employee" shall
include, without limitation, any employee, including any
professionally licensed employee, of the Company. Such term
shall also include, without limitation, any employee, including
any professionally licensed employee, of a subsidiary or
affiliate of the Company who is acting on behalf of the Company.
The indemnification provided by this Section 15 shall be
limited with respect to directors, officers and controlling
persons to the extent provided in any undertaking entered into by
the Company or its subsidiaries or affiliates, as required by the
Securities and Exchange Commission pursuant to any rule or
regulation of the Securities and Exchange Commission now or
hereafter in effect.
If any action with respect to indemnification of directors
or officers is taken by way of amendment to these By-Laws,
resolution of the Board of Directors, or by agreement, then the
Company shall give such notice to the stockholders as is required
by law.
The Company may purchase and maintain insurance on behalf of
any person described in this Section 15 against any liability
which may be asserted against such person whether or not the
Company would have the power to indemnify such person against
such liability under the provisions of this Section 15 or
otherwise.
If any provision of this Section 15 shall be found to be
invalid or limited in application by reason of any law,
regulation or proceeding, it shall not affect any other provision
or the validity of the remaining provisions hereof.
The provisions of this Section 15 shall be applicable to
claims, actions, suits or proceedings made, commenced or pending
after the adoption hereof, whether arising from acts or omissions
to act occurring before or after the adoption hereof. (As
amended October 29, 1986.)
Section 16. These By-Laws may be amended or added to at any
meeting of the Board of Directors by affirmative vote of a
majority of all of the directors, if notice of the proposed
change has been delivered or mailed to the directors five days
before the meeting, or if all the directors are present, or if
all not present assent in writing to such change; provided,
however, that the provisions of Section 7 relating to the number
of directors constituting the Board of Directors may be amended
only by the affirmative vote, in person or by proxy, of the
holders of a majority of the outstanding shares of capital stock
entitled to vote at any meeting of the stockholders of the
Company; and provided further that the provisions of Section 7
other than those relating to the number of directors constituting
the Board of Directors, and the provisions of this Section 16 may
be amended or added to only by the affirmative vote, in person
or by proxy, of the holders of two-thirds of the outstanding
shares of capital stock entitled to vote at any meeting of the
stockholders of the Company; and provided further, in the event
of any such amendment or addition pursuant to vote by the
stockholders of the Company, that such amendment or addition, or
a summary thereof, shall have been set forth or referred to in
the notice of such meeting. (As renumbered and amended October
29, 1986.)
Exhibit 10(f)(1)
American Electric Power Company, Inc.
Deferred Compensation and Stock Plan
for Non-Employee Directors
Article 1
Purpose
The purposes of this American Electric Power Company, Inc. Deferred
Compensation and Stock Plan For Non-Employee Directors (the "Plan")
are to enable the Company to attract and retain qualified persons
to serve as Non-Employee Directors, to provide Non-Employee
Directors with an opportunity to defer some or all of their
Retainer as a means of saving for retirement or other purposes, to
solidify the common interests of its Non-Employee Directors and
shareholders by enhancing the equity interest of Non-Employee
Directors in the Company, and to encourage the highest level of
Non-Employee Director performance by providing such Non-Employee
Directors with a proprietary interest in the Company's performance
and progress by permitting Non-Employee Directors to receive all or
a portion of their Retainer in Common Stock and/or to defer all or
a portion of their Retainer in Stock Units.
Article 2
Effective Date
The Plan is subject to the approval of a majority of the holders of
the Company's Common Stock entitled to vote thereon at the Annual
Meeting of Shareholders to be held on April 23, 1997, or such other
date fixed for the next meeting of shareholders or any adjournment
or postponement thereof. Subject to the receipt of such approval,
the Plan shall be effective as of January 1, 1997.
Article 3
Definitions
Whenever used in the Plan, the following terms shall have the
respective meanings set forth below:
3.1 "Account" means, with respect to each Participant, the
Participant's separate individual account established and
maintained for the exclusive purpose of accounting for the
Participant's deferred Retainer which is accrued in terms of
Stock Units.
3.2 "Beneficiary" means, with respect to each Participant, the
recipient or recipients designated by the Participant who are,
upon the Participant's death, entitled in accordance with the
Plan's terms to receive the benefits to be paid with respect
to the Participant.
3.3 "Board" means the Board of Directors of the Company.
3.4 "Committee" means the Human Resources Committee of the Board.
3.5 "Common Stock" means the common stock, $6.50 par value, of the
Company.
3.6 "Company" means American Electric Power Company, Inc., a New
York corporation, and any successor thereto.
3.7 "Director" means an individual who is a member of the Board.
3.8 "Market Value" means the closing price of the Common Stock, as
published in The Wall Street Journal report of the New York
Stock Exchange - Composite Transactions on the date in
question or, if the Common Stock shall not have been traded on
such date or if the New York Stock Exchange is closed on such
date, then the first day prior thereto on which the Common
Stock was so traded.
3.9 "Non-Employee Director" means any person who serves on the
Board and who is not an officer of the Company or employee of
its Subsidiaries.
3.10 "Participant" means any Non-Employee Director who has made an
election to receive all or a portion of such person's
Retainer in shares of Common Stock and/or to defer payment of
all or a portion of such Retainer in Stock Units.
3.11 "Retainer" means the designated annual cash retainer,
currently paid quarterly, for Non-Employee Directors
established from time to time by the Board as annual
compensation for services rendered, exclusive of compensation
for service as a member of any committee designated by the
Board or in connection with any meeting of the Board or
special assignment, and exclusive of reimbursements for
expenses incurred in performance of service as a Director.
3.12 "Stock Unit" means a measure of value, expressed as a share of
Common Stock, credited to a Participant under this Plan. No
certificates shall be issued with respect to such Stock Units,
but the Company shall maintain a bookkeeping Account in the
name of the Participant to which the Stock Units shall relate.
3.13 "Subsidiary" means any corporation in which the Company owns
directly or indirectly through its Subsidiaries, at least 50
percent of the total combined voting power of all classes of
stock, or any other entity (including, but not limited to,
partnerships and joint ventures) in which the Company owns at
least 50 percent of the combined equity thereof.
3.14 "Termination" means retirement from the Board or termination
of service as a Director for any other reason.
Article 4
Election to Receive Common Stock for Retainer
and/or to Defer Retainer in Stock Units
4.1 Election
On or before December 31 of any year, for calendar years subsequent
to 1997, a Non-Employee Director may elect, by filing with the
Company an election, (a) to receive all or a specified portion of
the Director's Retainer in shares of Common Stock and/or (b) to
defer receipt of all or a specified portion of the Director's
Retainer in Stock Units until the Director's Termination or for a
period that results in payment commencing not later than five years
thereafter as elected by the Participant. The election to defer
payment beyond the Participant's Termination must be made at least
one year prior to such Termination.
Notwithstanding the foregoing, a Non-Employee Director may choose
to participate in the Plan beginning with the Retainer payable on
June 30, 1997, by filing an election to so participate on or before
March 31, 1997. A Non-Employee Director elected to fill a vacancy
on the Company's Board and who was not a Director on the preceding
December 31, or whose term of office did not begin until after that
date, may file an election to receive Common Stock and/or to defer,
for all or a specified portion of the Director's Retainer,
commencing not less than three months after the date of the
election.
4.2 Revocation of Election
An effective election pursuant to Section 4.1 may not be revoked or
modified (except as otherwise stated herein) with respect to the
Retainer payable for a calendar year or portion of a calendar year
for which such election is effective. An effective election may be
terminated or modified for any subsequent calendar year by the
filing of an election, on or before December 31 of the preceding
calendar year for which such modification or termination is to be
effective.
4.3 Common Stock Election
When a Participant elects pursuant to Section 4.1 to receive all or
a portion of the Participant's Retainer in shares of Common Stock,
the number of whole shares to be distributed to the Participant,
with any fractional shares to be paid in cash, as of the date the
Retainer would otherwise have been payable to the Participant,
shall be equal to the dollar amount of the Retainer which otherwise
would have been payable to the Participant divided by the Market
Value on such date.
4.4 Deferred Retainer Election
When a Participant elects pursuant to Section 4.1 to defer all or
a portion of the Participant's Retainer in Stock Units, the number
of whole and fractional Stock Units, computed to three decimal
places, to be credited to the Participant's Account, on the date
the deferred Retainer would otherwise have been payable to the
Participant, shall be equal to the dollar amount of the deferred
Retainer which otherwise would have been payable to the Participant
divided by the Market Value on such date.
Article 5
Dividends and Adjustments
5.1 Reinvestment of Dividends
On each dividend payment date with respect to the Common Stock, the
Account of a Participant, with Stock Units held pursuant to Article
4, shall be credited with an additional number of whole and
fractional Stock Units, computed to three decimal places, equal to
the product of the dividend per share then payable, multiplied by
the number of Stock Units then credited to such Account, divided by
the Market Value on the dividend payment date.
5.2 Adjustments
The number of Stock Units credited to a Participant's Account
pursuant to Article 4 shall be appropriately adjusted for any
change in the Common Stock by reason of any merger,
reclassification, consolidation, recapitalization, stock dividend,
stock split or any similar change affecting the Common Stock.
Article 6
Payment of Stock Units
6.1 Manner of Payment Upon Termination
In accordance with the Participant's election, filed with the
Company, all Stock Units held in a Participant's Account shall be
paid to the Participant either as (a) a lump sum distribution
within 10 days after the Participant's deferred distribution date,
or (b) up to 10 annual installments commencing within 10 days after
the Participant's deferred distribution date. This election shall
be made at the same time the Participant makes a deferral election
as provided in Section 4.1. Payment may be made in cash, shares of
Common Stock, or a combination of both as elected by the
Participant. The election to be paid in cash or Common Stock must
be filed with the Company at least 30 days prior to the payment
date and, in the event an election is not made, payment will be
made in cash.
6.2 Manner of Payment Upon Death
Notwithstanding the Participant's election, if a Participant dies
while Stock Units are held in the Participant's Account, such Stock
Units will be paid in a lump sum in cash within 90 days from the
date of the Participant's death to the Beneficiary or the
Participant's estate, as the case may be. Upon application by the
Beneficiary or the legal representative for the Participant's
estate, the lump sum payment may be deferred beyond 90 days for
good cause if the Committee consents to such deferral.
6.3 Determination
Any cash payments of Stock Units shall be calculated on the basis
of the average of the Market Value of the Common Stock for the last
20 trading days prior to the Participant's deferred distribution
date, respective installment payment dates or the date of the
Participant's death, as the case may be. Payment in Common Stock
shall be at the rate of one share of Common Stock for each Stock
Unit, with any fractional shares to be paid in cash.
Article 7
Beneficiary Designation
Each Participant shall be entitled to designate a Beneficiary or
Beneficiaries (which may be an entity other than a natural person)
who, following the Participant's death, will be entitled to receive
any payments to be made under Section 6.2. At any time, and from
time to time, any designation may be changed or cancelled by the
Participant without the consent of any Beneficiary. Any
designation, change, or cancellation must be by written notice
filed with the Company and shall not be effective until received by
the Company. Payment shall be made in accordance with the last
unrevoked written designation of Beneficiary that has been signed
by the Participant and delivered by the Participant to the Company
prior to the Participant's death. If the Participant designates
more than one Beneficiary, any payments under Section 6.2 to the
Beneficiaries shall be made in equal shares unless the Participant
has designated otherwise, in which case the payments shall be made
in the proportions designated by the Participant. If no
Beneficiary has been named by the Participant or if all
Beneficiaries predecease the Participant, payment shall be made to
the Participant's estate.
Article 8
Transferability Restrictions
The Plan shall not in any manner be liable for, or subject to, the
debts and liabilities of any Participant or Beneficiary. No payee
may assign any payment due such party under the Plan. No benefits
at any time payable under the Plan shall be subject in any manner
to anticipation, alienation, sale, transfer, assignment, pledge,
attachment, garnishment, levy, execution, or other legal or
equitable process, or encumbrance of any kind.
Article 9
Funding Policy
The Company's obligations under the Plan shall be totally unfunded
so that the Company or any Subsidiary is under merely a contractual
duty to make payments when due under the Plan. The promise to pay
shall not be represented by notes and shall not be secured in any
way.
Article 10
Change in Control
Notwithstanding any provision of this Plan to the contrary, if a
"Change in Control" (as defined below) of the Company occurs, Stock
Units held in a Participant's Account will be paid in a lump sum in
cash, shares of Common Stock, or a combination of both, to the
Participant, as elected by the Participant, not later than 15 days
after the date of the Change in Control. For this purpose, the
balance in the Account shall be determined by the higher of (a) the
average of the Market Value of the Common Stock for the last 20
trading days prior to such Change in Control or (b) if the Change
in Control of the Company occurs as a result of a tender or
exchange offer or consummation of a corporate transaction, then the
highest price paid per share of Common Stock pursuant thereto. Any
consideration other than cash forming a part or all of the
consideration for the Common Stock to be paid pursuant to the
applicable transaction shall be valued at the valuation price
thereon determined by the Board.
In addition, the Company shall reimburse a Participant for the
legal fees and expenses incurred if the Participant is required to
seek to obtain or enforce any right to distribution. In the event
that it is determined that such Participant is properly entitled to
a cash distribution hereunder, such Participant shall also be
entitled to interest thereon at the prime rate of interest as
published in The Wall Street Journal plus two percent from the date
such distribution should have been made to and including the date
it is made. Notwithstanding any provisions of this Plan to the
contrary, the provisions of this Article may not be amended by an
amendment effected within three years following a Change in
Control.
A "Change in Control" of the Company shall be deemed to have
occurred if (a) any "person" or "group" (as such terms are used in
Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as
amended ("Exchange Act")), other than a trustee or other fiduciary
holding securities under an employee benefit plan of the Company,
becomes the "beneficial owner" (as defined in Rule 13d-3 under the
Exchange Act), directly or indirectly, of more than 25 percent of
the then outstanding voting stock of the Company; (b) during any
period of two consecutive years, individuals who at the beginning
of such period constitute the Board, together with any new
Directors whose election or nomination for election was approved by
a vote of at least two-thirds of the Directors then still in office
who were either Directors at the beginning of the period or whose
election or nomination for election was previously so approved,
cease for any reason to constitute at least a majority of the
Board; or (c) the Company's shareholders approve a merger or
consolidation of the Company with any other corporation, other than
a merger or consolidation which would result in the voting
securities of the Company outstanding immediately prior thereto
continuing to represent (either by remaining outstanding or by
being converted into voting securities of the surviving entity) at
least 75 percent of the total voting power represented by the
voting securities of the Company or such surviving entity
outstanding immediately after such merger or consolidation; or (d)
the shareholders of the Company approve a plan of complete
liquidation of the Company, or an agreement for the sale or
disposition by the Company (in one transaction or a series of
transactions) of all or substantially all of the Company's assets.
Notwithstanding the foregoing, a Change in Control shall not be
deemed to occur as a result of any event described in (a) or (c)
above, if Directors who were a majority of the members of the Board
prior to such event and who continue to serve as Directors after
such event determine that the event shall not constitute a Change
in Control.
Article 11
Administration
The Plan shall be administered by the Committee. The Committee
shall have authority to interpret the Plan, and to prescribe, amend
and rescind rules and regulations relating to the administration of
the Plan, and all such interpretations, rules and regulations shall
be conclusive and binding on all Participants. The Committee may
employ agents, attorneys, accountants, or other persons (who also
may be employees of a Subsidiary) and allocate or delegate to them
powers, rights, and duties, all as the Committee may consider
necessary or advisable to properly carry out the administration of
the Plan.
Article 12
Amendment and Termination
The Company, by resolution duly adopted by the Board, shall have
the right, authority and power to alter, amend, modify, revoke, or
terminate the Plan; except as provided in Article 10; and provided
further, that no amendment or termination of the Plan shall
adversely affect the rights of any Participant with respect to any
Stock Units held in such Participant's Account, unless the
Participant shall consent thereto in writing.
Article 13
Miscellaneous
13.1 No Right to Continue as a Director
Nothing in this Plan shall be construed as conferring upon a
Participant any right to continue as a member of the Board.
13.2 No Interest as a Shareholder
Stock Units do not give a Participant any rights whatsoever with
respect to shares of Common Stock until such time and to such
extent that payment of Stock Units is made in shares of Common
Stock as requested by the Participant.
13.3 No Right to Corporate Assets
Nothing in this Plan shall be construed as giving the Participant,
the Participant's designated Beneficiaries or any other person any
equity or interest of any kind in the assets of the Company or any
Subsidiary or creating a trust of any kind or a fiduciary
relationship of any kind between the Company or any Subsidiary and
any person. As to any claim for payments due under the provisions
of the Plan, a Participant, Beneficiary and any other persons
having a claim for payments shall be unsecured creditors of the
Company or any Subsidiary.
13.4 Payment to Legal Representative for Participant
In the event the Committee shall find that a Participant is unable
to care for his or her affairs because of illness or accident, the
Committee may direct that any payment due the Participant be paid
to the Participant's duly appointed legal representative, and any
such payment so made shall be a complete discharge of the
liabilities of the Plan.
13.5 No Limit on Further Corporate Action
Nothing contained in the Plan shall be construed so as to prevent
the Company or any Subsidiary from taking any corporate action
which is deemed by the Company or any Subsidiary to be appropriate
or in its best interest.
13.6 Governing Law
The Plan shall be construed and administered according to the laws
of the State of New York to the extent that those laws are not
preempted by the laws of the United States of America.
13.7 Headings
The headings of articles, sections, subsections, paragraphs or
other parts of the Plan are for convenience of reference only and
do not define, limit, construe, or otherwise affect its contents.
Exhibit 10(f)(2)
AMERICAN ELECTRIC POWER COMPANY, INC.
STOCK UNIT ACCUMULATION PLAN
FOR NON-EMPLOYEE DIRECTORS
ARTICLE 1
PURPOSE
The purposes of this American Electric Power Company, Inc. Stock
Unit Accumulation Plan For Non-Employee Directors (the "Plan")
are to enable the Company to attract and retain qualified persons
to serve as Non-Employee Directors, to solidify the common
interests of its Non-Employee Directors and shareholders by
enhancing the equity interest of Non-Employee Directors in the
Company, and to encourage the highest level of Non-Employee
Director performance by providing such Non-Employee Directors
with a proprietary interest in the Company's performance and
progress by paying a portion of the compensation of the Non-
Employee Directors in deferred Stock Units.
ARTICLE 2
EFFECTIVE DATE
The Plan shall be effective as of January 1, 1997.
ARTICLE 3
DEFINITIONS
Whenever used in the Plan, the following terms shall have the
respective meanings set forth below:
3.1 "Account" means, with respect to each Participant, the
Participant's separate individual account established and
maintained for the exclusive purpose of accounting for the
Participant's award of Stock Units.
3.2 "Beneficiary" means, with respect to each Participant, the
recipient or recipients designated by the Participant who
are, upon the Participant's death, entitled in accordance
with the Plan's terms to receive the benefits to be paid
with respect to the Participant.
3.3 "Board" means the Board of Directors of the Company.
3.4 "Committee" means the Human Resources Committee of the
Board.
3.5 "Common Stock" means the common stock, $6.50 par value, of
the Company.
3.6 "Company" means American Electric Power Company, Inc., a New
York corporation, and any successor thereto.
3.7 "Director" means an individual who is a member of the Board.
3.8 "Market Value" means the closing price of the Common Stock,
as published in The Wall Street Journal report of the New
York Stock Exchange - Composite Transactions on the date in
question or, if the Common Stock shall not have been traded
on such date or if the New York Stock Exchange is closed on
such date, then the first day prior thereto on which the
Common Stock was so traded.
3.9 "Non-Employee Director" means any person who serves on the
Board and who is not an officer of the Company or employee
of its Subsidiaries.
3.10 "Participant" means any Non-Employee Director who has
received an award of Stock Units.
3.11 "Retainer" means the designated annual cash retainer,
currently paid quarterly, for Non-Employee Directors
established from time to time by the Board as annual
compensation for services rendered, exclusive of
compensation for service as a member of any committee
designated by the Board or in connection with any meeting of
the Board or special assignment, and exclusive of
reimbursements for expenses incurred in performance of
service as a Director.
3.12 "Stock Unit" means a measure of value, expressed as a share
of Common Stock, credited to a Participant under this Plan.
No certificates shall be issued with respect to such Stock
Units, but the Company shall maintain a bookkeeping Account
in the name of the Participant to which the Stock Units
shall relate.
3.13 "Subsidiary" means any corporation in which the Company owns
directly or indirectly through its Subsidiaries, at least 50
percent of the total combined voting power of all classes of
stock, or any other entity (including, but not limited to,
partnerships and joint ventures) in which the Company owns
at least 50 percent of the combined equity thereof.
3.14 "Termination" means retirement from the Board or termination
of service as a Director for any other reason.
ARTICLE 4
STOCK UNIT AWARDS
4.1 ANNUAL AWARDS
Each Non-Employee Director's Account shall be credited with 300
Stock Units as of the first day of the month in which the
Director becomes a member of the Board, and on the first day of
such month for each year thereafter, up to a maximum of 3,000
Stock Units for each Participant. In the event of a change in
the Retainer, the Committee may reconsider the amount of the
annual awards and may recommend to the Board changes in the
number of Stock Units to be awarded.
4.2 VESTING AND FORFEITURE
If a Participant's Termination occurs prior to the completion of
five years of service on the Board, the Participant shall forfeit
an amount of Stock Units equal to the product of all Stock Units
awarded pursuant to Section 4.1 and associated dividends credited
pursuant to Section 5.1, held in the Participant's Account,
multiplied by the difference of 60 minus the Participant's number
of months of service (with service for a partial month counted as
service for the entire month), divided by 60, computed to three
decimal places. If a Participant's Termination occurs after five
years of service, all such Stock Units shall be vested and
nonforfeitable.
4.3 RETIREMENT PROGRAM TERMINATION AWARDS
On and as of December 31, 1996, each Non-Employee Director
serving as such on such date who makes or has made an irrevocable
election by January 31, 1997 to waive participation in, and any
and all benefits under, the Company's Retirement Plan For
Directors, shall have credited to the Account of such
Participant, as of January 1, 1997, the number of vested and
nonforfeitable Stock Units as follows: R. M. Duncan 3,000; R. W.
Fri 600; A. G. Hansen 3,000; L. A. Hudson, Jr. 3,000; A. E.
Peyton 3,000; D. G. Smith 900; L. G. Stuntz 1,200; M. Tanenbaum
2,400; and A. H. Zwinger 3,000. Stock Units awarded pursuant to
this Section 4.3 will be included for purposes of determining the
application of the limitation on annual awards specified in
Section 4.1.
ARTICLE 5
DIVIDENDS AND ADJUSTMENTS
5.1 REINVESTMENT OF DIVIDENDS
On each dividend payment date with respect to the Common Stock,
the Account of a Participant, with Stock Units held pursuant to
Article 4, shall be credited with an additional number of whole
and fractional Stock Units, computed to three decimal places,
equal to the product of the dividend per share then payable,
multiplied by the number of Stock Units then credited to such
Account, divided by the Market Value on the dividend payment
date.
5.2 ADJUSTMENTS
The number of Stock Units credited to a Participant's Account
pursuant to Article 4 shall be appropriately adjusted for any
change in the Common Stock by reason of any merger,
reclassification, consolidation, recapitalization, stock
dividend, stock split or any similar change affecting the Common
Stock.
ARTICLE 6
PAYMENT OF STOCK UNITS
6.1 MANNER OF PAYMENT UPON TERMINATION
Stock Units held in a Participant's Account shall be paid to the
Participant in a lump sum in cash within 10 days after the
Participant's Termination unless the Participant has filed an
election with the Company to defer such payment as provided in
the following sentence. The Participant may elect (a) to defer
the lump sum payment for one or more years up to a maximum of
five years following Termination or (b) to receive payment of the
Stock Units in up to 10 annual installments commencing within 10
days after Termination or the deferred payment date elected by
the Participant pursuant to part (a) of this sentence. The
election to defer payment beyond the Participant's Termination
must be made at least one year prior to such Termination.
6.2 MANNER OF PAYMENT UPON DEATH
Notwithstanding the Participant's election, if a Participant dies
while Stock Units are held in the Participant's Account, such
Stock Units, whether vested or unvested and forfeitable, will be
paid in a lump sum in cash within 90 days from the date of the
Participant's death to the Beneficiary or the Participant's
estate, as the case may be. Upon application of the Beneficiary
or the legal representative of the Participant's estate, the lump
sum payment may be deferred beyond 90 days for good cause if the
Committee consents to such deferral.
6.3 DETERMINATION
Any cash payments of Stock Units shall be calculated on the basis
of the average of the Market Value of the Common Stock for the
last 20 trading days prior to the Participant's Termination,
deferred distribution date, respective installment payment dates
or the date of the Participant's death, as the case may be.
ARTICLE 7
BENEFICIARY DESIGNATION
Each Participant shall be entitled to designate a Beneficiary or
Beneficiaries (which may be an entity other than a natural
person) who, following the Participant's death, will be entitled
to receive any payments to be made under Section 6.2. At any
time, and from time to time, any designation may be changed or
cancelled by the Participant without the consent of any
Beneficiary. Any designation, change, or cancellation must be by
written notice filed with the Company and shall not be effective
until received by the Company. Payment shall be made in
accordance with the last unrevoked written designation of
Beneficiary that has been signed by the Participant and delivered
by the Participant to the Company prior to the Participant's
death. If the Participant designates more than one Beneficiary,
any payments under Section 6.2 to the Beneficiaries shall be made
in equal shares unless the Participant has designated otherwise,
in which case the payments shall be made in the proportions
designated by the Participant. If no Beneficiary has been named
by the Participant or if all Beneficiaries predecease the
Participant, payment shall be made to the Participant's estate.
ARTICLE 8
TRANSFERABILITY RESTRICTIONS
The Plan shall not in any manner be liable for, or subject to,
the debts and liabilities of any Participant or Beneficiary. No
payee may assign any payment due such party under the Plan. No
benefits at any time payable under the Plan shall be subject in
any manner to anticipation, alienation, sale, transfer,
assignment, pledge, attachment, garnishment, levy, execution, or
other legal or equitable process, or encumbrance of any kind.
ARTICLE 9
FUNDING POLICY
The Company's obligations under the Plan shall be totally
unfunded so that the Company or any Subsidiary is under merely a
contractual duty to make payments when due under the Plan. The
promise to pay shall not be represented by notes and shall not be
secured in any way.
ARTICLE 10
CHANGE IN CONTROL
Notwithstanding any provision of this Plan to the contrary, if a
"Change in Control" (as defined below) of the Company occurs,
Stock Units held in a Participant's Account, whether vested or
unvested and forfeitable, will be paid in a lump sum in cash to
the Participant not later than 15 days after the date of the
Change in Control. For this purpose, the balance in the Account
shall be determined by the higher of (a) the average of the
Market Value of the Common Stock for the last 20 trading days
prior to such Change in Control or (b) if the Change in Control
of the Company occurs as a result of a tender or exchange offer
or consummation of a corporate transaction, then the highest
price paid per share of Common Stock pursuant thereto. Any
consideration other than cash forming a part or all of the
consideration for the Common Stock to be paid pursuant to the
applicable transaction shall be valued at the valuation price
thereon determined by the Board.
In addition, the Company shall reimburse a Participant for the
legal fees and expenses incurred if the Participant is required
to seek to obtain or enforce any right to distribution. In the
event that it is determined that such Participant is properly
entitled to a cash distribution hereunder, such Participant shall
also be entitled to interest thereon at the prime rate of
interest as published in The Wall Street Journal plus two percent
from the date such distribution should have been made to and
including the date it is made. Notwithstanding any provisions of
this Plan to the contrary, the provisions of this Article may not
be amended by an amendment effected within three years following
a Change in Control.
A "Change in Control" of the Company shall be deemed to have
occurred if (a) any "person" or "group" (as such terms are used
in Sections 13(d) and 14(d) of the Securities Exchange Act of
1934, as amended ("Exchange Act")), other than a trustee or other
fiduciary holding securities under an employee benefit plan of
the Company, becomes the "beneficial owner" (as defined in Rule
13d-3 under the Exchange Act), directly or indirectly, of more
than 25 percent of the then outstanding voting stock of the
Company; (b) during any period of two consecutive years,
individuals who at the beginning of such period constitute the
Board, together with any new Directors whose election or
nomination for election was approved by a vote of at least two-
thirds of the Directors then still in office who were either
Directors at the beginning of the period or whose election or
nomination for election was previously so approved, cease for any
reason to constitute at least a majority of the Board; or (c) the
Company's shareholders approve a merger or consolidation of the
Company with any other corporation, other than a merger or
consolidation which would result in the voting securities of the
Company outstanding immediately prior thereto continuing to
represent (either by remaining outstanding or by being converted
into voting securities of the surviving entity) at least 75
percent of the total voting power represented by the voting
securities of the Company or such surviving entity outstanding
immediately after such merger or consolidation; or (d) the
shareholders of the Company approve a plan of complete
liquidation of the Company, or an agreement for the sale or
disposition by the Company (in one transaction or a series of
transactions) of all or substantially all of the Company's
assets.
Notwithstanding the foregoing, a Change in Control shall not be
deemed to occur as a result of any event described in (a) or (c)
above, if Directors who were a majority of the members of the
Board prior to such event and who continue to serve as Directors
after such event determine that the event shall not constitute a
Change in Control.
ARTICLE 11
ADMINISTRATION
The Plan shall be administered by the Committee. The Committee
shall have authority to interpret the Plan, and to prescribe,
amend and rescind rules and regulations relating to the
administration of the Plan, and all such interpretations, rules
and regulations shall be conclusive and binding on all
Participants. The Committee may employ agents, attorneys,
accountants, or other persons (who also may be employees of a
Subsidiary) and allocate or delegate to them powers, rights, and
duties, all as the Committee may consider necessary or advisable
to properly carry out the administration of the Plan.
ARTICLE 12
AMENDMENT AND TERMINATION
The Company, by resolution duly adopted by the Board, shall have
the right, authority and power to alter, amend, modify, revoke,
or terminate the Plan; except as provided in Article 10; and
provided further, that no amendment or termination of the Plan
shall adversely affect the rights of any Participant with respect
to any Stock Units held in such Participant's Account, unless the
Participant shall consent thereto in writing.
ARTICLE 13
MISCELLANEOUS
13.1 NO RIGHT TO CONTINUE AS A DIRECTOR
Nothing in this Plan shall be construed as conferring upon a
Participant any right to continue as a member of the Board.
13.2 NO INTEREST AS A SHAREHOLDER
Stock Units do not give a Participant any rights whatsoever with
respect to shares of Common Stock.
13.3 NO RIGHT TO CORPORATE ASSETS
Nothing in this Plan shall be construed as giving the
Participant, the Participant's designated Beneficiaries or any
other person any equity or interest of any kind in the assets of
the Company or any Subsidiary or creating a trust of any kind or
a fiduciary relationship of any kind between the Company or any
Subsidiary and any person. As to any claim for payments due
under the provisions of the Plan, a Participant, Beneficiary and
any other persons having a claim for payments shall be unsecured
creditors of the Company or any Subsidiary.
13.4 PAYMENT TO LEGAL REPRESENTATIVE FOR PARTICIPANT
In the event the Committee shall find that a Participant is
unable to care for his or her affairs because of illness or
accident, the Committee may direct that any payment due the
Participant be paid to the Participant's duly appointed legal
representative, and any such payment so made shall be a complete
discharge of the liabilities of the Plan.
13.5 NO LIMIT ON FURTHER CORPORATE ACTION
Nothing contained in the Plan shall be construed so as to prevent
the Company or any Subsidiary from taking any corporate action
which is deemed by the Company or any Subsidiary to be
appropriate or in its best interest.
13.6 GOVERNING LAW
The Plan shall be construed and administered according to the
laws of the State of New York to the extent that those laws are
not preempted by the laws of the United States of America.
13.7 HEADINGS
The headings of articles, sections, subsections, paragraphs or
other parts of the Plan are for convenience of reference only and
do not define, limit, construe, or otherwise affect its contents.
Exhibit 10(g)(2)
AMERICAN ELECTRIC POWER SYSTEM
SUPPLEMENTAL SAVINGS PLAN (NON-QUALIFIED)
Amended as of November 15, 1995
The American Electric Power Service Corporation (AEPS)
hereby establishes effective as of the 1st day of January, 1994,
the American Electric Power System Supplemental Savings Plan
(Plan). The purpose of this Plan is to provide to eligible
management employees a tax-deferred savings opportunity otherwise
not available under the American Electric Power System Employees
Savings Plan because of restrictions imposed by the Internal
Revenue Code.
ARTICLE 1
DEFINITIONS
1.1 "Applicable Federal Rate" means 120% of the applicable
Federal long-term rate, with monthly compounding (as prescribed
under Section 1274(d) of the Code), published for the December
immediately prior to the Plan Year.
1.2 "Book Reserve Account" means the separate account
established and maintained by AEPS to record Participant and AEPS
Supplemental Contributions for each Participant and to record
interest credited to the balances in each such account.
1.3 "Code" means the Internal Revenue Code of 1986, as
amended from time to time.
1.4 "Committee" means the Employee Benefit Trusts Committee
established pursuant to a resolution adopted by the AEPS Board of
Directors as in effect from time to time.
1.5 "Compensation" means the remuneration paid to a
Participant by AEPS and determined prior to any deferrals under
this Plan or the Savings Plan or under the American Electric
Power System Medical and Dental Plans, but excluding any bonuses,
pay for overtime, award amounts and other discretionary
remuneration paid to the Participant by AEPS and excluding AEPS'
cost for any public or private employee benefit plan (including
this Plan) under rules uniformly applicable to all employees
similarly situated.
1.6 "ERISA" means the Employee Retirement Income Security
Act of 1974, as amended from time to time.
1.7 "Participant" means an individual who is an employee of
AEPS, and is covered under the American Electric Power System
Excess Benefits Plan and who is confirmed by the Committee as
eligible to participate in the Plan and to receive book entry
credits associated with Supplemental Contributions.
1.8 "Plan Year" means (i) January 1, 1994 through
December 31, 1994 and (ii) each and every calendar year
thereafter.
1.9 "Salary Reduction Agreement" means an agreement between
AEPS and the Participant in which the Participant elects to
reduce his Compensation for the Plan Year and AEPS agrees to
treat the amount of the reduction as Participant contributions to
this Plan.
1.10 "Savings Plan" means the American Electric Power System
Employees Savings Plan, as in effect from time to time.
1.11 "Supplemental Contributions" mean Participant or AEPS
Contributions credited to a Participant's Book Reserve Account
pursuant to Sections 3.1 and 3.2 of this Plan.
ARTICLE 2
TERM
This Plan shall commence as of January 1, 1994, and shall be
effective until terminated by the AEPS Board of Directors as
herein provided.
ARTICLE 3
BOOK RESERVE FOR ACCRUED SUPPLEMENTAL CONTRIBUTIONS
3.1 PARTICIPANT SUPPLEMENTAL CONTRIBUTIONS. For any Plan
Year in which a Participant's contributions to the Savings Plan
will be restricted due to the contribution or account balance
limits imposed by the Code, the Participant may make Participant
Supplemental Contributions to the Plan. Participant Supplemental
Contributions shall not exceed the difference between (a) the
Participant's Compensation for the Plan Year times the maximum
Savings Plan Contribution percentage for highly-compensated
employees for the prior Plan Year and (b) the aggregate amount of
the Participant's pre-tax and after-tax contributions to the
Savings Plan for the Plan Year. The Participant's election to
make Participant Supplemental Contributions pursuant to a Salary
Reduction Agreement shall be made as provided in Section 4.1 of
this Plan.
3.2 EMPLOYER SUPPLEMENTAL CONTRIBUTIONS. For each
Participant electing to make (a) Participant Supplemental
Contributions or (b) Savings Plan contributions, AEPS shall, at
the time the Participant Supplemental Contributions are credited
to the Participant's Book Reserve Account or at the time
contributions are credited to the Participant's Savings Plan
account, credit the Participant's Book Reserve Account with
Employer Supplemental Contributions. Employer Supplemental
Contributions, in combination with contributions made by AEPS to
the Savings Plan, shall, in the aggregate, be equal to the lesser
of (a) fifty percent of the Participant's contributions to the
Savings Plan and this Plan, or (b) three percent of the
Participant's Compensation. If the aggregate contributions made
by AEPS exceed three percent of the Participant's Compensation,
Employer Supplemental Contributions credited to the Participant's
Book Reserve Account shall be reduced until the aggregate AEPS
contributions made under both plans do not exceed three percent
of the Participant's Compensation.
3.3 Interest Accruals. The Book Reserve Account balances,
comprising prior interest credits and all Participant or Employer
Supplemental Contributions credited to a Participant's Book
Reserve Account, shall be credited with interest. All interest
credits pursuant to this Section shall be based on the Book
Reserve Account balance as of the beginning of the month and
computed at an annual rate equal to the Applicable Federal Rate
in effect in December of the prior Plan Year. The Committee
reserves the right to change the rate, method and frequency of
interest credit to the Participants' Book Reserve Accounts.
3.4 AEPS' LIABILITY FOR THE BOOK RESERVE ACCOUNTS. The
amounts credited to the Book Reserve Accounts shall represent
entries made on AEPS' books solely for record keeping purposes
under the Plan. All amounts so credited shall at all times
constitute general, unsecured liabilities of AEPS payable
exclusively out of its general assets, and in no event and under
no circumstance shall AEPS be obligated or required to segregate
from its general assets (whether by trust or otherwise) funds
sufficient to pay any of the amounts from time to time credited
to the Book Reserve Accounts.
3.5 RIGHTS OF PARTICIPANTS IN THE BOOK RESERVE ACCOUNTS.
Nothing contained in the Plan shall be deemed to confer upon any
Participant any right, title or vested interest in and to his
Book Reserve Accounts or the amounts from time to time credited
thereto. Each Participant agrees as a condition of participation
hereunder that (1) AEPS shall only have a contractual obligation
to accrue Participant Supplemental Contributions, Employer
Supplemental Contributions and interest and to distribute the
Book Reserve Account as provided herein, and the rights of the
Participant under the Plan are no greater than the rights of any
unsecured creditor of AEPS, (2) to the extent that any person
other than a Participant acquires a right to receive
distributions from AEPS under the Plan, such right is not greater
than the rights of any general unsecured creditor of AEPS, (3)
nothing contained in the Plan shall create or be construed to
create a trust of any kind or a fiduciary relationship between
AEPS and the Participant, (4) the rights of the Participant may
not be sold, assigned, transferred, pledged, or encumbered, nor
shall any interest of the Participant be liable for the claim of
any creditor of the Participant or subject to any judicial
process involving the Participant, and (5) no Participant shall
have any rights in any specific assets of AEPS, and any Book
Reserve Account established under the Plan only reflects a
contractual obligation of AEPS on its books of accounting and
does not constitute a segregated fund of assets or separation of
assets.
ARTICLE 4
TIME AND METHOD OF ELECTION AND DISTRIBUTION
4.1 TIME AND METHOD OF PARTICIPANT CONTRIBUTION ELECTION.
In order for an election to make Participant Supplemental
Contributions to be effective under Section 3.1 for any given
Plan Year, the Participant must deliver a signed Salary Reduction
Agreement to the Committee no later than December 31 of the year
preceding the Plan Year as to which the election is to take
effect. Upon receipt of the written signed Salary Reduction
Agreement by the Committee, the election shall remain in force as
to the Plan Year for which it is delivered and for each
subsequent Plan Year until it is revoked by a new Salary
Reduction Agreement. Notwithstanding any other provision of the
Plan to the contrary, no election shall be effective to defer
under the Plan any Compensation which is earned by the
Participant on or before the date upon which the signed Salary
Reduction Agreement is delivered to the Committee. The Salary
Reduction Agreement and any revocation thereof shall contain such
information as may be reasonably required by the Committee, shall
be executed at the time and in the manner prescribed, and shall
be delivered to the Committee, attention of the Chairman.
4.2 TIME OF DISTRIBUTION. Following a Participant's
termination of service with AEPS or one of its affiliates or
subsidiaries for any reason other than death, all amounts which
are credited to the Participant's Book Reserve account shall be
distributed to the Participant in the form of (1) a single lump-
sum payment payable as soon as practicable or, alternatively, at
the end of a post-termination deferral period of up to five
years, or (2) in approximately equal annual or semi-annual
installment payments over not less than two or more than ten
years as elected by the Participant. The Participant's
distribution election shall be made when the Participant first
elects to participate in the Plan. The Participant may amend or
revoke the distribution election at any time prior to termination
of service, but any such amendment or revocation must be made at
least twelve months prior to the initial distribution. The
distribution of a lump-sum payment, if the Participant does not
elect to defer the payment of the lump-sum amount, or the first
installment payment shall be made within 120 days after the
Participant's termination of service. If the Participant elected
to defer the payment of the lump-sum payment, the distribution
shall be made within 120 days after the end of the deferral
period. For purposes of this Section 4.2, Participant employment
transfers between AEPS and its affiliates and subsidiaries shall
not be treated as a termination of service with AEPS. If the
Participant elects deferral of the lump-sum payment or elects
installment payments, interest shall continue to accrue on the
remaining Book Reserve Account in accordance with Section 3.3 of
this Plan.
Upon a Participant's death prior to termination of service,
all amounts which are credited to the Participant's Book Reserve
Account shall be distributed to (a) the Participant's estate in a
single lump-sum if the Participant did not name a beneficiary or
if the named beneficiary predeceases the Participant, or (b) to
the Participant's named beneficiary. Distributions to the
beneficiary shall be in the form of (1) a single lump-sum payment
or (2) in approximately equal annual or semi-annual installment
payments over not less than two or more than ten years as elected
by the beneficiary. The beneficiary's distribution election must
be made within 90 days after the Participant's date of death. If
an election is not made, the beneficiary shall receive a lump-sum
payment. The distribution of a lump-sum payment to the
Participant's estate shall be made within 120 days after the
Participant's date of death. The distribution of a lump-sum
payment or the first installment payment to a beneficiary shall
be made within 90 days after the beneficiary makes the
distribution election. If the beneficiary elects installment
payments, interest shall continue to accrue on the remaining
balance in the Book Reserve Account in accordance with Section
3.3 of this Plan. In the event a beneficiary receiving
installment payments shall die prior to a complete distribution
of the Participant's Book Reserve Account, the remaining balance
in the Participant's Book Reserve Account shall be paid to the
beneficiary's estate within 120 days after the Committee is
notified of the beneficiary's death.
4.3 DESIGNATION OF BENEFICIARY. Each Participant shall
have the right to designate a beneficiary or beneficiaries who
shall receive the balance of the Participant's Book Reserve
Account if the Participant dies before the complete distribution
of the Participant's Book Reserve Account. Any designation, or
change or rescission thereof, shall be made in writing by
completing and furnishing to the Committee the appropriate
beneficiary form prescribed by the Committee. The last
designation of beneficiary received by the Committee prior to the
death of the Participant shall control.
4.4 SOCIAL SECURITY AND INCOME TAX WITHHOLDING. Each
Participant agrees that as a condition of participation in the
Plan, AEPS may withhold federal, state and local income taxes and
social security taxes from any distribution hereunder to the
extent that such taxes are then payable.
4.5 FACILITY OF PAYMENT. In the event that the Committee
shall find that a Participant is unable to care for his affairs
because of illness or accident, the Committee may direct that any
benefit payment due him be paid to his duly appointed legal
representative, and any such payment so made shall be a complete
discharge of the liabilities of the Plan therefore.
ARTICLE 5
TAX TREATMENT
The adoption and maintenance of the Plan is conditioned upon
(1) the applicability of Section 451(a) of the Code to the
Participants' recognition of gross income as a result of
participation herein, (2) the fact that the Participants will not
recognize gross income as a result of participation in the Plan
unless and until and then only to the extent that distributions
are received, (3) the applicability of Section 404(a)(5) of the
Code to the deductibility of the amounts distributed to the
Participants hereunder, (4) the fact that AEPS will not receive a
deduction for amounts credited to any Book Reserve unless and
until and then only to the extent that amounts are actually
distributed and (5) the inapplicability of the provisions of
Titles 2, 3, and 4 of ERISA. If the Internal Revenue Service,
the Department of Labor or any court of competent jurisdiction
determines or finds as a fact or legal conclusion that any of the
above conditions is untrue and issues an assessment,
determination, opinion or report to such effect, or if in the
opinion of counsel to AEPS any one of the above assumptions is
incorrect, then AEPS shall have the option to terminate this Plan
as provided in Section 7.2 below.
ARTICLE 6
ADMINISTRATION OF THE PLAN
6.1 RESPONSIBILITY OF COMMITTEE. The Committee shall (i)
administer and interpret the terms and conditions of the Plan,
(ii) establish reasonable procedures with which Participants must
comply to exercise any right established hereunder, and (iii) be
permitted to delegate its responsibilities or duties hereunder to
any person or entity. The rights and duties of the Participants
and all other persons and entities claiming an interest under the
Plan are subject to, and governed by, such acts of
administration, interpretation, procedure and delegation.
6.2 BOOK RESERVE ACCOUNT. AEPS shall maintain, or cause to
be maintained, records showing the individual credit balances of
each Participant's Book Reserve Account. Each Participant shall
be furnished with semi-annual statements setting forth the value
of the total credits to his Book Reserve Account.
6.3 PRESENTATION OF CLAIMS. A Participant, or any other
person or entity claiming under a Participant, may present a
written request to the Committee for distribution of any amounts
due or alleged to be due from the Participant's Book Reserve.
Within 30 days following receipt of the request, the Committee
shall advise the Participant or other person or entity in writing
as to the amount and method of distribution if any.
6.4 APPEAL OF DENIED CLAIMS. If the Committee shall deny a
claim for distribution under the Plan, the Committee shall set
forth in writing in a manner calculated to be understood by the
Participant or other person or entity (1) the specific reason or
reasons for the denial, (2) specific reference to the pertinent
provisions of the Plan upon which the denial is based, (3) a
description of any additional material or information necessary
for the claimant to perfect the claim and an explanation of why
such material or information is necessary, and (4) an explanation
of the Committee's review procedure. The Committee shall afford
the Participant or the person or entity a reasonable opportunity
for a full and fair review by the Committee of its decision to
deny the claim if the claimant requests such a review within 30
days after receipt of the written denial.
ARTICLE 7
MISCELLANEOUS
7.1 EFFECT OF PLAN. The establishment and continuance of
the Plan by AEPS shall not constitute a contract of employment
between any Participant and AEPS, and shall not be deemed to be
consideration for, inducement to or a condition of employment of
any Participant. The making of Salary Cap Contributions pursuant
to the provisions of the Plan shall not be construed to give any
Participant the right to be retained in the employ of AEPS or to
interfere with the right of AEPS to terminate such employment at
any time.
7.2 AMENDMENT AND TERMINATION. AEPS intends to continue
the Plan indefinitely but reserves the right to modify the Plan
from time to time, or to terminate the Plan entirely or to direct
the permanent discontinuance or temporary suspension of
Supplemental Contributions under the Plan; provided that no such
modification, termination, discontinuance or suspension shall
interrupt the interest accruals under Section 3.3 or shall affect
or otherwise deprive the Participants of any distributions to
which they may be entitled under the Plan.
7.3 PROHIBITION AGAINST ASSIGNMENT. The right of any
Participant (or any designated beneficiary) to receive any
payment or installment under the Plan shall not be subject in any
manner to attachment or other legal process or proceedings for
discharge of the debts of the Participant or beneficiary, and any
such payment or installment shall not be subject to anticipation,
alienation, sale, transfer, assignment, pledge, mortgage or
encumbrance.
7.4 GOVERNING LAW. Except to the extent preempted or
superseded by the federal laws of the United States of America,
the laws of the state of Ohio will govern the Plan.
7.5 NOTICES. All notices, reports, statements,
distributions or payments given, made, delivered, or transmitted
to a Participant or his designated beneficiary shall be deemed to
be duly given, made, delivered or transmitted when mailed, by
first class mail, postage prepaid, addressed to the Participant
or beneficiary at the address appearing on the books of AEPS.
Written directions, notices and other communications to AEPS or
the Committee shall be deemed to be duly given, made or delivered
when received by the Committee at such location as it may from
time to time specify.
7.6 GENDER AND NUMBER. Whenever appropriate in the Plan,
the masculine gender shall be construed to include the feminine
and neuter gender, and the feminine gender shall be construed to
include the masculine and neuter gender. Words used in the
singular shall be construed to include the plural, and the plural
to include the singular.
7.7 HEADINGS. The headings of the Articles and Sections of
the Plan are intended solely for convenience of reference, and if
there is any conflict between the headings and the text of the
Plan, the text shall control.
Exhibit 10(i)(1)
AMERICAN ELECTRIC POWER SYSTEM
SENIOR OFFICER ANNUAL INCENTIVE
COMPENSATION PLAN
ARTICLE 1
ESTABLISHMENT, PURPOSE AND EFFECTIVE DATE
1.1 The Company hereby establishes the "American Electric Power
System Senior Officer Annual Incentive Compensation Plan" (the
"Plan").
1.2 The purposes of the Plan are to improve corporate performance
and enhance shareholder value by providing senior officers
incentives to earn annual incentive compensation through the
achievement of performance goals and to assist the Company in
retaining and recruiting key employees.
1.3 The Plan is effective as of January 1, 1997.
ARTICLE 2
DEFINITIONS
2.1 "Account" means, with respect to each Participant, the
Participant's separate individual account established and
maintained for the exclusive purpose of accounting for the
incentive compensation deferred by the Participant in the form
of Stock Units pursuant to Section 3.3 of the Plan.
2.2 "Board" means the Board of Directors of the Company.
2.3 "Committee" means the Human Resources Committee of the Board.
2.4 "Common Stock" means the common stock, $6.50 par value, of the
Company.
2.5 "Company" means American Electric Power Company, Inc., a New
York corporation, and any successor thereto.
2.6 "Incentive Award" means the amount of incentive compensation,
as determined by the Committee, payable to a Participant upon
the attainment of the Performance Goals for the Plan Year.
2.7 "Market Value" means the closing price of the Common Stock, as
published in The Wall Street Journal report of the New York
Stock Exchange - Composite Transactions on the date in
question or, if the Common Stock shall not have been traded on
such date or if the New York Stock Exchange is closed on such
date, then the first day prior thereto on which the Common
Stock was so traded.
2.8 "Participant" means persons holding the positions of Chairman
of the Board, President, Chief Executive Officer and Executive
Vice President of American Electric Power Service Corporation,
a Subsidiary of the Company, and any other senior officer of
the Company or its Subsidiaries selected by the Committee.
2.9 "Performance Goals" means performance goals as shall be
established in writing by the Committee which may be based on,
but are not limited to, earnings, stock price, return on
equity, return on investment, total return to shareholders,
economic value added, debt rating and/or achievement of
business or operational goals, such as safety, customer
satisfaction, market share and/ or business development. Such
goals may be absolute in their terms or measured against or in
relationship to other companies.
2.10 "Plan Year" means the Company's fiscal year commencing January
1 and ending December 31.
2.11 "Stock Unit" means a measure of value, expressed as a share of
Common Stock. No certificates shall be issued with respect to
such Stock Units, but the Company shall maintain a bookkeeping
Account in the name of the Participant to which the Stock
Units shall relate.
2.12 "Subsidiary" means any corporation in which the Company owns
directly or indirectly through it Subsidiaries, at least 50
percent of the total combined voting power of all classes of
stock, or any other entity (including, but not limited to,
partnerships and joint ventures) in which the Company owns at
least 50 percent of the combined equity thereof.
ARTICLE 3
AWARD DETERMINATION AND PAYMENT
3.1 Within 90 days after the commencement of each Plan Year, the
Committee shall establish Performance Goals for such Plan
Year.
3.2 The Incentive Award payable to a Participant shall be
determined by the Committee as soon as practicable after the
determination of the achieved Performance Goals. A
Participant's Incentive Award may range from zero to 60
percent of the Participant's base salary or compensation in
effect at the beginning of the Plan Year depending upon the
level of the Performance Goal achievement. An increase in a
Participant's base salary or compensation during the Plan Year
will not be considered when calculating the Participant's
Incentive Award. The Committee may, in its sole discretion,
reduce or eliminate for any reason the Incentive Award that
would otherwise be payable to a Participant.
3.3 Incentive Award payments shall be made in cash as soon as
practicable after the end of the Plan Year. However, a
Participant may elect to defer payment of all or part of the
Incentive Award for one or more years with a maximum deferral
period that results in payment commencing no later than five
years after the Participant's termination of employment. The
deferral election must be filed with the Company on or before
December 31 of the preceding Plan Year and may be effective
for the immediately following Plan Year or all subsequent Plan
Years. A deferral election may be terminated or modified for
any subsequent Plan Year by the filing of a new deferral
election on or before December 31 of the preceding Plan Year.
3.4 If a Participant elects to defer all or a portion of the
Participant's Incentive Award, Stock Units shall be credited
to the Participant's Account effective January 1 immediately
following the completion of the Plan Year. The number of
whole and fractional Stock Units, computed to three decimal
places, to be credited to the Participant's Account shall be
equal to the dollar amount of the Incentive Award which
otherwise would have been payable to the Participant divided
by the average of the Market Value for the last 20 trading
days of the associated Plan Year. On each dividend payment
date with respect to the Common Stock, the Account of a
Participant shall be credited with an additional number of
whole and fractional Stock Units equal to the product of the
dividend per share then payable, multiplied by the number of
Stock Units then credited to such Account, divided by the
Market Value on the dividend payment date. The number of a
Participant's Stock Units shall be appropriately adjusted for
any change in the Common Stock by reason of any merger,
reclassification, consolidation, recapitalization, stock
dividend, stock split or any similar change affecting the
Common Stock.
3.5 If a Participant's participation in the Plan terminates during
a Plan Year due to the Participant's death, total disability,
retirement or other reasons or causes as approved by the
Committee, the Participant's Incentive Award for the Plan Year
shall be pro-rated based upon the Participant's period of
employment with the Subsidiaries. Such Incentive Award shall
be paid to the Participant or the Participant's beneficiary
when the Incentive Awards for such Plan Year are paid to the
other Participants.
ARTICLE 4
PAYMENT OF DEFERRED INCENTIVE AWARDS
4.1 In accordance with the Participant's election, filed with the
Company, all Stock Units held in a Participant's Account shall
be paid to the Participant either as (a) a lump sum cash
distribution within 10 days after the Participant's deferred
distribution date, or (b) up to 10 annual installments
commencing within 10 days after the Participant's deferred
distribution date. This election shall be made at the same
time the Participant makes a deferral election as provided in
Section 3.3. The amount attributable to the Stock Units shall
be calculated on the basis of the average of the Market Value
of the Common Stock for the last 20 trading days prior to the
Participant's deferred distribution date or respective
installment payment dates, as the case may be.
4.2 If a Participant dies while Stock Units are held in the
Participant's Account, such Stock Units will be paid in a lump
sum in cash within 90 days from the date of the Participant's
death to the Participant's designated beneficiary or the
Participant's estate, as the case may be. The amount of the
lump sum cash distribution attributable to the Stock Units
shall be calculated on the basis of the average of the Market
Value of the Common Stock for the last 20 trading days prior
to the Participant's death. Upon application by the
beneficiary or the legal representative for the Participant's
estate, the lump sum payment may be deferred beyond 90 days
for good cause if the Committee consents to such deferral.
4.3 Each Participant shall have the right to designate a
beneficiary or beneficiaries who shall receive the balance of
the Participant's Account if the Participant dies before the
complete distribution of the Account. Any designation, or
change or rescission thereof, shall be made in writing by
completing and furnishing to the Committee the appropriate
beneficiary form prescribed by the Committee. The last
designation of beneficiary received by the Committee prior to
the death of the Participant shall control.
ARTICLE 5
ADMINISTRATION
5.1 The Plan shall be administered by the Committee. The
Committee shall have the authority to interpret the Plan and
to prescribe, amend and rescind rules and regulations relating
to the administration of the Plan, and all such
interpretations, rules and regulations shall be conclusive and
binding on all Participants.
5.2 The Committee may employ agents, attorneys, accountants, or
other persons (who also may be employees of a Subsidiary) and
allocate or delegate to them powers, rights, and duties, all
as the Committee may consider necessary or advisable to
properly carry out the administration of the Plan.
ARTICLE 6
MISCELLANEOUS
6.1 The Committee shall have the right, authority and power to
alter, amend, modify, revoke or terminate the Plan; except as
provided in Article 7; and provided further, that no amendment
or termination of the Plan shall adversely affect the rights
of any Participant with respect to any Stock Units held in
such Participant's Account, unless the Participant shall
consent thereto in writing.
6.2 No benefits at any time payable under this Plan to a
Participant or beneficiary shall be subject in any manner to
anticipation, alienation, sale, transfer, assignment, pledge,
attachment, garnishment, levy, execution, or other legal or
equitable process, or encumbrance of any kind.
6.3 A Participant's deferred Incentive Award shall be totally
unfunded so that the Company or any Subsidiary is under merely
a contractual duty to make payments when due under the Plan.
The promise to pay shall not be represented by notes and shall
not be secured in any way.
6.4 Nothing in this Plan shall interfere with or limit in any way
the right of the Company or any Subsidiary to terminate any
Participant's employment at any time, nor confer upon any
Participant any right to continue in the employ of the Company
or Subsidiary.
6.5 The Plan shall be construed and administered according to the
laws of the State of New York to the extent that those laws
are not preempted by the laws of the United States of America.
6.6 The Company or its Subsidiaries may withhold federal, state
and local income taxes and social security taxes from any
distribution hereunder to the extent that such taxes are then
payable.
6.7 In the event the Committee shall find that a Participant is
unable to care for his or her affairs because of illness or
accident, the Committee may direct that any payment due the
Participant be paid to the Participant's duly appointed legal
representative, and any such payment so made shall be a
complete discharge of the liabilities of the Plan.
ARTICLE 7
CHANGE IN CONTROL
Notwithstanding any provision of this Plan to the contrary, if a
"Change in Control" (as defined below) of the Company occurs, Stock
Units held in a Participant's Account shall be paid to the
Participant in a lump sum in cash not later than 15 days after the
date of the Change in Control. For this purpose, the balance in
the Account shall be determined by the higher of (a) the average of
the Market Value of the Common Stock for the last 20 trading days
prior to such Change in Control or (b) if the Change in Control of
the Company occurs as a result of a tender or exchange offer or
consummation of a corporate transaction, then the highest price
paid per share of Common Stock pursuant thereto. Any consideration
other than cash forming a part or all of the consideration for the
Common Stock to be paid pursuant to the applicable transaction
shall be valued at the valuation price thereon determined by the
Board.
In addition, the Company shall reimburse a Participant for the
legal fees and expenses incurred if the Participant is required to
seek to obtain or enforce any right to distribution. In the event
that it is determined that such Participant is properly entitled to
a cash distribution hereunder, such Participant shall also be
entitled to interest thereon at the prime rate of interest as
published in The Wall Street Journal plus two percent from the date
such distribution should have been made to and including the date
it is made. Notwithstanding any provisions of this Plan to the
contrary, the provisions of this Article may not be amended by an
amendment effected within three years following a Change in
Control.
A "Change in Control" of the Company shall be deemed to have
occurred if (a) any "person" or "group" (as such terms are used in
Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as
amended ("Exchange Act")), other than a trustee or other fiduciary
holding securities under an employee benefit plan of the Company,
becomes the "beneficial owner" (as defined in Rule 13d-3 under the
Exchange Act), directly or indirectly, of more than 25 percent of
the then outstanding voting stock of the Company; (b) during any
period of two consecutive years, individuals who at the beginning
of such period constitute the Board, together with any new
directors whose election or nomination for election was approved by
a vote of at least two-thirds of the directors then still in office
who were either directors at the beginning of the period or whose
election or nomination for election was previously so approved,
cease for any reason to constitute at least a majority of the
Board; or (c) the Company's shareholders approve a merger or
consolidation of the Company with any other corporation, other than
a merger or consolidation which would result in the voting
securities of the Company outstanding immediately prior thereto
continuing to represent (either by remaining outstanding or by
being converted into voting securities of the surviving entity) at
least 75 percent of the total voting power represented by the
voting securities of the Company or such surviving entity
outstanding immediately after such merger or consolidation; or (d)
the shareholders of the Company approve a plan of complete
liquidation of the Company, or an agreement for the sale or
disposition by the Company (in one transaction or a series of
transactions) of all or substantially all of the Company's assets.
Notwithstanding the foregoing, a Change in Control shall not be
deemed to occur as a result of any event described in (a) or (c)
above, if Directors who were a majority of the members of the Board
prior to such event and who continue to serve as Directors after
such event determine that the event shall not constitute a Change
in Control.
Exhibit 10(i)(2)
American Electric Power System
Performance Share Incentive Plan
as Amended and Restated through February 26, 1997
Article 1. Establishment and Purpose
1.1 Establishment of the Plan.
The Company hereby establishes an incentive compensation plan to be
known as the "American Electric Power System Performance Share
Incentive Plan" (the "Plan"), as set forth in this document.
1.2 Purposes.
The Purposes of the Plan are to provide competitive, longer-term,
performance driven, incentive compensation opportunities to
Participants, which are directly related to and dependent upon the
competitiveness of the longer-term returns realized by the
Company's shareholders; and to facilitate ownership of Restricted
Stock Units by Participants so as to equate further their long-term
financial interests with those of the shareholders.
Article 2. Effective Date and Term of Plan
The Plan was approved by the Company's shareholders and the
Securities and Exchange Commission effective January 1, 1994.
While the Board may suspend or terminate the Plan at any time, no
such suspension or termination shall adversely affect any
outstanding Performance Share Units without the Participant's
written consent as specified in Section 12.2. No Performance Share
Units shall be granted for Performance Periods commencing after
December 31, 2003.
Article 3. Definitions
Whenever used in the Plan, the following terms shall have the
meanings set forth below and, when the meaning is intended, the
initial letter of the word is capitalized:
(a) "Award Certificate" means a certificate setting forth the
terms and provisions applicable to each grant of
Performance Share Units, which shall include, but shall
not be limited to, the number of Performance Share Units
granted to the Participant, the Performance Measure, the
levels of Performance Share Unit payment opportunities
based on the Performance Measure, the method of
determining earned Performance Share Units pursuant to
Section 8.1 and the length of the Performance Period.
(b) "Board" means the Board of Directors of the Company.
(c) "Committee" shall mean the Human Resources Committee of
the Board.
(d) "Common Stock" shall mean the common stock of the
Company.
(e) "Company" means American Electric Power Company, Inc., a
New York corporation, and any successor thereto.
(f) "Director" means an individual who is a member of the
Board.
(g) "Disability" shall have the definition set forth in the
American Electric Power System Retirement Plan.
(h) "Equivalent Stock Ownership Target" means a stock
ownership target for each Participant established by the
Board which is a combination of Common Stock and Common
Stock equivalents held by a Participant.
(i) "Fair Market Value" means the closing sale price of the
Common Stock, as published in The Wall Street Journal
report of New York Stock Exchange -- Composite
Transactions on the date in question or, if the Common
Stock shall not have been traded on such date or if the
New York Stock Exchange is closed on such date, then the
first day prior thereto on which the Common Stock was so
traded.
(j) "Participant" means any full-time, nonunion employee of
any Subsidiary, who has been selected to participate in
the Plan for a stipulated Performance Period by the
Committee.
(k) "Performance Measure" means, for a period of at least
three years, the financial objective to be applied to the
Performance Period in which Performance Share Units held
by a Participant for a Performance Period are earned,
based on the relative ranking of the Company's TSR
compared to the TSR's of the companies comprising the S&P
Electric Utility Index.
(l) "Performance Period" means the period established by the
Committee, during which the number of Performance Share
Units earned by Participants shall be determined.
(m) "Performance Share Unit" means a measure of
participation, expressed as a share of Common Stock,
received as a grant under Section 7.1 or as a dividend
under Section 7.2.
(n) "Restricted Stock Unit" means a measure of value,
expressed as a share of Common Stock, allocated to a
Participant under Section 8.1. No certificates shall be
issued with respect to such Restricted Stock Units, but
the Company shall maintain a bookkeeping account in the
name of the Participant to which the Restricted Stock
Units shall relate.
(o) "Retirement" means termination of employment with any
Subsidiary other than for cause after attaining age 55
and at least five (5) years of service.
(p) "Section 162(m)" means Section 162(m) of the Internal
Revenue Code of 1986, as amended and applicable
interpretive authority thereunder.
(q) "Subsidiary" shall mean any corporation in which the
Company owns directly or indirectly through its
Subsidiaries, at least fifty percent (50%) of the total
combined voting power of all classes of stock, or any
other entity (including, but not limited to, partnerships
and joint ventures) in which the Company owns at least
fifty percent (50%) of the combined equity thereof.
(r) "Transition Performance Period" means the one (1) and two
(2) year Performance Periods that may be made available
on a one-time basis to Participants receiving Performance
Share Units at the commencement of the Plan and
Participants receiving their first grant of Performance
Share Units for a Performance Period at any time during
the term of the Plan.
(s) "TSR" means total shareholder return and is the compound
product of the annual TSR amounts obtained by dividing:
(1) the sum of: (i) the annual amount of dividends for
each year of the Performance Period, assuming dividend
reinvestment, and (ii) the difference between the share
price at the end and the beginning of each year of the
Performance Period; by (2) the share price at the
beginning of each year of the Performance Period.
Article 4. Administration
4.1 The Committee.
The Plan shall be administered by the Committee consisting of not
less than three (3) Directors. Each member of the Committee shall
at all times while serving be an "outside director" within the
meaning of Section 162(m).
4.2 Authority of the Committee.
Subject to the provisions herein and to the approval of the Board,
the Committee shall have full power for the following:
(a) Selecting Participants to whom Performance Share Units
are granted.
(b) Determining the size and frequency of grants (which need
not be the same for each Participant), except as limited
by Article 5.
(c) Construing and interpreting the Plan and any agreement or
instrument entered into under the Plan.
(d) Establishing, amending, rescinding or waiving rules and
regulations for the Plan's administration.
(e) Amending, modifying, and/or terminating the Plan, subject
to the provisions of Article 12 herein.
Further, the Committee shall have the full power to make all other
determinations which may be necessary or advisable for the
administration of the Plan, to the extent consistent with the
provisions of the Plan, and subject to the approval of the Board.
As permitted by law, the Committee may delegate its authority as
identified hereunder; provided, however, that the Committee may not
delegate certain of its responsibilities hereunder if such
delegation may jeopardize compliance with the "outside directors"
provision of Section 162(m).
4.3 Decisions Binding.
All determinations and decisions made by the Committee pursuant to
the provisions of the Plan, and all related orders or resolutions
of the Board shall be final, conclusive, and binding on all
persons, including the Company, its shareholders, Participants and
their estates, and beneficiaries.
Article 5. Maximum Awards and Adjustments
5.1 Maximum Amount Available for Awards.
The maximum number of Performance Share Units which may be earned
during the term of the Plan on an aggregate basis is 1,000,000 and,
for one Performance Period, the maximum number of Performance Share
Units which may be earned by a Participant is 25,000.
Not more than 1,000,000 shares of Common Stock will be available
for delivery upon payment for Performance Share Units earned under
the Plan. The shares to be delivered under the Plan will be made
available from shares reacquired by the Company.
The limitations in this Section 5.1 on the maximum amount of
Performance Share Units and shares of Common Stock available under
the Plan are subject to adjustment as provided in Section 5.2.
5.2 Adjustments.
If the Committee determines that the occurrence of any merger,
reclassification, consolidation, recapitalization, stock dividend
or stock split requires an adjustment in order to preserve the
benefits intended under the Plan, then the Committee may, in its
discretion, make equitable proportionate adjustments in the maximum
number of Performance Share Units which may be earned on an
aggregate basis or by a Participant, the maximum number of shares
of Common Stock which may be delivered, as specified in Section
5.1, and the number of Restricted Stock Units held by a
Participant.
Article 6. Eligibility and Participation
6.1 Eligibility.
Eligibility for participation in the Plan shall be limited to
senior officers of the Company and/or its Subsidiaries who, in the
opinion of the Committee, have the capacity for contributing in a
substantial measure to the successful performance of the Company.
6.2 Actual Participation.
Participation in the Plan shall begin on the first day of each
Performance Period. At the beginning of each Performance Period,
the Committee will identify which, if any, Participants shall
receive a grant of Performance Share Units for that Performance
Period. As soon as practicable following selection, a Participant
shall receive an Award Certificate.
Article 7. Grants of Performance Share Units
7.1 Grant Timing, Frequency and Number.
Performance Share Units may be granted to Participants as of the
first day of each Performance Period on an annual basis. It is
intended that Performance Periods will overlap. However, grants do
not necessarily have to be on an annual basis. The number of
Performance Share Units to be granted to each Participant shall be
determined by the Committee in its sole discretion.
7.2 Dividends.
During the Performance Period, Participants will be credited with
dividends, equivalent in value to those declared and paid on shares
of the Common Stock, on all Performance Share Units granted to
them. These dividends will be regarded as having been reinvested
in Performance Share Units on the date of the Common Stock dividend
payments based on the then Fair Market Value of the Common Stock,
thereby increasing the number of Performance Share Units held by a
Participant.
Participants will be credited with dividend equivalents, equal in
value to those declared and paid on shares of Common Stock, on all
Restricted Stock Units allocated to the Participants. Dividend
equivalents on Restricted Stock Units required to be held pursuant
to Section 8.2 or deferred pursuant to Section 8.4 will be regarded
as having been reinvested in Restricted Stock Units on the date of
the Common Stock dividend payments based on the then Fair Market
Value of the Common Stock, thereby increasing the number of
Restricted Stock Units held by a Participant.
7.3 Performance Periods.
Subject to the next sentence, the Committee shall establish
Performance Periods in its discretion. Performance Periods shall,
in all cases, be at least three (3) years in length, except for the
Transition Performance Periods.
The first Performance Periods shall be the one (1) and two (2) year
Transition Performance Periods ending December 31, 1994 and
December 31, 1995, respectively, and the three-year period
beginning January 1, 1994 and ending December 31, 1996.
Performance Share Units granted as part of the initial grant of
Performance Share Units for such Performance Periods shall be
deemed to be granted as of the first day of such Performance
Periods.
Article 8. Determination and Payment
8.1 Determination.
The number of Performance Share Units earned by a Participant for
a Performance Period shall be determined by multiplying the number
of Performance Share Units held by the Participant at the end of
the Performance Period by a factor based upon the Performance
Measure. No Performance Share Units shall be earned by any
Participant if, at the end of the Performance Period, shareholders
do not realize a positive TSR under the Performance Measure. In
any event, the Committee may, at its discretion, reduce the number
of Performance Share Units earned by any Participant for a
Performance Period.
Earned Performance Share Units shall be converted to Restricted
Stock Units if the Participant has not met the Equivalent Stock
Ownership Target. A Participant shall receive one Restricted Stock
Unit for each earned Performance Share Unit. Once a Participant
has attained the Equivalent Stock Ownership Target, earned
Performance Share Units shall be paid to the Participant at the end
of the Performance Period as provided in Section 8.3 or may be
deferred by the Participant as provided in Section 8.4.
8.2 Holding of Restricted Stock Units.
Restricted Stock Units required to meet the Equivalent Stock
Ownership Target will be held until the Participant terminates
employment at which time the Participant shall receive payment for
the Restricted Stock Units unless the Participant has elected
deferral of such payment in accordance with Section 8.4.
8.3 Payment of Restricted Stock Units and Earned Performance
Share Units.
The payment of Restricted Stock Units that were required to be held
pursuant to Section 8.2 shall be made in cash, shares of Common
Stock, or a combination of both as then elected by the Participant.
Cash payments of Restricted Stock Units shall be calculated on the
basis of the average of the Fair Market Value of the Common Stock
for the last 20 trading days prior to the Participant's employment
termination date or the date of the Participant's death, as the
case may be.
The payment of earned Performance Share Units not required to be
converted to Restricted Stock Units pursuant to Section 8.1 shall
be made in cash, shares of Common Stock, or a combination of both
as then elected by the Participant. Cash payments of earned
Performance Share Units shall be calculated on the basis of the
average of the Fair Market Value of the Common Stock for the last
20 trading days of the Performance Period for which the Performance
Share Units were earned.
8.4 Deferrals.
Once the Participant attains the Equivalent Stock Ownership Target,
the Participant may make annual elections to defer the payment of
subsequent earned Performance Share Units for one or more years;
however, if the Participant's deferral period extends beyond the
Participant's employment termination date, payment must commence no
later than five years after the Participant's termination of
employment. The deferral election must be made at least one year
prior to the end of the Performance Period for which the
Participant has received an allocation with regard to a Performance
Period and each earned Performance Share Unit shall be converted
into a Restricted Stock Unit. The Participant may also elect to
defer the payment of Restricted Stock Units provided under Section
8.2 for a period of one or more years with a maximum deferral
period that results in payment commencing no later than five years
following termination of employment, but such election must be made
at least one year prior to termination of employment. As elected
by the Participant, payment of the Participant's elective deferrals
will be made at the end of the deferral period as a lump sum
distribution or up to 10 annual installments. Payments may be made
in cash, shares of Common Stock, or a combination of both as then
elected by the Participant. Cash payments of Restricted Stock
Units shall be calculated on the basis of the average of the Fair
Market Value of the Common Stock for the last 20 trading days prior
to the Participant's deferred distribution date, respective
installment payment dates or the date of the Participant's death,
as the case may be.
8.5 Manner of Payment.
Payment in Common Stock shall be at the rate of one share of Common
Stock for each Restricted Stock Unit or earned Performance Share
Unit, with any fractional shares paid in cash. The election to be
paid in cash or Common Stock must be filed with the Company at
least 30 days prior to the payment date and, in the event an
election is not made, payment will be made in cash.
8.6 Payment Upon Death
Notwithstanding the Participant's election, if a Participant dies
while Restricted Stock Units are held by the Participant, such
Restricted Stock Units will be paid in a lump sum in cash within 90
days from the date of the Participant's death to the Participant's
designated beneficiary or the Participant's estate, as the case may
be. Upon application by the beneficiary or the legal
representative for the Participant's estate, the lump sum payment
may be deferred beyond 90 days for good cause if the Committee
consents to such deferral.
8.7 Performance Share Units Granted in 1994.
Performance Share Units granted in 1994 for the two Transition
Performance Periods ending December 31, 1994 and December 31, 1995
and for the Performance Period ending December 31, 1996 shall be
paid 50% in cash and 50% in Common Stock unless the Participant
consents to have the Performance Share Units earned for the
Transition Performance Period ending December 31, 1995 and the
Performance Share Units earned for the Performance Period ending
December 31, 1996 paid in accordance with the provisions of
Sections 8.1 through 8.4. The payment in cash and Common Stock
shall be as provided in the second paragraph of Section 8.3.
8.8 Limitations on Sales of Common Stock.
A Participant shall not be permitted to sell the shares of Common
Stock distributed to such Participant pursuant to Section 8.7 until
the Participant has attained the Equivalent Stock Ownership Target
without counting such shares towards the attainment of the Target.
In order to enforce the limitations imposed upon the shares of
Common Stock distributed pursuant to Section 8.7, the Committee may
(a) direct the delivery of stock certificates to Participants to be
withheld until the shares of Common Stock covered by such
certificates may be sold by the Participant, (b) cause a legend or
legends to be placed on any such certificates, and/or (c) issue
"stop transfer" instructions as it deems necessary or appropriate.
Holders of shares of Common Stock limited as to sale under this
Section 8.8 shall have rights as a shareholder with respect to such
shares to receive dividends in cash or other property or other
distribution or rights in respect of such shares and to vote such
shares as the record owner thereof.
Article 9. Termination of Employment
9.1 Termination of Employment Due to Death, Disability, Retirement
or Involuntary Termination Other Than for Cause.
In the event of a Participant's termination of employment with the
Subsidiaries, prior to the end of a Performance Period but after
the first six months of such Performance Period, by reason of the
Participant's death, Disability, Retirement or involuntary
termination other than for cause, the Participant will be eligible
to earn prorated Performance Share Units for each such Performance
Period which has not yet ended, determined pursuant to Section 8.1
for such period and the number of days of participation during such
Performance Period. In the case of the Transition Performance
Periods, the Performance Share Units earned would not be subject to
proration if the employment period and termination conditions
specified in this Section 9.1 were met.
9.2 Termination for Reasons Other Than Death, Disability,
Retirement or Involuntary Termination Other Than for Cause.
In the event a Participant's employment is terminated for reasons
other than death, Disability, Retirement or involuntary termination
other than for cause, all rights to any unearned Performance Share
Units under the Plan shall be forfeited.
Article 10. Beneficiary Designation
10.1 Designation of Beneficiary.
Each Participant shall be entitled to designate a beneficiary or
beneficiaries who, following the Participant's death, will be
entitled to receive any payments to be made under Section 8.6. All
designations shall be signed by the Participant, and shall be in
such form as prescribed by the Committee. Each designation shall
be effective as of the date delivered to the Company by the
Participant. The Participant may change his or her designation of
beneficiary on such form as prescribed by the Committee. The
payment of any amounts owing to a Participant pursuant to such
Participant's outstanding Performance Share Units or Restricted
Stock Units held under the Plan shall be in accordance with the
last unrevoked written designation of beneficiary that has been
signed by the Participant and delivered by the Participant to the
Company prior to the Participant's death.
10.2 Death of Beneficiary.
In the event that all of the beneficiaries named by a Participant
pursuant to Section 10.1 herein predecease the Participant, any
amounts that would have been paid to the Participant or the
Participant's beneficiaries under the Plan shall be paid to the
Participant's estate.
Article 11. Rights of Participants
11.1 Employment.
Nothing in the Plan shall interfere with or limit in any way the
right of the Company or any Subsidiary to terminate any
Participant's employment at any time, nor confer upon any
Participant any right to continue in the employ of the Company or
Subsidiary.
11.2 Participation.
No Participant shall at any time have a right to be selected for
participation in the Plan for any Performance Period, despite
having been selected for participation in a previous Performance
Period.
11.3 Nontransferability.
No Performance Share Units held by a Participant or Restricted
Stock Units held pursuant to Sections 8.2 or 8.4 may be sold,
transferred, pledged, assigned, or otherwise alienated or
hypothecated, other than by will or by the laws of descent and
distribution.
11.4 Rights to Common Stock.
Performance Share Units or Restricted Stock Units do not give a
Participant any rights whatsoever with respect to shares of Common
Stock until such time and to such extent that payment of earned
Performance Share Units or Restricted Stock Units is made in shares
of Common Stock as requested by the Participant.
Article 12. Amendment, Modification and Termination
12.1 Amendment, Modification and Termination.
The Committee may amend or modify the Plan at any time, with the
approval of the Board. However, without the approval of the
shareholders of the Company, no such amendment or modification may:
(a) Materially modify the eligibility requirements of the
Plan.
(b) Materially increase the benefits accruing to Participants
under the Plan.
(c) Materially increase the number of Performance Share Units
which may be earned on an aggregate basis or by a
Participant (except as provided in Section 5.2).
(d) Materially increase the maximum number of shares of
Common Stock available for payment under the Plan (except
as provided in Section 5.2).
(e) Modify the Performance Measure and the method of
determining Performance Share Units earned pursuant to
Section 8.1, except as may be permitted by Section
162(m).
12.2 Performance Share Units Previously Granted.
No termination, amendment or modification of the Plan shall in any
manner adversely affect any outstanding Performance Share Units or
Restricted Stock Units under the Plan, without the written consent
of the Participant holding such Performance Share Units or
Restricted Stock Units.
Article 13. Miscellaneous Provisions
13.1 Costs of the Plan.
The costs of the Plan awards shall be paid directly by the
Subsidiary that pays each Participant's base salary during the
Performance Period. Although not prohibited from doing so, the
Subsidiary is not required in any way to segregate assets in any
manner or to specifically fund the benefits provided under the
Plan.
13.2 Relationship to Other Benefits.
No payment under the Plan shall be taken into account in
determining any benefits under any pension, retirement, group
insurance, or other benefit plan of the Company and/or its
Subsidiaries.
13.3 Governing Law.
To the extent not preempted by Federal law, the Plan, and all
agreements hereunder, shall be construed in accordance with and
governed by the laws of the State of New York.
Article 14. Change in Control
Notwithstanding any provision of this Plan to the contrary, if a
"Change in Control" (as defined below) of the Company occurs,
Restricted Stock Units held by a Participant will be paid in a lump
sum in cash, shares of Common Stock, or a combination of both, to
the Participant, as elected by the Participant, not later than 15
days after the date of the Change in Control. For this purpose,
the Restricted Stock Units shall be determined by the higher of (a)
the average of the Market Value of the Common Stock for the last 20
trading days prior to such Change in Control or (b) if the Change
in Control of the Company occurs as a result of a tender or
exchange offer or consummation of a corporate transaction, then the
highest price paid per share of Common Stock pursuant thereto. Any
consideration other than cash forming a part or all of the
consideration for the Common Stock to be paid pursuant to the
applicable transaction shall be valued at the valuation price
thereon determined by the Board.
In addition, the Company shall reimburse a Participant for the
legal fees and expenses incurred if the Participant is required to
seek to obtain or enforce any right to distribution. In the event
that it is determined that such Participant is properly entitled to
a cash distribution hereunder, such Participant shall also be
entitled to interest thereon at the prime rate of interest as
published in The Wall Street Journal plus two percent from the date
such distribution should have been made to and including the date
it is made. Notwithstanding any provisions of this Plan to the
contrary, the provisions of this Article may not be amended by an
amendment effected within three years following a Change in
Control.
A "Change in Control" of the Company shall be deemed to have
occurred if (a) any "person" or "group" (as such terms are used in
Sections 13(d) and 14(d) of the Securities Exchange Act of 1934
("Exchange Act")), other than a trustee or other fiduciary holding
securities under an employee benefit plan of the Company, becomes
the "beneficial owner" (as defined in Rule 13d-3 under the Exchange
Act), directly or indirectly, of more than 25 percent of the then
outstanding voting stock of the Company; (b) during any period of
two consecutive years, individuals who at the beginning of such
period constitute the Board, together with any new Directors whose
election or nomination for election was approved by a vote of at
least two-thirds of the Directors then still in office who were
either Directors at the beginning of the period or whose election
or nomination for election was previously so approved, cease for
any reason to constitute at least a majority of the Board; or (c)
the Company's shareholders approve a merger or consolidation of the
Company with any other corporation, other than a merger or
consolidation which would result in the voting securities of the
Company outstanding immediately prior thereto continuing to
represent (either by remaining outstanding or by being converted
into voting securities of the surviving entity) at least 75 percent
of the total voting power represented by the voting securities of
the Company or such surviving entity outstanding immediately after
such merger or consolidation; or (d) the shareholders of the
Company approve a plan of complete liquidation of the Company, or
an agreement for the sale or disposition by the Company (in one
transaction or a series of transactions) of all or substantially
all of the Company's assets.
Notwithstanding the foregoing, a Change in Control shall not be
deemed to occur as a result of any event described in (a) or (c)
above, if Directors who were a majority of the members of the Board
prior to such event and who continue to serve as Directors after
such event determine that the event shall not constitute a Change
in Control.
Exhibit 10(l)
MODIFICATION NO. 1 TO THE
AEP SYSTEM INTERIM ALLOWANCE AGREEMENT
BY AND AMONG
APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
KENTUCKY POWER COMPANY
OHIO POWER COMPANY
AND WITH
AMERICAN ELECTRIC POWER SERVICE CORPORATION
AS AGENT
CONTENTS
PREAMBLE . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
ARTICLE 1 - Definitions. . . . . . . . . . . . . . . . . . . 4
ARTICLE 2 - Emission Allowance Management. . . . . . . . . . 9
ARTICLE 3 - Agent's Responsibilities . . . . . . . . . . . . 10
ARTICLE 4 - Settlements. . . . . . . . . . . . . . . . . . . 11
ARTICLE 5 - Billings and Payments. . . . . . . . . . . . . . 15
ARTICLE 6 - Taxes. . . . . . . . . . . . . . . . . . . . . . 15
ARTICLE 7 - Modifications. . . . . . . . . . . . . . . . . . 16
ARTICLE 8 - Effective Date and Terms of this Agreement . . . 16
ARTICLE 9 - Regulatory Authorities . . . . . . . . . . . . . 17
ARTICLE 10 - Assignment . . . . . . . . . . . . . . . . . . . 17
0.1 THIS AGREEMENT, made and entered into as of the 28th day
of July, 1994 by and among APPALACHIAN POWER COMPANY (APCo), a
Virginia corporation, COLUMBUS SOUTHERN POWER COMPANY (CSP), an
Ohio corporation, INDIANA MICHIGAN POWER COMPANY (I&M), an Indiana
corporation, KENTUCKY POWER COMPANY (KPCo), a Kentucky corporation,
OHIO POWER COMPANY (OPCo), an Ohio corporation, said companies
(herein sometimes called 'Members' when referred to collectively
and 'Member' when referred to individually) being affiliated
companies of the integrated public utility electric system known as
the American Electric Power System (AEP), and AMERICAN ELECTRIC
POWER SERVICE CORPORATION (Agent), a New York corporation, being a
service company engaged solely in the business of furnishing
essential services to the aforesaid companies and the other
affiliated companies.
W I T N E S S E T H
T H A T:
0.2 WHEREAS, the Members own and operate electric facilities
in the states herein indicated, (i) APCo in Virginia, West Virginia
and Tennessee, (ii) CSP in Ohio, (iii) I&M in Indiana and Michigan,
(iv) KPCo in Kentucky, and (v) OPCo in Ohio and West Virginia; and
0.3 WHEREAS, the Members have entered into an Interconnection
Agreement, dated July 6, 1951, with modifications thereto, which
provides for certain understandings, conditions, and procedures
designed to achieve the full benefits and advantages available
through the coordinated planning and operation of their electric
power supply facilities; and
0.4 WHEREAS, Congress in 1990 enacted amendments to the Clean
Air Act, including Title IV, 104 Stat. 2584, 42 U.S.C.A. Section
7651, et seq. ("the 1990 Amendments") which limit emissions of
sulfur dioxide (SO2) by electric utilities; and
0.5 WHEREAS, under the 1990 Amendments, compliance is to be
achieved in two stages -- Phase I, which begins January 1, 1995 and
Phase II which begins January 1, 2000; and reductions in sulfur
dioxide emissions are to be effected by a system in which a limited
number of "emission allowances" have been allocated by the United
States Environmental Protection Agency (EPA) to individual utility
generating units; and
0.6 WHEREAS, twenty-one (21) of the Members' generating units
have been designated by the 1990 Amendments as Phase I affected
units, and fifty-one (51) of the Members' generating units have
been designated as Phase II affected units, and as such, have been
awarded emission allowances by the EPA; and
0.7 WHEREAS, the Members may have ownership or entitlement to
emission allowances through several means, including: (i) EPA-
AWARDED ALLOWANCES based on emission levels experienced during a
base-line period, (ii) EPA bonus allowances awarded for various
compliance strategies, primarily through the installation of FGD
systems, and (iii) the purchase of allowances. Generally, Members
are permitted to emit SO2 only to the extent they have allowances
to cover such emissions.
0.8 WHEREAS, compliance with the 1990 Amendments has been and
will continue to be planned by the Members on an integrated and
coordinated basis, consistent with the integrated and coordinated
planning and operation of the Members' electric systems; and
0.9 WHEREAS, the Members desire to arrive at an equitable
methodology of allocating emission allowances and associated costs
and benefits between and among the Members; and
0.10 WHEREAS, the Members have entered into the Interim
Allowance Agreement to establish, on an interim basis, a
methodology and transfer price for the transfer of SO2 emission
allowances; and
0.11 WHEREAS, the Members believe that an agreement which
provides for an equitable assignment of cost and benefits among the
Members can best be realized if administered by a single clearing
agent; and
0.12 WHEREAS, the Members believe that the Agent designated
herein for such purpose is qualified to perform such services;
0.13 NOW, THEREFORE, in consideration of the premises and of
the mutual covenants and agreements hereinafter contained, the
parties hereto, hereby agree as follows:
ARTICLE 1 - DEFINITIONS
1.1 The following terms and factors associated with
settlements under this Agreement are defined in alphabetic order as
follows:
1.2 DELIVERING MEMBER -- a Member which sells PRIMARY ENERGY
and/or ECONOMY ENERGY to the POOL.
1.3 ECONOMY ENERGY -- electric energy delivered to the POOL
from the MEMBER PRIMARY CAPACITY of a particular Member to displace
energy that otherwise would be supplied by less efficient MEMBER
PRIMARY CAPACITY of another Member to meet its MEMBER LOAD
OBLIGATION.
1.4 EPA-AWARDED ALLOWANCES -- the allowances awarded to each
generating unit by the EPA as defined in Section 404(a) of the 1990
Amendments.
1.5 FERC -- the Federal Energy Regulatory Commission or any
successor agency.
1.6 GAVIN BONUS ALLOWANCES -- 184.7, 184.0, 44.6, 44.6 and
44.6 thousand allowances, excluding transfer allowances, for the
years 1995, 1996, 1997, 1998 and 1999, respectively, awarded by the
EPA to OPCo's Gavin Plant pursuant to Section 404(d) of the 1990
Amendments.
1.7 GAVIN EPA-AWARDED ALLOWANCES -- the allowances awarded to
the Gavin Plant by the EPA pursuant to Section 404(a) of the 1990
Amendments.
1.8 GAVIN SCRUBBER SO2 REDUCTION -- the difference between
actual SO2 emissions at OPCo's Gavin Plant operating with scrubbers
and GAVIN UNCONTROLLED EMISSIONS for a given year.
1.9 GAVIN UNCONTROLLED EMISSIONS -- an estimated amount of
SO2 emissions that would result from operating the Gavin Plant
without scrubbers. The estimate of GAVIN UNCONTROLLED EMISSIONS is
calculated by dividing the scrubbed Gavin SO2 EMISSIONS by (1.00
minus the scrubber SO2 removal efficiency rate).
1.10 INTERCONNECTION AGREEMENT -- the Interconnection
Agreement among the Members dated July 6, 1951, as amended.
1.11 MEMBER AFFECTED UNITS -- a Member's generating units that
are required to meet the emission standards established by the 1990
Amendments.
1.12 MEMBER CAPACITY DEFICIT FACTOR -- for any Member, the
average for the calendar year of its MEMBER PRIMARY CAPACITY
DEFICIT divided by the sum of all members' average MEMBER PRIMARY
CAPACITY DEFICITS.
1.13 MEMBER DEMAND -- MEMBER LOAD OBLIGATION determined on a
clock-hour integrated kilowatt basis.
1.14 MEMBER GENERATION -- the total of a Member's net
generation from its MEMBER PRIMARY CAPACITY.
1.15 MEMBER LOAD OBLIGATION -- a Member's internal load plus
any firm power sales to Foreign Companies and to affiliated
companies other than Members.
1.16 MEMBER LOAD RATIO -- the ratio of a particular Member's
MEMBER MAXIMUM DEMAND in effect for a calendar month to the sum of
the five MEMBER MAXIMUM DEMANDS in effect for such month.
1.17 MEMBER MAXIMUM DEMAND -- the MEMBER MAXIMUM DEMAND in
effect for a calendar month for a particular Member shall be equal
to the maximum MEMBER DEMAND experienced by said Member during the
twelve consecutive calendar months next preceding such calendar
month.
1.18 MEMBER PRIMARY CAPACITY -- the aggregate capacity of the
electric power sources of a particular Member, in kilowatts, that
is normally expected to be available to carry load. Such capacity
shall include (i) the capacity installed at the generating stations
owned by the Member and (ii) the capacity available to that Member
through interconnection arrangements with affiliated companies or
Foreign Companies.
1.19 MEMBER PRIMARY CAPACITY DEFICIT -- difference between the
MEMBER PRIMARY CAPACITY and MEMBER PRIMARY CAPACITY RESERVATION of
a particular Member, when such MEMBER PRIMARY CAPACITY is less than
such MEMBER PRIMARY CAPACITY RESERVATION.
1.20 MEMBER PRIMARY CAPACITY RESERVATION -- SYSTEM PRIMARY
CAPACITY multiplied by the MEMBER LOAD RATIO of a particular
Member.
1.21 OPCo CAPACITY SURPLUS FACTOR -- the weighted average for
the calendar year of (OPCo's MEMBER PRIMARY CAPACITY minus OPCo's
MEMBER PRIMARY CAPACITY RESERVATION) divided by OPCo's MEMBER
PRIMARY CAPACITY.
1.22 OVER-COMPLIANCE -- the amount by which a Member's SO2
EMISSIONS are less than its EPA-AWARDED ALLOWANCES for the current
year; provided, however, that in determining OPCo's OVER-
COMPLIANCE, its emissions shall be deemed to include, in lieu of
actual emissions from the Gavin Plant, 50% of GAVIN UNCONTROLLED
EMISSIONS, and its allowances shall be deemed to include, in lieu
of actual GAVIN EPA-AWARDED ALLOWANCES, only 50% of GAVIN EPA-
AWARDED ALLOWANCES.
1.23 POOL -- electric energy delivered by one Member, from its
MEMBER PRIMARY CAPACITY, to another Member shall be considered to
be energy delivered to the POOL by the former Member and delivered
from the POOL by the latter Member.
1.24 POWER SALES TO FOREIGN COMPANIES -- sales of electric
power and energy to Foreign Companies, made by a Member on behalf
of the System, where the revenue and cost of such sales are
allocated to the Members in proportion to their respective MEMBER
LOAD RATIOS.
1.25 PRIMARY AND ECONOMY ENERGY RECEIPT FACTOR -- the ratio of
PRIMARY ENERGY and ECONOMY ENERGY receipts by a receiving Member
from a DELIVERING MEMBER to the total sales of PRIMARY ENERGY and
ECONOMY ENERGY by the DELIVERING MEMBER.
1.26 PRIMARY AND ECONOMY ENERGY SUPPLY FACTOR -- the sum of
the Member's PRIMARY ENERGY and ECONOMY ENERGY deliveries divided
by the MEMBER'S GENERATION.
1.27 PRIMARY ENERGY -- electric energy delivered to the POOL
from the MEMBER PRIMARY CAPACITY of a particular Member to meet
another Member's deficiency in capacity.
1.28 RECEIVING MEMBER -- a Member which buys PRIMARY ENERGY
and/or ECONOMY ENERGY from the POOL.
1.29 SO2 EMISSIONS -- the total of the Member's SO2 EMISSIONS
from the MEMBER'S AFFECTED UNITS.
1.30 SURPLUS ALLOWANCES -- the excess of a Member's current
year EPA-AWARDED ALLOWANCES, plus allowances transferred to the
Member pursuant to Sections 4.1, 4.2, 4.3 and 4.4 of this
Agreement, over the Member's annual SO2 EMISSIONS and its MLR share
of the SYSTEM ALLOWANCE BANK.
1.31 SYSTEM ALLOWANCE BANK -- the sum of all the Members'
allowances in excess of all the Members' SO2 emissions.
1.32 SYSTEM COST OF COMPLIANCE -- for calendar year 1995 is
$115.43/ton of SO2. For each subsequent year, the SYSTEM COST OF
COMPLIANCE shall be $115.43/ton of SO2 escalated annually at a rate
of 10.56%.
1.33 SYSTEM PRIMARY CAPACITY -- the sum of the MEMBER PRIMARY
CAPACITY of all the Members.
1.34 UNDER-COMPLIANCE -- the amount by which a Member's SO2
EMISSIONS are greater than its EPA-AWARDED ALLOWANCES for the
current year; provided, however, that in determining OPCo's UNDER-
COMPLIANCE, its emissions shall be deemed to include, in lieu of
actual emissions from the Gavin Plant, 50% of GAVIN UNCONTROLLED
EMISSIONS, and its allowances shall be deemed to include, in lieu
of actual GAVIN EPA-AWARDED ALLOWANCES, only 50% of GAVIN EPA-
AWARDED ALLOWANCES.
ARTICLE 2 - EMISSION ALLOWANCE MANAGEMENT
2.1 In determining the transfer of costs and benefits related
to emission allowances among Members, settlements for the following
transactions will be governed by this Agreement: 1) an annual
reallocation of Gavin allowances, described in Section 4.1, 2) an
annual cash settlement for the transfer of allowances associated
with PRIMARY ENERGY and ECONOMY ENERGY, described in Section 4.2,
3) a monthly cash settlement for allowances consumed for POWER
SALES TO FOREIGN COMPANIES, described in Section 4.3, 4) sales and
purchases of allowances to/from non-affiliated parties, described
in Section 4.4, and 5) an annual transfer of allowances for current
period compliance and allocation of the SYSTEM ALLOWANCE BANK,
described in Section 4.5.
2.2 Agent shall have the authority to make any and all
decisions relating to the use, management, purchase, sale and
transfer of emission allowances. Except as provided in this
Agreement or any superseding agreement, no other payment or
compensation shall be made between or among the Members with
respect to any such use, management, purchase, sale or transfer.
ARTICLE 3 - AGENT'S RESPONSIBILITIES
3.1 For the purpose of carrying out the provisions of this
Agreement, the Members hereby delegate to Agent, and Agent hereby
accepts, the responsibility of administration of this Agreement,
and in furtherance thereof Agent hereby agrees:
3.11 To render to each Member as promptly as possible
after the end of each month a statement setting forth the
settlements hereunder for such preceding calendar month, in
such detail and with such segregation as may be needed for
accounting, operating, or other proper purposes.
3.12 To carry out allowance transfer settlements under
this Agreement. Settlement for the Gavin Allowance
Reallocation shall be recorded annually in December for each
calendar year.
3.13 To carry out cash settlements under this Agreement
through an account (hereby designated and hereinafter called
the SYSTEM ALLOWANCE ACCOUNT) to be administered by Agent.
Payments to or from such account shall be made to or by Agent
as clearing agent of the account. The total amount of the
payments made by the Members to the SYSTEM ALLOWANCE ACCOUNT
each month shall be equal to the total amount of the payments
made from the SYSTEM ALLOWANCE ACCOUNT for the same period.
3.131 Monthly settlements by the Members shall be
determined for Allowances Consumed for Power Sales to
Foreign Companies.
3.132 Annual settlements by the Members shall be
determined in December of each calendar year for
Allowance Transfers for Primary and Economy Energy
Transactions.
3.133 Settlements by the Members shall be
determined for allowances sold and purchased to/from non-
affiliated parties as they occur.
3.134 Annual settlements by the Members shall be
determined in December of each calendar year for the
Transfer of Allowances for Current Period Compliance and
Allocation of the System Allowance Bank.
ARTICLE 4 - SETTLEMENTS
4.1 GAVIN ALLOWANCE REALLOCATION - In December of 1995 and
each subsequent calendar year, the allowance inventory accounts of
the Members will be adjusted to recognize the Gavin Allowance
Reallocation. The number of Gavin allowances available for
reallocation is determined by multiplying the OPCo CAPACITY SURPLUS
FACTOR by the sum of (i) GAVIN BONUS ALLOWANCES and (ii) 50% of the
sum of the GAVIN EPA-AWARDED ALLOWANCES and the GAVIN SCRUBBER SO2
REDUCTION. The Gavin allowances available for reallocation shall
be transferred, at zero cost, to the Members having a MEMBER
PRIMARY CAPACITY DEFICIT. Each deficit Member's share of the Gavin
Allowance Reallocation is determined by multiplying the Gavin
Allowances to Reallocate by the MEMBER'S CAPACITY DEFICIT FACTOR.
4.2 ALLOWANCE TRANSFERS ASSOCIATED WITH PRIMARY AND ECONOMY
ENERGY TRANSACTIONS - In December of each year, the DELIVERING
MEMBERS shall transfer allowances to or receive allowances from the
RECEIVING MEMBERS, according to this Section. A DELIVERING MEMBER
shall be transferred allowances from a RECEIVING MEMBER if the
DELIVERING MEMBER is in an UNDER-COMPLIANCE position. A DELIVERING
MEMBER shall transfer allowances to a RECEIVING MEMBER if the
DELIVERING MEMBER is in an OVER-COMPLIANCE position. Members
supplying allowances shall be compensated by the Members receiving
allowances based on the supplying Member's average allowance
inventory cost. For the year, a Member may be both a DELIVERING
MEMBER and a RECEIVING MEMBER.
4.21 In December of each year, the Member's annual OVER-
COMPLIANCE or UNDER-COMPLIANCE shall be determined.
4.22 The PRIMARY AND ECONOMY ENERGY SUPPLY FACTOR of
each DELIVERING MEMBER shall be multiplied by that Member's
over/(under) compliance to determine its incremental OVER-
COMPLIANCE or incremental UNDER-COMPLIANCE position. The
incremental over/(under) compliance position represents the
total number of allowances to be transferred from or received
by the DELIVERING MEMBER.
4.23 If the DELIVERING MEMBER is in an UNDER-COMPLIANCE
position, the number of allowances to be transferred from the
RECEIVING MEMBER is calculated by multiplying the DELIVERING
MEMBER'S incremental UNDER-COMPLIANCE by the respective
PRIMARY AND ECONOMY ENERGY RECEIPT FACTOR. If the DELIVERING
MEMBER is in an OVER-COMPLIANCE position, the number of
allowances to be transferred to the RECEIVING MEMBERS is
calculated by multiplying the incremental OVER-COMPLIANCE of
the DELIVERING MEMBER by the respective PRIMARY AND ECONOMY
ENERGY RECEIPT FACTORS.
4.24 The net allowances transferred from the supplying
Member during the year are priced at their individual weighted
average inventory cost computed at the end of December. The
net allowances transferred to the receiving Members shall be
based on the weighted average inventory cost of all Members
supplying allowances. The average inventory cost of a
supplying Member is computed by taking the total book cost of
allowances available for transfer divided by the number of
allowances available for transfer at the end of December.
4.3 ALLOWANCES CONSUMED FOR POWER SALES TO FOREIGN COMPANIES
- - When allowances are consumed for power sales to foreign
companies, the customer has the option of reimbursing the supplying
company with allowances in kind, or paying cash for the allowances
at the current market rate. If the customer reimburses in kind,
the allowances shall be retained by the supplying Member (Member
company that generated the energy and consumed the allowances); and
a cash settlement shall be made to each Member based on its MLR-
share of the current value of the allowances received. If cash is
received, in lieu of allowances, it shall be shared by each member
based on its current MLR. The supplying Member's consumed cost of
allowances for sale to foreign companies shall be allocated to each
Member based on its current MLR. The method for determining the
allowances consumed in generating the energy for POWER SALES TO
FOREIGN COMPANIES is set forth in Appendix E to this Agreement.
4.4 ALLOWANCE TRANSACTIONS WITH NON-AFFILIATED PARTIES -
Participation in the allowance market could involve either the sale
or purchase of allowances to or from non-affiliated parties.
4.41 SALE OF ALLOWANCES - Except as provided in Section
4.43, in the event allowances are sold to non-affiliated
parties, each Member shall contribute its MLR share of the
total quantity sold. To the extent a Member cannot provide
its MLR share due to a shortfall, that Member shall purchase
an amount of allowances necessary to cover the shortfall from
other Members having a surplus, at the System Cost of
Compliance. Each Member shall receive its MLR share of the
total proceeds.
4.42 PURCHASE OF ALLOWANCES - In the event allowances
are purchased from non-affiliated parties, each Member shall
take ownership of its MLR share of the total quantity
purchased and pay its MLR share of the total cost.
4.43 SALE OF WITHHELD ALLOWANCES AT EPA AUCTIONS - The
proceeds from sales of allowances withheld by the EPA,
pursuant to Section 416 of Title IV of the 1990 Amendments,
shall be retained by the Member owning the generating units
from which the allowances were withheld.
4.44 NET PROCEEDS AND COSTS FROM PREVIOUS ALLOWANCE
TRANSACTIONS - The net proceeds from sales of allowances to
non-affiliated parties which occurred prior to the effective
date of Modification No. 1 to this Agreement, the cost of
allowances purchased from non-affiliated parties which
occurred prior to the effective date of Modification No. 1 to
this Agreement and all carrying charges accrued on such
proceeds and costs, shall be shared by each Member based on
its MLR.
4.5 TRANSFERS OF ALLOWANCES FOR CURRENT PERIOD COMPLIANCE AND
ALLOCATION OF THE SYSTEM ALLOWANCE BANK - At the end of December of
each calendar year, each Member shall own a share of the SYSTEM
ALLOWANCE BANK, based on its current MEMBER LOAD RATIO. A Member
whose annual SO2 EMISSIONS exceed its available allowance
inventory, after intercompany settlements described in Section 4.1,
4.2, 4.3 and 4.4 of this Agreement, will purchase allowances to
eliminate its shortfall in that calendar year and to provide for
its MLR share of the SYSTEM ALLOWANCE BANK. These purchases will
be made from Members having SURPLUS ALLOWANCES and will be priced
at the SYSTEM COST OF COMPLIANCE. If more than one Member has
SURPLUS ALLOWANCES, the buying Member will purchase a proportionate
share from the surplus Members.
ARTICLE 5 - BILLINGS AND PAYMENTS
5.1 All bills for amounts owing hereunder shall be due and
payable on the fifteenth day of the month next following the month
to which a settlement has been rendered, or on the tenth day
following the receipt of the bill, whichever date is later.
Interest on unpaid amounts shall accrue daily at the prime interest
rate per annum in effect on the due date at Citibank, plus 2% per
annum, from the due date until the date upon which payment is made.
Unless otherwise agreed upon, the calendar month shall be the
standard period for the purpose of settlements under this
Agreement. If bills cannot be accurately determined at any time,
they shall be rendered on an estimated basis and subsequently
adjusted to conform to the terms of this Agreement.
ARTICLE 6 - TAXES
6.1 If at any time during the duration of this Agreement
there should be levied and/or assessed by any governmental
authority against any Member any tax related to the receipt of
settlements calculated pursuant to Article 5 of this Agreement
(including, but not limited to sales, excise, etc.), the tax
expense incurred by such Member that would not have been incurred
were the allowance settlements hereunder not being made, such
Member shall be entitled to reimbursement of the tax expense from
the Member generating the tax expense.
ARTICLE 7 - MODIFICATIONS
7.1 Any Member, by written notice given to the other Members
and Agent, may call for a reconsideration of the terms and
conditions herein provided. If such reconsideration is called for,
the Members shall take into account any changed conditions, any
results from the application of said terms and conditions, and any
other facts that might cause said terms and conditions to result in
an inequitable sharing of costs and benefits under this Agreement.
Any modification in terms and conditions agreed to by the Members
shall be subject to appropriate regulatory approval and become
effective the first day of the month following regulatory
authorization.
ARTICLE 8 - EFFECTIVE DATE AND TERMS OF THIS AGREEMENT
8.1 This Agreement shall become effective and shall become a
binding obligation of the Parties on January 1, 1995, or such other
effective date determined by FERC.
8.2 This Agreement shall continue in effect from the
effective date until the effective date of any subsequent
agreement.
ARTICLE 9 - REGULATORY AUTHORITIES
9.1 The Members recognize that this Agreement, and any tariff
or rate schedule which shall embody or supersede this Agreement or
any part thereof, are in certain respects subject to the
jurisdiction of the FERC under the Federal Power Act, and are also
subject to such lawful action as any regulatory authority having
jurisdiction shall hereinafter take with respect thereto. The
performance of any obligation of the Members shall be subject to
the receipt of such authorizations, approvals or actions of
regulatory authorities having jurisdiction as shall be required by
law.
9.2 It is expressly understood that the Members shall be
entitled, at any time unilaterally, to make application to the FERC
for a change in the rates, charges, classification of service, or
any rule, regulation or contract relating thereto, or to make any
change in or supersede in whole or in part any provision of the
this Agreement, under Section 205 of the Federal Power Act and
pursuant to the FERC's Rules and Regulations promulgated
thereunder.
ARTICLE 10 - ASSIGNMENT
10.1 This Agreement shall accrue to the benefit of and be
binding upon the successors and assigns of the respective parties.
IN WITNESS WHEREOF, the parties hereto have caused the
Agreement to be executed in their respective corporate names and on
their behalf by their proper officers thereunto duly authorized as
of the day and year first above written.
APPALACHIAN POWER COMPANY
By: (Signature on Original Document)
--------------------------------
COLUMBUS SOUTHERN POWER COMPANY
OHIO POWER COMPANY
By: (Signature on Original Document)
--------------------------------
INDIANA MICHIGAN POWER COMPANY
By: (Signature on Original Document)
--------------------------------
KENTUCKY POWER COMPANY
By: (Signature on Original Document)
--------------------------------
AMERICAN ELECTRIC POWER SERVICE
CORPORATION
By: (Signature on Original Document)
--------------------------------
WHEREAS, APPALACHIAN POWER COMPANY (APCO), a Virginia
corporation, COLUMBUS SOUTHERN POWER COMPANY (CSP), an Ohio
corporation, INDIANA MICHIGAN POWER COMPANY (I&M), an Indiana
corporation, KENTUCKY POWER COMPANY (KPCO), a Kentucky corporation,
OHIO POWER COMPANY (OPCO), an Ohio corporation, said companies
(herein sometimes called 'Members' when referred to collectively
and 'Member' when referred to individually) being affiliated
companies of the integrated public utility electric system known as
the American Electric Power System (AEP), and AMERICAN ELECTRIC
POWER SERVICE CORPORATION (Agent), a New York corporation, being a
service company engaged solely in the business of furnishing
essential services to the aforesaid companies and the other
affiliated companies, all of whom are currently doing business as
American Electric Power, desire to establish a mechanism for the
allocation of emission allowance costs and proceeds associated with
purchases and sales with non-affiliated entities; and
WHEREAS, the Members desire to amend the AEP System Interim
Allowance Agreement dated July 28, 1994 to reflect this mechanism
and to effect certain other changes to the Agreement; and
WHEREAS, except as changed by amendments, the AEP System
Interim Allowance Agreement remains in full force and effect.
NOW THEREFORE, the Members adopt the document attached hereto
showing the proposed amendments to the AEP System Interim Allowance
Agreement in a form in which deletions appear as struck-through
text and additions appear as shaded text, as "Modification No. 1 to
the AEP System Interim Allowance Agreement By and Among Appalachian
Power Company, Columbus Southern Power Company, Indiana Michigan
Power Company, Kentucky Power Company, Ohio Power Company and With
American Electric Power Service Corporation As Agent."
Agreed to this ______ day of June, 1996.
By: /s/ William J. Lhota
---------------------------------
William J. Lhota
Title: President and Chief Operating Officer of
Appalachian Power Company, Columbus
Southern Power Company, Indiana Michigan
Power Company, Kentucky Power Company,
and Ohio Power Company; and Executive
Vice President of American Electric Power
Service Corporation, collectively doing
business as American Electric Power
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER
1 Riverside Plaza
Columbus, Ohio 43215-2373
CONTENTS
Selected Consolidated Financial Data
Management's Discussion and Analysis of Financial Condition
and Results of Operations
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings
Consolidated Statements of Cash Flows
Consolidated Balance Sheets
Notes to Consolidated Financial Statements
Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries
Schedule of Consolidated Long-term Debt of Subsidiaries
Management's Responsibility
Independent Auditors' Report
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
<CAPTION>
Year Ended December 31, 1996 1995 1994 1993 1992
<S> <C> <C> <C> <C> <C>
INCOME STATEMENTS DATA
(in millions):
Operating Revenues $5,849 $5,670 $5,505 $5,269 $5,045
Operating Income 1,008 965 932 929 883
Net Income 587 530 500 354 468
December 31, 1996 1995 1994 1993 1992
BALANCE SHEETS DATA
(in millions):
Electric Utility Plant $18,970 $18,496 $18,175 $17,712 $17,509
Accumulated Depreciation
and Amortization 7,550 7,111 6,827 6,612 6,281
Net Electric Utility Plant $11,420 $11,385 $11,348 $11,100 $11,228
Total Assets $15,886 $15,902 $15,739 $15,362 $14,217
Common Shareholders' Equity 4,545 4,340 4,229 4,151 4,245
Cumulative Preferred Stocks
of Subsidiaries:
Not Subject to Mandatory
Redemption 90 148 233 268 535
Subject to Mandatory
Redemption* 510 523 590 501 234
Long-term Debt* 4,884 5,057 4,980 4,995 5,311
Obligations Under Capital
Leases* 414 405 400 284 300
*Including portion due within one year
Year Ended December 31, 1996 1995 1994 1993 1992
COMMON STOCK DATA:
Earnings per Share $3.14 $2.85 $2.71 $1.92 $2.54
Average Number of Shares
Outstanding (in thousands) 187,321 185,847 184,666 184,535 184,535
Market Price Range: High $44-3/4 $40-5/8 $37-3/8 $40-3/8 $35-1/4
Low 38-5/8 31-1/4 27-1/4 32 30-3/8
Year-end Market Price 41-1/8 40-1/2 32-7/8 37-1/8 33-1/8
Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio 76.5% 84.1% 88.6% 125.2% 94.6%
Book Value per Share $24.15 $23.25 $22.83 $22.50 $23.01
</TABLE>
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Business Outlook
With the issuance of two Federal Energy Regulatory Commission (FERC)
orders and the commencement of planning for retail competition at the state
level, we are in a better position to identify and develop strategies for
addressing the issues that face American Electric Power (AEP) and our
changing industry. We recognize that the conventional ways of maintaining
and enhancing shareholder value are becoming less effective as the industry
moves towards greater competition in the generation and sale of
electricity. The industry's transition to competition and customer choice
and the ability to fully recover costs are probably the most significant
factors affecting AEP's future profitability.
Although AEP has the financial strength, geographic reach, location and
cost structure to be an able competitor, no assurance can be given that AEP
can maintain this position in the future. However, we intend to make every
effort to maintain and strengthen our competitive position. We see a link
between a smooth transition to a competitive marketplace and the
maintaining and enhancing of shareholder value.
The new FERC orders facilitate increased competition in both the
generation and sale of bulk power to wholesale customers. They provide,
among other things, for open access to transmission facilities. AEP's
support of the FERC's open access transmission rule is evidenced by our
being among the first to file a comparability tariff, offering access to
our transmission grid at 143 interconnections to all parties under the same
terms and conditions available to AEP. This has provided AEP with greater
opportunities for transmission service revenues.
Although customer choice proposals and discussions are under way in the
states in which we operate, it is difficult to predict their result and the
timing of any resultant changes. We are actively involved in discussions
on the state and federal level regarding how best to transition to
competition in order to represent the best interests of our customers,
shareholders and employees. We favor a transition because we believe that
AEP will in the long-term fare better in a competitive market than under
continued regulation.
As the electric energy market evolves from cost-of-service ratemaking to
market-based pricing, many complex issues must be resolved, including the
recovery of stranded costs. While the new FERC orders provide, under
certain conditions, for recovery of stranded costs at the wholesale level,
the issue of stranded cost remains open at the much larger state retail
level.
Stranded Costs
Stranded costs occur when a customer switches to a new supplier for its
electric energy needs or when a component of the business, for example
generation, is no longer subject to cost-based regulation, creating the
issue of who pays for plant investment, purchased power or fuel contracts
both non-affiliated and affiliated, inventories, construction work in
progress, nuclear decommissioning, plant removal and shutdown costs,
previously deferred costs (regulatory assets) and other investments and
commitments that are no longer needed, economic or recoverable in a
competitive market. The amount of any stranded costs AEP may experience
depends on the timing of and the extent to which direct competition is
introduced to our business and the then-existing market price of energy.
Under the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation,"
assets (deferred expenses) and liabilities (deferred revenues) are included
in the consolidated financial statements in accordance with regulatory
actions to match expenses and revenues in cost-based rates. In the event a
portion of the business no longer met the requirements of SFAS 71, net
regulatory assets would have to be written off for that portion of the
business. Among other requirements SFAS 71 requires that the rates charged
customers be cost based.
Our generation business is still cost-based regulated and should remain
so for at least three to five years as the industry transitions to full
competition. Although the recent FERC orders provide for competition in
the firm wholesale market, that market is a relatively small part of our
business and many of our firm wholesale sales are still under
cost-of-service contracts. We believe that enabling state legislation should
provide for a sufficient transition period to allow for the recovery of any
generation-related stranded costs and we are dedicating ourselves to work
with regulators, customers and legislators to accomplish both an orderly
transition and a reasonable and fair disposition of the stranded cost
issue.
We favor the recovery of stranded costs during a transition period in
which rates would be fixed or frozen and electric utilities would take
steps to achieve cost savings which would be used to reduce or eliminate
stranded costs. However, if electric utilities were to no longer be
cost-based regulated and it were not possible to recover stranded costs, the
results of operations and financial condition of AEP and other electric
utilities would be adversely affected.
Since state commissions have jurisdiction over the sale and distribution
of electricity to retail customers, we believe that state legislation and
regulation should shape the future competitive market for electricity while
federal legislation should seek to ensure reciprocity among the states and
a level playing field for all power suppliers. Presently states with
higher cost power, like California and Massachusetts, are aggressively
pursuing deregulation. The states AEP operates in, however, are generally
addressing the call for customer choice more cautiously and the transition
to competition is expected to evolve at an uneven pace across the states.
Restructuring/Functional Unbundling
In 1996 we took some major steps to maintain and enhance AEP's
competitive strength and made progress towards our long-term goal of
becoming the world's premier supplier of energy and related services. We
restructured our management and operations to allow us to comply with the
new FERC orders by separating our generation and energy sales operations
from our energy transmission delivery operations and to address increasing
competition among electric suppliers through distinct functional business
units. This has achieved and should continue to achieve staffing,
managerial and operating efficiencies. The generation and marketing
business units expect to eventually compete in an open market for
customers. Our energy delivery business will remain regulated and may
ultimately be subject to some form of incentive or performance-based
ratemaking while Corporate Development and Marketing will be working to
cultivate new but related non-regulated business opportunities.
Corporate Branding and Positioning
We are enhancing our marketing and customer service efforts with programs
like the Key Accounts Program which strives to build strong partnerships
with key customers in order to build customer loyalty. In 1996 AEP also
launched a series of new television commercials as part of a branding
campaign to inform our customers that we will be operating under the name
American Electric Power and that we are AEP: America's Energy Partner. The
commercials are intended to position AEP as more than just a supplier of
electricity. As we enter an increasingly competitive energy market we want
to be the energy and energy services provider of choice.
New Business Opportunities
In the non-rate-regulated environment, AEP offers energy consulting and
project management services both domestically and internationally and
contracts with other public utilities and government agencies for the
licensing of intellectual property and the delivery of energy services. In
1996 an AEP subsidiary and two Chinese companies formed a joint venture
company to finance and build a 250-megawatt electric generating facility in
China. AEP's share of the total cost of the facility is approximately $120
million and the project is expected to be operational in 1999.
On February 24, 1997 AEP and Public Service Company of Colorado with
equal interests in a joint venture announced a cash tender offer for
Yorkshire Electricity Group plc in the United Kingdom. The joint venture
proposes to pay $2.4 billion to acquire all of the stock of Yorkshire
Electricity. AEP's equity invest-ment, estimated to be $360 million, will
be made through its subsidiary AEP Resources Inc., initially using cash
borrowed under a revolving credit agreement. We consider the China
investment and Yorkshire tender offer as important steps in our long-term
goal to become the premier provider of energy and energy services
worldwide.
In addition to pursuing foreign power generation, transmission and
distribution investments we formed new subsidiaries in 1996 to explore
other new complementary business opportunities including AEP
Communications, Inc. which was formed to provide data transmission and
related telecommunications products and services. In January 1997 AEP
Communications, Inc. entered into an agreement with Sprint Communications,
Inc. to construct jointly a 150 mile fiber optic line between Charleston,
West Virginia and Roanoke, Virginia. Another new subsidiary AEP Power
Marketing is presently seeking approval to market and broker power outside
of our traditional service territory. Plans are also in place to commence
gas marketing. We are pursuing non-regulated related business
opportunities because we believe they offer the opportunity to earn
enhanced returns as compared with our traditional regulated business.
However, we recognize that these opportunities are generally riskier.
Investments in new business opportunities may be made after management
carefully assesses the risks versus the potential for enhanced shareholder
value.
Cost Containment
In 1996 we continued our efforts to reduce costs in order to maintain our
competitiveness. Reviews of our major processes led to decisions to
consolidate the management and operations of internal service functions
performed at multiple locations. Among the functions being consolidated
are fossil generation plant maintenance, nuclear operations support staff,
system operations, accounting and load research. A study of the Company's
procurement and supply chain operations led to cost reductions through
better inventory management, just-in-time delivery and the increased use of
electronic purchasing. Also in 1996 we completed the installation of an
activity based management budgeting system throughout the system. This
tool will enable managers to better analyze work and control costs. While
staff reductions and cost savings are being achieved in these and other
areas, expenses for new marketing and customer services and modern
efficient management information systems are being increased to prepare for
competition. These expenditures for the future should produce further
improvements and efficiencies, enabling AEP to maintain its position as a
low-cost producer.
Fuel Costs
Coal is 70% of the production cost of electricity for AEP. Although our
coal costs per unit of electricity (per Kwh) have declined by one-half in
constant dollars in the last 10 years, we recognize that we must continue
to manage our coal costs to continue to maintain our competitive position.
Approximately 15% of the coal we burn is supplied by affiliated mines; the
remainder is acquired under long-term contracts and in the spot market. As
long-term contracts expire we are negotiating with non-affiliated suppliers
to lower purchased coal costs. Efforts also continued in 1996 to reduce
the cost of affiliated coal. We intend to continue to prudently supplement
our long-term coal supplies with spot market purchases as long as favorable
spot market prices exist.
In recent years we have agreed in our Ohio jurisdiction to certain
limitations on the recovery of affiliated coal costs. Our analysis shows
that we should be able to recover over the term of the agreement (through
2009) the Ohio jurisdictional portion of the current and deferred costs of
our affiliated mining operations including future mine closure costs.
Management intends to seek recovery of its non-Ohio jurisdictional portion
of the investment in and the liabilities and closing costs of our
affiliated mines estimated at $180 million after tax. However, should it
become apparent that the costs will not be recoverable from Ohio and/or
non-Ohio jurisdictional customers, the mines may have to be closed and
future earnings and possibly financial condition adversely affected. In
addition compliance with Phase II requirements of the Clean Air Act, which
become effective in January 2000, could also cause the mining operations to
close. Unless the cost of any mine closure is recovered either in
regulated rates or as a stranded cost in a transition to competition,
future earnings and possibly financial condition could be adversely
affected.
Nuclear Costs
Significant efforts have been made to enhance our competitiveness in
nuclear power generation and to improve our nuclear organizational
efficiency. Net generation in 1996 for the Company's only nuclear plant,
the two-unit Donald C. Cook Nuclear Plant, located on the shores of Lake
Michigan, was 16,396 gigawatts, the highest in the plant's 20-year history.
The generation record was set in part due to Unit 2's best continuous run
in its history, 226 days, reached in December 1996. Refueling costs and
related outage time have been reduced. We also reduced nuclear staff
support costs in 1996 by relocating our Columbus-based nuclear management
and support staff to Michigan to consolidate it with the plant staff.
It is difficult to reduce nuclear generation costs since certain major
cost components are impacted by federal laws and Nuclear Regulatory
Commission (NRC) regulations. The Nuclear Waste Policy Act of 1982
established federal responsibility for the permanent off-site disposal of
spent nuclear fuel and high-level radioactive waste. By law we participate
in the Department of Energy's (DOE's) Spent Nuclear Fuel (SNF) disposal
program which is described in Note 4 of the Notes to Consolidated Financial
Statements. Since 1983 our customers have paid $254 million for the
disposal of spent nuclear fuel consumed at the Cook Nuclear Plant. Under
the provisions of the Nuclear Waste Policy Act, collections from customers
are to provide the DOE with money to build a repository for spent fuel. To
date the federal government has not made sufficient progress towards a
permanent repository or otherwise assuming responsibility for SNF. As long
as there is a delay in the storage repository for SNF, the cost of both
temporary and permanent storage will continue to increase.
The cost to decommission the Cook Nuclear Plant is also affected by NRC
regulations and the DOE's SNF disposal program. Studies completed in 1994
estimate the cost to decommission the Cook Nuclear Plant and dispose of
low-level nuclear waste accumulation to range from $634 million to $988
million in 1993 dollars. This estimate could escalate due to uncertainty
in the DOE's SNF disposal program and the length of time that SNF may need
to be stored at the plant site delaying decommissioning. Presently we are
recovering the estimated cost of decommissioning the Cook Nuclear Plant
over its remaining life. However, AEP's future results of operations and
possibly its financial condition could be adversely affected if the cost of
spent nuclear fuel disposal and decommissioning continues to increase and
cannot be recovered in regulated rates or as a stranded cost in a future
competitive market.
Environmental Concerns
We take great pride in our efforts to economically produce and deliver
electricity while minimizing the impact on the environment. AEP has spent
millions of dollars to equip our facilities with the latest economical
clean air and water technologies and to research possible new technologies.
We are also proud of our award winning efforts to reclaim our mining
properties. We intend to continue to take a leadership role to foster
economically prudent efforts to protect and preserve the environment.
Hazardous Material
By-products from the generation of electricity include materials such as
ash, slag, sludge, low-level radioactive waste and spent nuclear fuel.
Coal combustion by-products, which constitute the overwhelming percentage
of these materials, are typically disposed of or treated in captive
disposal facilities or are beneficially utilized. In addition, our
generating plants and transmission and distribution facilities have used
asbestos, polychlorinated biphenyls (PCBs) and other hazardous and
non-hazardous materials. We are currently incurring costs to safely dispose
of such substances, and additional costs could be incurred to comply with new
laws and regulations if enacted.
The Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA or Superfund) addresses clean-up of hazardous substances at
disposal sites and authorized the United States Environmental Protection
Agency (Federal EPA) to administer the clean-up programs. As of year-end
1996, we are currently involved in litigation with respect to five sites
being overseen by the Federal EPA and have been named by the Federal EPA as
"Potentially Responsible Parties" (PRPs) for six other sites. There are
eight additional sites for which AEP companies have received information
requests which could lead to PRP designation. Also, an AEP subsidiary has
received an information request with respect to one site administered by
state authorities. Our liability has been resolved for a number of sites
with no significant effect on results of operations. In those instances
where we have been named a PRP or defendant, our disposal or recycling
activity was in accordance with the then-applicable laws and regulations.
Unfortunately, CERCLA does not recognize compliance as a defense, but
imposes strict liability on parties who fall within its broad statutory
categories.
While the potential liability for each Superfund site must be evaluated
separately, several general statements can be made regarding such potential
liability. The disposal at a particular site by AEP is often
unsubstantiated; the quantity of material we disposed of at a site was
generally small; and the nature of the material we generally disposed of
was non-hazardous. Typically, we are one of many parties named as PRPs for
a site and, although liability is joint and several, generally some of the
other parties are financially sound enterprises. Therefore, our present
estimates do not anticipate material cleanup costs for identified sites for
which we have been declared PRPs. 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 from customers.
Federal EPA Actions
Federal EPA is required by the Clean Air Act Amendments of 1990 (CAAA) to
issue rules to implement the law. In December 1996 Federal EPA issued
final rules governing nitrogen oxide emissions that must be met after
January 1, 2000 (Phase II of the CAAA). The final rules will require
substantial reductions in nitrogen oxide emissions from certain types of
power plant boilers including those in AEP's power plants. In December
1996 a group of utilities including AEP operating companies filed a
petition for review of the rules in a U.S. Court of Appeals and requested
expedited consideration of the appeal. The cost to comply with the
emission reductions required by the final rules is expected to be
substantial and could have a material adverse impact on results of
operations and possibly financial condition if these costs are not
recovered from customers.
Federal EPA is considering proposals to revise the existing ambient air
quality standard for ozone and to establish a new ambient air quality
standard for fine particulate matter. The rules being considered could
result in requirements for reductions of nitrogen oxides and sulfur dioxide
emitted from coal fired power plants and could have a significant impact on
AEP's operations. The proposals being considered are of particular concern
because they do not appear to have a sound scientific basis. The cost of
complying with any new emission reduction requirements imposed as a result
of the adoption of revised ambient air quality standards can not be
precisely determined but could be substantial. If Federal EPA ultimately
promulgates stricter ambient air quality standards, they could have a
material adverse impact on results of operations and possibly financial
condition if these costs are not recovered from customers.
Results of Operations
1996 was a good year for AEP with earnings the best since 1989 and total
shareholder return placing us among the best in our industry. We continued
to be well within our goal of being in the upper quartile of the companies
in the Standard & Poor's electric utility index, based on cumulative
three-year return.
Earnings Increase
In 1996 earnings increased 11% to $587 million or $3.14 per share from
$530 million or $2.85 per share in 1995. The increase is mainly
attributable to increased sales of energy and services and reduced interest
charges and preferred stock dividends. Sales increased due to increased
transmission and other services provided to power marketers and utilities
and increased energy sales to non-affiliated utilities and industrial
customers. The reduction in interest and preferred stock dividends
resulted from the Company's refinancing program. Also contributing to the
improvement in earnings were severance pay charges recorded in 1995 in
connection with realigning operations and management and gains recorded in
1996 from emission allowance transactions.
Earnings increased 6% in 1995 to $530 million or $2.85 per share from
$500 million or $2.71 per share in 1994. The primary reason for the
earnings improvement was increased retail energy sales reflecting increased
usage and growth in the number of customers. Unseasonably warm weather in
the summer of 1995 and colder weather in the fourth quarter of 1995, were
the primary factors accounting for the increased usage. The positive
earnings impact of the increased sales was partly offset by the unfavorable
effect of severance pay.
Revenues And Sales Increase
Operating revenues increased 3% in 1996 and 1995. Increased wholesale
energy sales and transmission and coal conversion service revenues were the
primary reasons for the increase in 1996 revenues. In 1995 the revenue
increase resulted primarily from an increase in retail customers' energy
usage, growth in the number of retail customers and the effects of rate
increases.
The change in revenues can be analyzed as follows:
Increase (Decrease)
From Previous Year
(Revenues in Millions) 1996 1995
Amount % Amount %
Retail:
Price Variance $ (42.9) $ 46.5
Volume Variance 63.7 173.0
Fuel Cost Recoveries 15.0 (22.9)
35.8 0.7 196.6 4.2
Wholesale:
Price Variance (202.0) (39.3)
Volume Variance 317.3 10.8
Fuel Cost Recoveries (3.6) (4.6)
111.7 16.4 (33.1) (4.6)
Other Operating Revenues 31.4 2.2
Total $ 178.9 3.2 $165.7 3.0
In 1996 retail revenues increased slightly due to growth in the number of
customers and the addition of a major new industrial customer in December
1995. Revenues from sales to residential customers, the most weather-sensitive
customer class, were flat, increasing less than one percent, as
the effect of cold winter weather in early 1996 was offset by mild summer
and December temperatures. Revenues from commercial and industrial
customers increased 1% reflecting growth in the number of customers.
Wholesale revenues increased 16% in 1996 reflecting a 46% increase in
wholesale sales attributable largely to new wholesale transactions with
power marketers and other utilities. As the wholesale energy market
evolves into a competitive marketplace the Company intends to take
advantage of new ways to market and price electricity and related services.
During 1996 the Company provided coal conversion services resulting in 6.8
billion kilowatthours of electricity generated for power marketers and
certain other utilities under a new FERC-approved interruptible, contingent
sales tariff. As a result of these new sales, the average price per
kilowatthour was significantly less in 1996 than in 1995. Also
contributing to the increased wholesale sales was a new long-term contract
with an unaffiliated utility to supply 205 MW of energy for 15 years
beginning January 1, 1996.
An increased level of activity in the wholesale energy markets encouraged
by the 1996 issuance of FERC open access transmission rules and AEP's
aggressive efforts to provide flexible and competitively priced
transmission services led to an increase in transmission service revenues.
As a result transmission revenues, which are recorded in other operating
revenues, increased by approximately $24 million.
The increase in 1995 operating revenues resulted primarily from a 4%
increase in energy sales to retail customers due mainly to increased usage
and continued growth in the number of customers in all retail customer
classes. Energy sales to residential customers, the most weather-sensitive
customer class, rose more than 6% in 1995 mainly as a result of increased
weather related usage in the last half of the year. Sales to commercial
and industrial customers rose 5% and 2%, respectively, reflecting the
effects of weather and the expanding economy.
Although revenues from wholesale customers declined in 1995, wholesale
energy sales increased by more than 1% largely due to increased short-term
sales made on an hourly basis to unaffiliated utilities. This type of
short-term sale is typically made when the unaffiliated utility can
purchase energy at a lower cost than the cost at which that utility can
generate the energy or when the customer is short on generating capacity.
Such sales increase in periods of extreme weather. The increase in 1995
wholesale energy sales occurred during the last six months of the year when
the summer was unseasonably warm and fall temperatures were colder compared
with the prior year. While wholesale energy sales increased, wholesale
revenues declined in 1995 reflecting increasing price related competition.
The level of wholesale sales tends to fluctuate due to the highly
competitive nature of the short-term energy market and other factors, such
as unaffiliated generating plant availability, the weather and the economy.
The recently adopted FERC rules which introduce a greater degree of
competition into the wholesale energy market have had the effect of
increasing short-term wholesale sales and transmission service revenues.
The Company's sales and in turn its results of operations were impacted in
1996 and prior years by the quantities of energy and services sold in
wholesale transactions. Future results of operations will be affected by
the quantity and price of wholesale transactions which often depends on the
weather and power plant availability.
Operating Expenses Increase
Operating expenses increased 3% in 1996 and 1995. The primary items
accounting for the increase in 1996 were increased fuel costs, federal
income taxes and expenditures for marketing, information systems and other
items necessary to prepare for the transition to competition. In 1995
increased rent and related operating costs of the newly installed Gavin
Plant flue gas desulfurization systems (scrubbers) and expenses related to
severance pay charges were the main reasons for the increase in operating
expenses. Changes in the components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1996 1995
Amount % Amount %
Fuel and Purchased Power $ 61.2 3.8 $(119.7) (6.9)
Other Operation 25.9 2.2 181.3 18.1
Maintenance (39.0) (7.2) (2.4) (0.5)
Depreciation and Amortization 7.8 1.3 20.8 3.6
Taxes Other Than Federal
Income Taxes 9.4 1.9 (5.0) (1.0)
Federal Income Taxes 70.2 25.8 58.6 27.5
Total $135.5 2.9 $ 133.6 2.9
Fuel and purchased power expense increased in 1996 due to an increase in
generation to meet the increase in industrial and wholesale customer
demand. The effect of increased generation was partially offset by reduced
average fossil fuel costs resulting from increased usage of lower cost spot
market coal and lower cost nuclear fuel.
Although generation increased 3% in 1995, fuel and purchased power
expense declined as a result of a decrease in the average cost of fossil
fuel resulting from reduced coal prices reflecting the renegotiation of
certain long-term coal contracts and other lower priced purchases under
existing and new contracts. Other factors which reduced fuel and purchased
power expense in 1995 were increased utilization of low cost nuclear
generation; decreased energy purchases due to the mild weather during the
first half of 1995 and the operation of fuel clause mechanisms. Changes in
fuel expense are generally deferred pending recovery in various fuel clause
mechanisms, as such they generally do not affect earnings.
The significant increase in other operation expense during 1995 was
primarily due to rent and other operating costs of the Gavin Plant
scrubbers which went into service in December 1994 and the first quarter of
1995; a $41 million ($27 million after-tax) provision for severance pay
recorded in 1995 related mainly to a functional realignment of operations;
and costs related to the development of a new activity based budgeting
system.
Maintenance expense decreased in 1996 due to the recovery of previously
expensed storm damage costs and reduced nuclear plant maintenance expense
due to workforce reductions and the reduction of contract labor at the Cook
Nuclear Plant.
The increases in federal income tax expense attributable to operations
was primarily due to an increase in pre-tax operating income and changes in
certain book/tax differences accounted for on a flow-through basis and in
1995 the effects of accrual adjustments for prior year tax returns.
Nonoperating Income
Nonoperating income decreased in 1996 due to the cost of the AEP branding
program and startup costs of the new business ventures. The increase in
nonoperating income in 1995 was mainly due to a 1994 loss of $8.2 million
on a demand side management investment.
Interest Charges and Preferred Stock Dividend Requirements
In 1996 interest charges and preferred stock dividend requirements
decreased as the Company's subsidiaries continued their refinancing
programs. The programs reduced the average interest rate and the amount of
long-term debt and preferred stock outstanding. The cost of short-term
borrowings in 1996 increased slightly re-flecting an increased average
balance of short-term debt outstanding.
Interest charges increased in 1995 mainly due to an increase in interest
on short-term debt resulting from a higher average interest rate in 1995 on
larger levels of outstanding short-term debt.
Common Dividend Remains Constant; Payout Ratio Decreases
The Company paid a quarterly dividend in 1996 of 60 cents a share
maintaining the annual dividend rate at $2.40 per share. The payout ratio
continued an improving trend to 76% in 1996 from 84% in 1995 and 89% in
1994. It has been a management objective to reduce the payout ratio
through efforts to increase earnings in order to enhance AEP's ability to
invest in new business ventures that complement our core competencies and
can maintain and improve shareholder value.
Liquidity and Capital Resources
Electric utility construction expenditures in the United States have
been declining in recent years due to slow growth in the demand for
electricity, environmental restrictions, and delays in obtaining approvals
to construct transmission facilities. Demand-side management programs such
as direct load control, interruptible load, energy efficiency, and other
demand and load reduction programs have lessened the need for new plant
expenditures. Also in some parts of the country substantial portions of
new generation additions have been by non-utility entities. AEP's
construction expenditures have followed the industry trend and have been
generally declining since 1991 when we last completed a new generating
facility. Our electric generating plant expenditures for 1996 accounted
for only 27% of the total electric utility plant expenditures, as compared
to the historic level of investment in electric generating plant of 49%.
Transmission and distribution (T&D) expenditures, on the other hand,
accounted for approximately 68% of expenditures, compared with the historic
investment level of 46%. Construction expenditures for our domestic
utility operations are estimated to be $2 billion over the next three years
with no major plant construction planned for our service territory. Total
T&D expenditures will be related to the improvement of and additions to
delivery facilities. Approximately 88% of the domestic construction
expenditures for the next three years will be financed internally.
Allowance for funds used during construction (AFUDC) accruals also declined
during this period. The decline in AFUDC in recent years is primarily due
to the decrease in the level of generation plant construction combined with
a decrease in interest rates.
The operating subsidiaries generally issue short-term debt to provide
for interim financing of capital expenditures that exceed internally
generated funds. They periodically reduce their outstanding short-term
debt through issuances of long-term debt and historically preferred stock
and with additional capital contributions by the parent company. In 1996
short-term borrowing decreased by $45 million. At December 31, 1996
American Electric Power Co., Inc. (the parent company) and its utility
subsidiaries had unused short-term lines of credit of $409 million, and
several of AEP's subsidiaries engaged in providing non-regulated energy
services had an unused line of credit of $100 million available under a
revolving credit agreement. In February 1997 the credit available under
the revolving credit agreement was increased to $500 million. The sources
of funds available to the parent company are dividends from its
subsidiaries, short-term and long-term borrowings and, when necessary,
proceeds from the issuance of common stock. The parent company issued
1,600,000 shares in 1996, 1,400,000 shares in 1995 and 700,000 shares in
1994 of common stock through a Dividend Reinvestment Program raising $65
million, $49 million and $22 million, respectively. As a result of the
common stock issuances and the reduction in long-term debt over the past
several years, the common equity to capitalization ratio has steadily
improved. At December 31, 1996 the ratio increased to 45.3% from 43.1% at
year-end 1995 and from 42.1% at year-end 1994.
The debt and preferred stock coverages of the principal operating
subsidiaries remained strong in 1996.
Coverages at December 31, 1996
Mortgage and Preferred
Long-term Debt Stock
Appalachian Power Co. 3.98 1.99
Columbus Southern Power Co. 4.44 N/A
Indiana Michigan Power Co. 6.66 3.07
Kentucky Power Co. 3.22 N/A
Ohio Power Co. 6.62 3.63
N/A = Not Applicable
Unless the subsidiaries meet certain earnings or coverage tests, they
cannot issue additional mortgage bonds or preferred stock. In order to
issue mortgage bonds (without refunding existing debt), each subsidiary
must have pre-tax earnings equal to at least two times the annual interest
charges on mortgage bonds after giving effect to the issuance of the new
debt. Generally, issuance of additional preferred stock requires after-tax
gross income at least equal to one and one-half times annual interest
and preferred stock dividend requirements after giving effect to the
issuance of the new preferred stock. The subsidiaries presently exceed
these minimum coverage requirements.
In January 1997 the Company announced a tender offer for certain
subsidiaries' preferred stock in conjunction with special meetings
scheduled to be held on February 28, 1997. The special meetings' purpose
is to consider amendments to the subsidiaries' articles of incorporation to
remove certain capitalization ratio requirements. These restrictions limit
the subsidiaries' financial flexibility and could place them at a
competitive disadvantage in the future. The amount paid to redeem the
preferred stock that is tendered could total as much as $514 million. The
subsidiaries expect to use a combination of short-term debt and unsecured
long-term debt to pay for the preferred stock tendered.
Litigation
AEP is involved in a number of legal proceedings and claims. While we
are unable to predict the outcome of such litigation, it is not expected
that the ultimate resolution of these matters will have a material adverse
effect on the results of operations and/or financial condition.
Effect of Inflation
Inflation affects AEP's cost of replacing utility plant and the cost of
operating and maintaining its plant. The rate-making process limits our
recovery to the historical cost of assets resulting in economic losses when
the effects of inflation are not recovered from customers on a timely
basis. However, economic gains that results from the repayment of long-term
debt with inflated dollars partly offset such losses.
Corporate Owned Life Insurance
In connection with the audit of AEP's 1991, 1992 and 1993 federal
income tax returns the Internal Revenue Service agents sought a ruling from
the IRS National Office that certain interest deductions relating to a
corporate owned life insurance (COLI) program should not be allowed. The
Company established the COLI program in 1990 as a part of its 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
approxiately $247 million (including interest). AEP believes it will
ultimately prevail on this issue and will vigorously contest any
disallowance that may be assessed.
In 1996 Congress enacted legislation that prospectively phases out the
tax benefits for COLI interest deductions over a three year period
beginning in 1996. As a result the Company intends to restructure its COLI
program. The restructuring of the COLI program is not expected to have a
material impact on results of operations.
New Accounting Rules
In 1996 the Financial Accounting Standards Board (FASB) issued an
exposure draft "Accounting for Certain Liabilities Related to Closure or
Removal of Long-Lived Assets." The proposal suggests 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. The FASB is
reconsidering the exposure draft proposal. It is unclear at this time in
what manner the FASB will adopt the proposal. Until it becomes apparent
what the FASB will decide and how certain questions raised by the exposure
draft are resolved the Company cannot determine its impact.
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands - except per share amounts)
<CAPTION>
Year Ended December 31,
1996 1995 1994
<S> <C> <C> <C>
OPERATING REVENUES $5,849,234 $5,670,330 $5,504,670
OPERATING EXPENSES:
Fuel and Purchased Power 1,686,754 1,625,531 1,745,245
Other Operation 1,210,027 1,184,158 1,002,822
Maintenance 502,841 541,825 544,312
Depreciation and Amortization 600,851 593,019 572,189
Taxes Other Than Federal Income Taxes 498,567 489,223 494,210
Federal Income Taxes 342,222 272,027 213,399
TOTAL OPERATING EXPENSES 4,841,262 4,705,783 4,572,177
OPERATING INCOME 1,007,972 964,547 932,493
NONOPERATING INCOME 2,212 20,204 11,485
INCOME BEFORE INTEREST CHARGES AND
PREFERRED DIVIDENDS 1,010,184 984,751 943,978
INTEREST CHARGES (net) 381,328 400,077 389,240
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES 41,426 54,771 54,726
NET INCOME $587,430 $529,903 $500,012
AVERAGE NUMBER OF SHARES OUTSTANDING 187,321 185,847 184,666
EARNINGS PER SHARE $3.14 $2.85 $2.71
CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
<CAPTION>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(in thousands)
Year Ended December 31,
1996 1995 1994
<S> <C> <C> <C>
RETAINED EARNINGS JANUARY 1 $1,409,645 $1,325,581 $1,269,283
NET INCOME 587,430 529,903 500,012
DEDUCTIONS:
Cash Dividends Declared 449,353 445,831 443,101
Other (24) 8 613
RETAINED EARNINGS DECEMBER 31 $1,547,746 $1,409,645 $1,325,581
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<CAPTION>
Year Ended December 31,
1996 1995 1994
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net Income $587,430 $529,903 $500,012
Adjustments for Noncash Items:
Depreciation and Amortization 590,657 578,003 561,188
Deferred Federal Income Taxes (21,478) 11,916 (16,033)
Deferred Investment Tax Credits (25,808) (25,819) (31,275)
Amortization of Operating Expenses
and Carrying Charges (net) 55,458 53,479 16,022
Changes in Certain Current Assets
and Liabilities:
Accounts Receivable (net) (39,049) (71,804) 34,302
Fuel, Materials and Supplies 35,831 457 (1,627)
Accrued Utility Revenues 32,953 (40,433) 2,419
Accounts Payable (13,915) (31,044) (7,959)
Taxes Accrued (6,019) 37,515 (26,521)
Other (net) 41,002 14,437 (52,803)
Net Cash Flows From
Operating Activities 1,237,062 1,056,610 977,725
INVESTING ACTIVITIES:
Construction Expenditures (577,691) (605,974) (643,457)
Proceeds from Sale of Property and Other 12,283 20,567 49,802
Net Cash Flows Used For
Investing Activities (565,408) (585,407) (593,655)
FINANCING ACTIVITIES:
Issuance of Common Stock 65,461 48,707 22,256
Issuance of Cumulative Preferred Stock - - 88,787
Issuance of Long-term Debt 407,291 523,476 411,869
Retirement of Cumulative Preferred Stock (70,761) (158,839) (35,949)
Retirement of Long-term Debt (601,278) (469,767) (445,636)
Change in Short-term Debt (net) (45,430) 48,140 38,009
Dividends Paid on Common Stock (449,353) (445,831) (443,101)
Net Cash Flows Used For
Financing Activities (694,070) (454,114) (363,765)
Net Increase (Decrease) in Cash and
Cash Equivalents (22,416) 17,089 20,305
Cash and Cash Equivalents January 1 79,955 62,866 42,561
Cash and Cash Equivalents December 31 $57,539 $79,955 $62,866
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In Thousands - Except Share Data)
<CAPTION>
December 31,
1996 1995
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production $ 9,341,849 $ 9,238,843
Transmission 3,380,258 3,316,664
Distribution 4,402,449 4,184,251
General (including mining assets and nuclear fuel) 1,491,781 1,442,086
Construction Work in Progress 353,832 314,118
Total Electric Utility Plant 18,970,169 18,495,962
Accumulated Depreciation and Amortization 7,549,798 7,111,123
NET ELECTRIC UTILITY PLANT 11,420,371 11,384,839
OTHER PROPERTY AND INVESTMENTS 892,674 825,781
CURRENT ASSETS:
Cash and Cash Equivalents 57,539 79,955
Accounts Receivable:
Customers (less allowance for uncollectible
accounts of $3,692 in 1996 and $5,430 in 1995) 415,413 417,854
Miscellaneous 115,919 74,429
Fuel - at average cost 235,257 271,933
Materials and Supplies - at average cost 251,896 251,051
Accrued Utility Revenues 174,966 207,919
Prepayments and Other 103,891 98,717
TOTAL CURRENT ASSETS 1,354,881 1,401,858
REGULATORY ASSETS 1,889,482 1,979,446
DEFERRED CHARGES 328,139 310,377
TOTAL $15,885,547 $15,902,301
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
<CAPTION>
December 31,
1996 1995
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock-Par Value $6.50:
1996 1995
Shares Authorized. .300,000,000 300,000,000
Shares Issued . . ..197,234,992 195,634,992
(8,999,992 shares were held in treasury) $ 1,282,027 $ 1,271,627
Paid-in Capital 1,715,554 1,658,524
Retained Earnings 1,547,746 1,409,645
Total Common Shareholders' Equity 4,545,327 4,339,796
Cumulative Preferred Stocks of Subsidiaries:*
Not Subject to Mandatory Redemption 90,323 148,240
Subject to Mandatory Redemption 509,900 515,085
Long-term Debt* 4,796,768 4,920,329
TOTAL CAPITALIZATION 9,942,318 9,923,450
OTHER NONCURRENT LIABILITIES 1,002,208 884,707
CURRENT LIABILITIES:
Preferred Stock and Long-term Debt Due Within One Year* 86,942 144,597
Short-term Debt 319,695 365,125
Accounts Payable 206,227 220,142
Taxes Accrued 414,173 420,192
Interest Accrued 75,124 80,848
Obligations Under Capital Leases 89,553 89,692
Other 304,323 304,466
TOTAL CURRENT LIABILITIES 1,496,037 1,625,062
DEFERRED INCOME TAXES 2,643,143 2,656,651
DEFERRED INVESTMENT TAX CREDITS 404,050 430,041
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 240,598 249,875
DEFERRED CREDITS 157,193 132,515
CONTINGENCIES (Note 4)
TOTAL $15,885,547 $15,902,301
*See Accompanying Schedules on pages 36 - 37.
</TABLE>
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies:
The American Electric Power System (AEP, AEP System or the Company) is a
public utility engaged in the generation, purchase, transmission and
distribution of electric power to over 2.9 million retail customers in its
seven state service territory which covers portions of Ohio, Michigan,
Indiana, Kentucky, West Virginia, Virginia and Tennessee. Electric power
is also supplied at wholesale to neighboring utility systems and power
marketers.
The organization of the AEP System consists of American Electric Power
Company, Inc., the parent holding company; seven electric utility operating
companies (utility subsidiaries); a generating subsidiary, AEP Generating
Company (AEPGEN); a service company, American Electric Power Service
Corporation (AEPSC); three active coal-mining companies and a group of
subsidiaries that complement utility activities. The following utility
subsidiaries pool their generating and transmission facilities and operate
them as an integrated system:
- - Appalachian Power Company (APCo)
- - Columbus Southern Power Company (CSPCo)
- - Indiana Michigan Power Company (I&M)
- - Kentucky Power Company (KEPCo)
- - Ohio Power Company (OPCo)
The remaining two utility subsidiaries, Kingsport Power Company and
Wheeling Power Company, are distribution companies that purchase power from
APCo and OPCo, respectively. AEPSC provides management and professional
services to the AEP System. The active coal-mining companies are wholly-owned
by OPCo and sell most of their production to OPCo. AEPGEN has a 50%
interest in the Rockport Plant which is comprised of two of the AEP
System's six 1,300 megawatt (mw) generating units. The group of
subsidiaries that complement utility activities are engaged in providing
non-regulated energy services and are seeking and considering new business
opportunities domestically and internationally that will permit AEP to
utilize its expertise and core competencies.
Effective January 1, 1996, AEPSC and the seven utility subsidiaries
began operating as American Electric Power. There has been no change to
the legal names of these companies. The AEP System's operations are
divided into major business units which are managed centrally by AEPSC.
Rate Regulation - The AEP System is subject to regulation by the Securities
and Exchange Commission (SEC) under the Public Utility Holding Company Act
of 1935 (1935 Act). The rates charged by the utility subsidiaries are
approved by the Federal Energy Regulatory Commission (FERC) or one of the
state utility commissions as applicable. The FERC regulates wholesale
rates and the state commissions regulate retail rates.
Principles of Consolidation - The consolidated financial statements include
American Electric Power Company, Inc. (AEPCo., Inc.) and its wholly-owned
subsidiaries consolidated with their wholly-owned subsidiaries.
Significant intercompany items are eliminated in consolidation.
Basis of Accounting - As the owner of cost-based rate-regulated electric
public utility companies, AEPCo., Inc.'s consolidated financial statements
reflect the actions of regulators that result in the recognition of
revenues and expenses in different time periods than enterprises that are
not rate regulated. In accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation," regulatory assets (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.
Utility Plant - Electric utility plant is stated at original cost and is
generally subject to first mortgage liens. Additions, major replacements
and betterments are added to the plant accounts. Retirements from the
plant accounts and associated removal costs, net of salvage, are deducted
from accumulated depreciation. The costs of labor, materials and overheads
incurred to operate and maintain utility plant are included in operating
expenses.
Allowance for Funds Used During Construction (AFUDC) - AFUDC is a noncash
nonoperating income item that is recovered over the service life of utility
plant through depreciation and represents the estimated cost of borrowed
and equity funds used to finance construction projects. The average rates
used to accrue AFUDC were 6.09%, 6.91%, and 6.59% in 1996, 1995 and 1994,
respectively.
Depreciation, Depletion and Amortization - Depreciation is provided on a
straight-line basis over the estimated useful lives of property other than
coal-mining property and
is calculated largely through the use of composite rates by functional
class as follows:
Composite
Functional Class Depreciation
of Property Annual Rates
Production:
Steam-Nuclear 3.4%
Steam-Fossil-Fired 3.2% to 4.4%
Hydroelectric-Conventional
and Pumped Storage 2.7% to 3.2%
Transmission 1.7% to 2.7%
Distribution 3.3% to 4.2%
General 2.5% to 3.8%
The utility subsidiaries presently recover amounts to be used for
demolition of non-nuclear plant through depreciation charges included in
rates. Depreciation, depletion and amortization of coal-mining assets is
provided over each asset's estimated useful life, ranging up to 30 years,
and is calculated using the straight-line method for mining structures and
equipment. The units-of-production method is used to amortize coal rights
and mine development costs based on estimated recoverable tonnages at a
current average rate of $1.49 per ton. These costs are included in the
cost of coal charged to fuel expense.
Cash and Cash Equivalents - Cash and cash equivalents include temporary
cash investments with original maturities of three months or less.
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.
Fuel Costs - Fuel costs are matched with revenues in accordance with rate
commission orders. Generally in the retail jurisdictions, changes in fuel
costs are deferred or revenues accrued until approved by the regulatory
commission for billing or refund to customers in later months. Wholesale
jurisdictional fuel cost changes are expensed and billed as incurred.
Levelization of Nuclear Refueling Outage Costs - Incremental operation and
maintenance costs associated with refueling outages at I&M's Donald C. Cook
Nuclear Plant (Cook Plant) are deferred and amortized over the period
(generally eighteen months) beginning with the commencement of an outage
and ending with the beginning of the next outage.
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 - Investment tax credits have been accounted for
under the flow-through method except where regulatory commissions have
reflected investment tax credits in the rate-making process on a deferral
basis. Deferred investment tax credits are being amortized over the life
of the related plant investment.
Debt and Preferred Stock - Gains and losses on reacquired debt are deferred
and amortized over the remaining term of the reacquired debt in accordance
with rate-making treatment. If the debt is refinanced the reacquisition
costs are deferred and amortized over the term of the replacement debt
commensurate with their recovery in rates.
Debt discount or premium and debt issuance expenses are amortized over
the term of the related debt, with the amortization included in interest
charges.
Redemption premiums paid to reacquire preferred stock are included in
paid-in capital and amortized to retained earnings in accordance with
rate-making treatment. The excess of par value over costs of preferred stock
reacquired to meet sinking fund requirements is credited to paid-in capital
and amortized to retained earnings.
Other Property and Investments - Excluding decommissioning and spent
nuclear fuel disposal trust funds, other property and investments are
stated at cost. Securities held in trust funds for decommissioning nuclear
facilities and for the disposal of spent nuclear fuel are recorded at
market value in accordance with SFAS No. 115, "Accounting for Certain
Investments in Debt and Equity Securities." Securities in the trust funds
have been classified as available-for-sale due to their long-term purpose.
Due to the rate-making process, adjustments for unrealized gains and losses
are not reported in equity but result in adjustments to regulatory assets
and liabilities.
2. Rate Matters:
Recovery of Fuel Costs - Under the terms of a 1992 stipulation agreement
the cost of coal burned at the Gavin Plant is subject to a 15-year
predetermined price of $1.575 per million Btu's with quarterly escalation
adjustments through November 2009. A 1995 Settlement Agreement set the fuel
component of the EFC factor at 1.465 cents per kwh for the period June 1,
1995 through November 30, 1998 and reserved certain items including
emission allowances for later consideration in determining total fuel
recovery. The agreements provide OPCo with the opportunity to recover over
the term of the stipulation agreement the Ohio jurisdictional share of
OPCo's investment in and the liabilities and future shut-down costs of its
affiliated mines as well as any fuel costs incurred above the fixed rate to
the extent the actual cost of coal burned at the Gavin Plant is below the
predetermined price. 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. Pursuant
to these agreements the Company has deferred $28.5 million for future
recovery at December 31, 1996.
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 the
affiliated Meigs, Muskingum and Windsor mines. 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 $180 million after tax at December 31,
1996.
The affiliated Muskingum and Windsor mines may have to close by January
2000 in order to comply with the Phase II requirements of the Clean Air Act
Amendments of 1990. The Muskingum and/or Windsor mines could close prior
to January 2000 depending on the economics of continued operation under the
terms of the above Settlement Agreement. Unless future shutdown costs
and/or the cost of affiliated coal production of the Meigs, Muskingum and
Windsor mines can be recovered, results of operations would be adversely
affected.
3. Effects of Regulation and Phase-In Plans:
In accordance with SFAS 71 the consolidated financial statements include
assets (deferred expenses) and liabilities (deferred income) recorded in
accordance with regulatory actions 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 the regulatory liabilities are
expected to reduce future cost recoveries. 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 net regulatory assets would have
to be written off for that portion of the business.
Regulatory assets and liabilities are comprised of the following at:
December 31,
1996 1995
(In Thousands)
Regulatory Assets:
Amounts Due From Customers For
Future Income Taxes $1,459,086 $1,446,485
Rate Phase-in Plan Deferrals 27,249 74,402
Unamortized Loss on Reacquired Debt 107,305 109,551
Other 295,842 349,008
Total Regulatory Assets $1,889,482 $1,979,446
Regulatory Liabilities:
Deferred Investment Tax Credits $404,050 $430,041
Other Regulatory Liabilities* 86,609 86,347
Total Regulatory Liabilities $490,659 $516,388
* Included in Deferred Credits on Consolidated Balance Sheets
The rate phase-in plan deferrals are applicable to the Zimmer Plant and
Rockport Plant Unit 1. The Zimmer Plant is 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 Public Utilities Commission of Ohio (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 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% 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 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 deferrals were
$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. 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.
The Rockport Plant consists of two 1,300 mw coal-fired units. I&M and
AEPGEN each own 50% of one unit (Rockport 1) and lease a 50% interest in
the other unit (Rockport 2) from unaffiliated lessors under an operating
lease. The gain on the sale and leaseback of Rockport 2 was deferred and
is being amortized, with related taxes, over the initial lease term which
expires in 2022. Rate phase-in plans in I&M's Indiana and FERC
jurisdictions for its share of Rockport 1 provide for the recovery and
straight-line amortization through 1997 of prior-year cost deferrals.
Unamortized deferred amounts under the phase-in plans were $11.9 million
and $27.5 million at December 31, 1996 and 1995, respectively.
Amortization was $16 million in 1996, 1995 and 1994.
4. Commitments and Contingencies:
Construction and Other Commitments - The AEP System has made substantial
construction commitments for utility operations. Such commitments do not
presently include any expenditures for new generating capacity. The
aggregate construction program expenditures for 1997-1999 are estimated to
be $2 billion.
Long-term fuel supply contracts contain clauses for periodic
adjustments, and most jurisdictions have fuel clause mechanisms that
provide for recovery of changes in the cost of fuel with the regulators'
review and approval. The contracts are for various terms, the longest of
which extend to the year 2014, and contain various clauses that would
release the Company from its obligation under certain force majeure
conditions.
The AEP System has contracted to sell up to 1,350 mw of capacity on a
long-term basis to unaffiliated utilities. Certain contracts totaling 705
mw of capacity are unit power agreements requiring the delivery of energy
regardless of whether the unit capacity is available. The power sales
contracts expire from 1997 to 2010.
Tender Offer - On February 24, 1997 AEP and Public Service Company of
Colorado with equal interests in a joint venture announced a cash tender
offer for Yorkshire Electricity Group plc in the United Kingdom. The joint
venture proposes to pay $2.4 billion to acquire all of the stock of
Yorkshire Electricity. AEP's equity investment, estimated to be $360
million, will be made through its subsidiary AEP Resources Inc., initially
using cash borrowed under a revolving credit agreement.
Nuclear Plant - I&M owns and operates the two-unit 2,110 mw Cook Nuclear
Plant under licenses granted by the Nuclear Regulatory Commission. The
operation of a nuclear facility involves special risks, potential
liabilities, and specific regulatory and safety requirements. Should a
nuclear incident occur at any nuclear power plant facility in the United
States, the resultant liability could be substantial. By agreement I&M is
partially liable together with all other electric utility companies that
own nuclear generating units for a nuclear power plant incident. In the
event nuclear losses or liabilities are underinsured or exceed accumulated
funds and recovery in rates is not possible, results of operations and
financial condition could be negatively affected.
Nuclear Incident Liability - Public liability is limited by law to $8.9
billion should an incident occur at any licensed reactor in the United
States. Commercially available insurance provides $200 million of
coverage. In the event of a nuclear incident at any nuclear plant in the
United States the remainder of the liability would be provided by a
deferred premium assessment of $79.3 million on each licensed reactor
payable in annual installments of $10 million. As a result, I&M could be
assessed $158.6 million per nuclear incident payable in annual installments
of $20 million. The number of incidents for which payments could be
required is not limited.
Nuclear insurance pools and other insurance policies provide $3.6
billion of property damage, decommissioning and decontamination coverage
for the Cook Plant. Additional insurance provides coverage for extra costs
resulting from a prolonged accidental Cook Plant outage. Some of the
policies have deferred premium provisions which could be triggered by
losses in excess of the insurer's resources. The losses could result from
claims at the Cook Plant or certain other non-affiliated nuclear units.
I&M could be assessed up to $35.8 million under these policies.
Spent Nuclear Fuel Disposal - Federal law provides for government
responsibility for permanent spent nuclear fuel disposal and assesses
nuclear plant owners fees for spent fuel disposal. A fee of one mill per
kilowatthour for fuel consumed after April 6, 1983 is being collected from
customers and remitted to the U.S. Treasury. Fees and related interest of
$172 million for fuel consumed prior to April 7, 1983 have been recorded as
long-term debt. I&M has not paid the government the pre-April 1983 fees
due to continued delays and uncertainties related to the federal disposal
program. At December 31, 1996, funds collected from customers towards
payment of the pre-April 1983 fee and related earnings thereon approximate
the liability.
Decommissioning and Low Level Waste Accumulation Disposal - Decommissioning
costs are accrued over the service life of the Cook Plant. The licenses to
operate the two nuclear units expire in 2014 and 2017. After expiration of
the licenses the plant is expected to be decommissioned through
dismantlement. The Company's latest estimate for decommissioning and low
level radioactive waste accumulation disposal costs range from $634 million
to $988 million 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 plant subsequent to ceasing operations.
This in turn 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 estimated decommissioning costs in its three rate-making
jurisdictions based on at least the lower end of the range in the most
recent decommissioning study at the time of the last rate proceeding. I&M
records decommissioning costs in other operation expense and records a
noncurrent liability equal to the decommissioning cost recovered in rates;
such amount was $27 million in 1996, $30 million in 1995 including $4
million of special deposits and $26 million in 1994. Decommissioning costs
recovered from customers are deposited in external trusts. Trust fund
earnings increase the fund assets and the recorded liability and decrease
the amount needed to be recovered from ratepayers. At December 31, 1996
I&M has recognized a decommissioning liability of $314 million which is
included in other noncurrent liabilities.
Litigation - The Company is involved in a number of legal proceedings and
claims. While management is unable to predict the ultimate 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.
5. Dividend Restrictions:
Mortgage indentures, charter provisions and orders of regulatory
authorities place various restrictions on the use of the subsidiaries'
retained earnings for the payment of cash dividends on their common stocks.
At December 31, 1996, $30 million of retained earnings were restricted. To
pay dividends out of paid-in capital the subsidiaries need regulatory
approval.
6. Lines of Credit and Commitment Fees:
At December 31, 1996 and 1995 unused short-term bank lines of credit 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. In addition
several of the subsidiaries engaged in providing non-regulated energy
services share a $100 million line of credit under a revolving credit
agreement which requires the payment of a commitment fee of approximately
1/8 of 1% of the unused balance. At December 31, 1996 no borrowings were
outstanding under the revolving credit agreement. In February 1997 the
credit available under this agreement was increased to $500 million.
Outstanding short-term debt consisted of:
December 31,
(Dollars In Thousands) 1996 1995
Balance Outstanding:
Notes Payable $ 91,293 $ 128,425
Commercial Paper 228,402 236,700
Total $319,695 $365,125
Year-End Weighted
Average Interest Rate:
Notes Payable 6.2% 6.1%
Commercial Paper 7.2% 6.1%
Total 6.9% 6.1%
7. Benefit Plans:
AEP System Pension Plan - The AEP pension plan is a trusteed,
noncontributory defined benefit plan covering all employees meeting
eligibility requirements, except participants in the United Mine Workers of
America (UMWA) pension plans. Benefits are based on service years and
compensation levels. The funding policy is to make annual contributions to
a qualified trust fund 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.
<PAGE>
Net AEP pension plan costs were computed as follows:
Year Ended December 31,
1996 1995 1994
(In Thousands)
Service Cost-Benefits Earned
During the Year $ 40,000 $ 30,400 $ 40,000
Interest Cost on Projected Benefit
Obligation 119,500 116,700 114,500
Actual Return on Plan Assets (302,400) (416,800) (6,700)
Net Amortization (Deferral) 161,800 281,800 (123,300)
Net AEP Pension Plan Costs $ 18,900 $ 12,100 $ 24,500
AEP pension plan assets and actuarially computed benefit obligations are:
December 31,
1996 1995
(In Thousands)
AEP Pension Plan Assets at
Fair Value (a) $2,009,500 $1,805,300
Actuarial Present Value
of Benefit Obligation:
Vested 1,377,000 1,321,600
Nonvested 136,500 147,400
Accumulated Benefit
Obligation 1,513,500 1,469,000
Effects of Salary Progression 162,700 181,000
Projected Benefit
Obligation 1,676,200 1,650,000
Funded Status - AEP
Pension Plan Assets
in Excess of Projected
Benefit Obligation 333,300 155,300
Unrecognized Prior
Service Cost 133,200 147,000
Unrecognized Net Gain (488,200) (295,200)
Unrecognized Net Transition
Assets (Being Amortized
Over 17 Years) (68,900) (78,700)
Accrued Net AEP
Pension Plan
Liability $ (90,600) $ (71,600)
(a) AEP pension plan assets primarily consist of common stocks, bonds and
cash equivalents and are included in a separate entity trust fund.
Assumptions used to determine AEP pension plan's funded status were:
December 31,
1996 1995 1994
Discount Rate 7.75% 7.25% 8.5%
Average Rate of Increase in
Compensation Levels 3.2% 3.2% 3.2%
Expected Long-Term Rate of Return
on Plan Assets 9.0% 9.0% 8.5%
AEP System Savings Plan - An employee savings plan is offered to non-UMWA
employees which allows participants to contribute up to 17% of their
salaries into various investment alternatives, including AEP 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 common stock. The employer's annual
contributions totaled $19 million in 1996, $18.8 million in 1995 and $18.6
million in 1994.
UMWA Pension Plans - The coal-mining subsidiaries of OPCo provide UMWA
pension benefits for UMWA employees meeting eligibility requirements.
Benefits are based on age at retirement and years of service. As of June
30, 1996, the UMWA actuary estimates the OPCo coal-mining subsidiaries'
share of the UMWA pension plans' unfunded vested liabilities was
approximately $26 million. In the event the OPCo coal-mining subsidiaries
cease or significantly reduce mining operations or contributions to the
UMWA pension plans, a withdrawal obligation may be triggered for all or a
portion of their share of the unfunded vested liability. Contributions are
based on the number of hours worked, are expensed when paid and totaled
$1.6 million in 1996, $1.4 million in 1995 and $1.6 million in 1994.
Postretirement Benefits Other Than Pensions (OPEB) - The AEP System
provides certain other benefits for retired employees. Substantially all
non-UMWA employees are eligible for postretirement health care and life
insurance if they retire from active service after reaching age 55 and have
at least 10 service years.
Postretirement medical benefits for UMWA employees at affiliated mining
operations who have or will retire after January 1, 1976 are the liability
of the OPCo coal-mining subsidiaries. They are eligible for postretirement
medical benefits if they retire from active service after reaching age 55
and have at least 10 service years. In addition, non-active UMWA employees
will become eligible for postretirement benefits at age 55 if they have had
20 service years.
The funding policy for AEP's 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 $45.8 million in 1996, $53 million in 1995 and $29.5
million in 1994. In several jurisdictions the utility subsidiaries
deferred the increased OPEB costs resulting from the SFAS 106 required
change from pay-as-you-go to accrual accounting which were not being
recovered in rates. No additional deferrals were made in 1996. At
December 31, 1996 and 1995, $14.5 million and $24.6 million, respectively,
of incremental OPEB costs were deferred.
<PAGE>
Aggregate OPEB costs were computed as follows:
Year Ended December 31,
1996 1995 1994
(In Thousands)
Service Cost $ 15,300 $ 13,500 $16,500
Interest Cost on Projected
Benefit Obligation 53,500 54,900 47,300
Net Amortization of
Transition Obligation 32,300 32,000 31,100
Return on Plan Assets (21,100) (25,400) 900
Net Amortization (Deferral) 9,900 16,800 (6,800)
Net OPEB Costs $ 89,900 $ 91,800 $89,000
OPEB assets and actuarially computed benefit obligations are:
December 31,
1996 1995
(In Thousands)
Fair Market Value of
Plan Assets (a) $ 232,500 $ 165,600
Accumulated Postretirement
Benefit Obligation:
Active Employees Fully
Eligible for Benefits 57,800 59,200
Current Retirees 423,000 398,400
Other Active Employees 245,600 282,400
Total Benefit Obligation 726,400 740,000
Unfunded Benefit Obligation (493,900) (574,400)
Unrecognized Net Loss (Gain) (3,300) 48,500
Unrecognized Net Transition
Obligation Being
Amortized Over 20 Years 448,500 485,600
Accrued Net OPEB Liability $ (48,700) $ (40,300)
(a) Plan assets consist of cash surrender value of life insurance contracts
on certain employees owned by the trust and short-term tax exempt municipal
bonds.
Assumptions used to determine OPEB's funded status were:
December 31,
1996 1995 1994
Discount Rate 7.75% 7.25% 8.5%
Expected Long-Term Rate
of Return on Plan Assets 8.75% 8.75% 8.25%
Initial Medical Cost
Trend Rate 7.5% 8.0% 8.0%
Ultimate Medical Cost
Trend Rate 4.75% 4.5% 5.25%
Medical Cost Trend Rate
Decreases to Ultimate
Rate in Year 2005 2005 2005
Assuming a one percent increase in the medical cost trend rate, the 1996
OPEB cost for all employees, both non-UMWA and UMWA, would increase by $8
million and the accumulated benefit obligations would increase by $82
million.
Several UMWA health plans pay the postretirement medical benefits for
the Company's UMWA retirees who retired before January 2, 1976 and their
survivors plus retirees and others whose last employer is no longer a
signatory to the UMWA contract or is no longer in business. The UMWA
health plans are funded by payments from current and former UMWA wage
agreement signatories, the 1950 UMWA Pension Plan surplus and the Abandoned
Mine Land Reclamation Fund Surplus. Required annual payments to the UMWA
health funds made by AEP's active and inactive coal-mining subsidiaries
were recognized as expense when paid and totaled $0.9 million in 1996, $2.8
million in 1995 and $3.1 million in 1994.
By law, excess Black Lung Trust funds may be used to pay certain
postretirement medical benefits under one of the UMWA health plans. Excess
AEP Black Lung Trust funds used to reimburse the coal companies totaled
$7.4 million in 1996, $7.9 million in 1995 and $6.9 million in 1994. The
Black Lung Trust had excess funds at December 31, 1996 of approximately $12
million, of which $10.8 million may be used to pay future costs.
8. Fair Value of Financial Instruments:
Nuclear Trust Funds Recorded at Market Value - The trust investments,
reported in other property and investments, are recorded at market value in
accordance with SFAS 115 and consist of long-term tax-exempt municipal
bonds and other securities.
At December 31, 1996 and 1995 the fair values of the trust investments
were $491 million and $434 million, respectively. Accumulated gross
unrealized holding gains were $21.9 million and $19.1 million and
accumulated gross unrealized holding losses were $1.2 million and $1
million at December 31, 1996 and 1995, respectively. The change in market
value in 1996 was a net unrealized holding gain of $2.6 million, in 1995 a
net unrealized holding gain of $24.9 million and in 1994 a net unrealized
holding loss of $27.1 million.
The trust investments' cost basis by security type were:
December 31,
1996 1995
(In Thousands)
Tax-Exempt Bonds $340,290 $336,073
Equity Securities 54,389 24,101
Treasury Bonds 26,958 12,992
Corporate Bonds 7,977 1,971
Cash, Cash Equivalents
and Accrued Interest 40,430 40,356
Total $470,044 $415,493
Proceeds from sales and maturities of securities of $115.3 million
during 1996 resulted in $2.6 million of realized gains and $2.1 million of
realized losses. Proceeds from sales and maturities of securities of $78.2
million during 1995 resulted in $1.4 million of realized gains and $0.3
million of realized losses. During 1994 proceeds from sales and maturities
of securities of $20.1 million resulted in $52,000 of realized gains and
$155,000 of realized losses. The cost of securities for determining
realized gains and losses is original acquisition cost including amortized
premiums and discounts.
At December 31, 1996, the year of maturity of trust fund investments
other than equity securities, was:
(In Thousands)
1997 $ 56,452
1998 - 2001 120,327
2002 - 2006 163,250
After 2006 75,626
Total $415,655
Other Financial Instruments Recorded at Historical Cost - The carrying
amounts of cash and cash equivalents, accounts receivable, short-term debt,
and accounts payable approximate fair value because of the short-term
maturity of these instruments. Fair values for preferred stock subject to
mandatory redemption were $517 million and $544 million and for long-term
debt were $5.0 billion and $5.3 billion at December 31, 1996 and 1995,
respectively. The carrying amounts on the financial statements for
preferred stock subject to mandatory redemption were $510 million and $523
million and for long-term debt were $4.9 billion and $5.1 billion 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.
The carrying amount of the pre-April 1983 spent nuclear fuel disposal
liability approximates the Company's best estimate of its fair value.
<PAGE>
<PAGE>
<TABLE>
9. Federal Income Taxes:
The details of federal income taxes as reported are as follows:
<CAPTION>
Year Ended December 31,
1996 1995 1994
(In Thousands)
Charged (Credited) to Operating Expenses (net):
<S> <C> <C> <C>
Current $375,528 $265,313 $240,655
Deferred (17,008) 22,990 (10,177)
Deferred Investment Tax Credits (16,298) (16,276) (17,079)
Total 342,222 272,027 213,399
Charged (Credited) to Nonoperating Income (net):
Current (5,636) 11,325 (2,907)
Deferred (4,470) (11,074) (5,856)
Deferred Investment Tax Credits (9,510) (9,543) (14,196)
Total (19,616) (9,292) (22,959)
Total Federal Income Tax as Reported $322,606 $262,735 $190,440
The following is a reconciliation of the difference between the amount of federal
incometaxes computed by multiplying book income before federal income taxes by the statutory
tax rate, and the amount of federal income taxes reported.
<CAPTION>
Year Ended December 31,
1996 1995 1994
(In Thousands)
<S> <C> <C> <C>
Income Before Preferred Stock Dividend
Requirements of Subsidiaries $628,856 $584,674 $554,738
Federal Income Taxes 322,606 262,735 190,440
Pre-Tax Book Income $951,462 $847,409 $745,178
Federal Income Tax on Pre-Tax Book
Income at Statutory Rate (35%) $333,012 $296,593 $260,812
Increase (Decrease) in Federal Income
Tax Resulting from the Following Items:
Depreciation 50,537 46,453 31,212
Removal Costs (15,327) (14,640) (13,818)
Corporate Owned Life Insurance (12,009) (25,506) (22,970)
Investment Tax Credits (net) (25,813) (26,179) (31,273)
Federal Income Tax Accrual Adjustments - - (16,100)
Other (7,794) (13,986) (17,423)
Total Federal Income Taxes as Reported $322,606 $262,735 $190,440
Effective Federal Income Tax Rate 33.9% 31.0% 25.6%
</TABLE>
<PAGE>
<PAGE>
<TABLE>
The following tables show the elements of the net deferred tax liability and the significant
temporary differences:
<CAPTION> December 31,
1996 1995
(In Thousands)
<S> <C> <C>
Deferred Tax Assets $ 784,349 $ 723,196
Deferred Tax Liabilities (3,427,492) (3,379,847)
Net Deferred Tax Liabilities $(2,643,143) $ 2,656,651)
Property Related Temporary Differences $(2,162,099) $(2,139,387)
Amounts Due From Customers For Future
Federal Income Taxes (428,698) (442,311)
Deferred State Income Taxes (229,429) (183,981)
All Other (net) 177,083 109,028
Total Net Deferred Tax Liabilities $(2,643,143) $(2,656,651)
</TABLE>
The Company 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 Company
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 $247 million (including interest). AEP 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.
<PAGE>
10. Leases:
Leases of property, plant and equipment are for periods up to 35 years
and require payments of related property taxes, maintenance and operating
costs. The majority of the leases have purchase or renewal options and
will be renewed or replaced by other leases.
Lease rentals are primarily charged to operating expenses in
accordance with rate-making treatment. The components of rentals are as
follows:
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995 1994
(In Thousands)
<S> <C> <C> <C>
Operating Leases $262,451 $259,877 $233,805
Amortization of Capital Leases 114,050 101,068 79,116
Interest on Capital Leases 28,696 27,542 23,280
Total Rental Payments $405,197 $388,487 $336,201
</TABLE>
<PAGE>
<PAGE>
<TABLE>
Properties under capital leases and related obligations on the Consolidated Balance
Sheets are as follows:
<CAPTION> December 31,
1996 1995
(In Thousands)
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production $ 44,390 $ 44,849
Transmission 6 7
Distribution 14,699 14,753
General:
Nuclear Fuel (net of amortization) 59,681 69,442
Mining Plant and Other 466,797 424,952
Total Electric Utility Plant 585,573 554,003
Accumulated Amortization 200,931 179,952
Net Electric Utility Plant 384,642 374,051
OTHER PROPERTY 33,439 34,536
Accumulated Amortization 3,854 3,994
Net Other Property 29,585 30,542
Net Property under Capital Leases $414,227 $404,593
Obligations under Capital Leases $414,227 $404,593
Less Portion Due Within One Year 89,553 89,692
Noncurrent Capital Lease Liability $324,674 $314,901
Properties under operating leases and related obligations are not included in the
Consolidated Balance Sheets.
<CAPTION>
Future minimum lease rentals, consisted of the following at December 31, 1996:
Noncancelable
Capital Operating
Leases Leases
(In Thousands)
<S> <C> <C>
1997 $ 90,813 $ 240,923
1998 73,817 232,903
1999 63,356 230,994
2000 53,027 229,039
2001 41,634 225,733
Later Years 150,278 3,858,008
Total Future Minimum Lease Rentals 472,925 (a) $5,017,600
Less Estimated Interest Element 118,379
Estimated Present Value of Future
Minimum Lease Rentals 354,546
Unamortized Nuclear Fuel 59,681
Total $414,227
(a) Minimum lease rentals do not include nuclear fuel rentals. The rentals are paid in
proportion to heat produced and carrying charges on the unamortized nuclear fuel balance.
There are no minimum lease payment requirements for leased nuclear fuel.
</TABLE>
<PAGE>
<PAGE>
11. SUPPLEMENTARY INFORMATION:
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995 1994
(In Thousands)
<S> <C> <C> <C>
Purchased Power - Ohio Valley Electric Corp.
(44.2% owned by AEP) $22,156 $10,546 $5,755
Cash was paid for:
Interest (net of capitalized amounts) $373,570 $395,169 $379,361
Income Taxes $404,297 $273,671 $312,233
Noncash Acquisitions under
Capital Leases were $136,988 $106,256 $227,055
<CAPTION>
12. CAPITAL STOCKS AND PAID-IN CAPITAL:
Changes in capital stocks and paid-in capital during the period January 1, 1994 through December 31, 1996 were:
Cumulative Preferred Stocks
Shares of Subsidiaries
Cumulative Not Subject Subject to
Common Stock- Preferred Stocks Paid-in To Mandatory Mandatory
Par Value $6.50(a) of Subsidiaries Common Stock Capital Redemption Redemption(b)
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C> <C>
January 1, 1994 193,534,992 7,687,768 $1,257,977 $1,624,176 $ 268,240 $ 500,537
Issuances 700,000 900,000 4,550 17,706 - 90,000
Retirements and Other - (351,517) - (1,221) (35,000) (152)
December 31, 1994 194,234,992 8,236,251 1,262,527 1,640,661 233,240 590,385
Issuances 1,400,000 - 9,100 39,607 - -
Retirements and Other - (1,526,500) - (21,744) (85,000) (67,650)
December 31, 1995 195,634,992 6,709,751 1,271,627 1,658,524 148,240 522,735
Issuances 1,600,000 - 10,400 55,061 - -
Retirements and Other - (707,518) - 1,969 (57,917) (12,835)
December 31, 1996 197,234,992 6,002,233 $1,282,027 $1,715,554 $ 90,323 $509,900
(a) Includes 8,999,992 shares of treasury stock.
(b) Including portion due within one year.
</TABLE>
<PAGE>
<PAGE>
13. Unaudited Quarterly Financial Information:
<TABLE>
<CAPTION>
Quarterly Periods Ended
1996
March 31 June 30 Sept. 30 Dec. 31
(In Thousands - Except
Per Share Amounts)
<S> <C> <C> <C> <C>
Operating Revenues $1,517,781 $1,400,941 $1,484,422 $1,446,090
Operating Income 292,122 220,625 259,745 235,480
Net Income 180,012 112,666 162,324 132,428
Earnings per Share 0.96 0.60 0.87 0.71
<CAPTION>
Quarterly Periods Ended
1995
March 31 June 30 Sept. 30 Dec. 31
(In Thousands - Except
Per Share Amounts)
<S> <C> <C> <C> <C>
Operating Revenues $1,416,169 $1,305,342 $1,523,390 $1,425,429
Operating Income 257,556 211,284 262,548 233,159
Net Income 147,850 96,478 154,156 131,419
Earnings per Share 0.80 0.52 0.83 0.70
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF
SUBSIDIARIES
<CAPTION>
December 31, 1996
Call
Price per Shares Shares Amount (in
Share (a) Authorized(b) Outstanding thousands)
<S> <C> <C> <C> <C>
Not Subject to Mandatory Redemption:
4.08% - 4.56% (c) $102-$110 932,403 903,233 $ 90,323
Subject to Mandatory Redemption (d):
5.90% - 5.92% (c) (e) 1,950,000 1,904,000 $190,400
6.02% - 6-7/8% (c) (f) 1,950,000 1,945,000 194,500
7% - 7-7/8% (c) $107.80-$107.88(g) 1,250,000 1,250,000 125,000
Total Subject to Mandatory
Redemption (h) $509,900
______________________________________________________________________________________________________
<CAPTION>
December 31, 1995
Call
Price per Shares Shares Amount (in
Share (a) Authorized Outstanding thousands)
<S> <C> <C> <C> <C>
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 932,403 $ 93,240
7.08% - 7.40% $101.85-$102.11 550,000 550,000 55,000
Total Not Subject to Mandatory
Redemption $148,240
Subject to Mandatory Redemption (d):
4.50% $102 19,625 2,348 $ 235
5.90% - 5.92% (e) 1,950,000 1,950,000 195,000
6.02% - 6-7/8% (f) 1,950,000 1,950,000 195,000
7% - 7-7/8% $107.80-$107.88(g) 1,250,000 1,250,000 125,000
9.50% (i) 750,000 75,000 7,500
Total Subject to Mandatory
Redemption (h) 522,735
Less Portion Due Within One Year 7,650
Long-term Portion $515,085
NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
(a) At the option of the subsidiary the shares may be redeemed at the call price plus accrued dividends.
The involuntary liquidation preference is $100 per share for all outstanding shares.
(b) As of December 31, 1996 the subsidiaries had 4,708,320, 22,200,000 and 5,801,850 shares of $100, $25
and no par value preferred stock, respectively, that were authorized but unissued.
(c) In January 1997 a tender offer for certain series of preferred stock was announced. In conjunction
with the tender offer a special shareholders meeting is scheduled to be held on February 28, 1997 for the
purpose of considering amendments to the subsidiaries' articles of incorporation to remove certain
capitalization ratio requirements.
(d) With sinking fund. Shares outstanding and related amounts are stated net of applicable retirements
through sinking funds (generally at par) and reacquisitions of shares in anticipation of future
requirements.
(e) Not callable prior to 2003; after that the call price is $100 per share.
(f) Not callable prior to 2000; after that the call price is $100 per share.
(g) Redemption is restricted prior to 1997.
(h) The sinking fund provisions of the series subject to mandatory redemption aggregate $5,000,000,
$5,000,000, $16,000,000 and $16,000,000 in 1998, 1999, 2000 and 2001, respectively.
(i) On February 1, 1996 the outstanding balance of 75,000 shares was redeemed at $100 per share.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
<CAPTION>
Weighted Average
Maturity Interest Rate Interest Rates at December 31, December 31,
December 31, 1996 1996 1995 1996 1995
(in thousands)
<S> <C> <C> <C> <C> <C>
FIRST MORTGAGE BONDS
1996-1999 7.35% 6-1/4%-9.15% 5%-9.15% $ 383,671 $ 496,866
2001-2006 7.10% 6%-8.95% 6%-9.31% 1,511,000 1,530,020
2020-2025 8.07% 7.10%-9.35% 7.10%-9-7/8% 1,276,750 1,473,127
INSTALLMENT PURCHASE CONTRACTS (a)
1998-2002 4.80% 4.10%-7-1/4% 5%-7-1/4% 209,500 209,500
2007-2025 6.45% 5.45%-7-7/8% 5.45%-7-7/8% 756,745 756,745
NOTES PAYABLE (b)
1996-2008 7.31% 5.29%-9.60% 5.29%-10.78% 282,681 221,000
DEBENTURES
1996 - 1999 (c) - - 5-1/8%-7-7/8% - 30,759
2025 - 2026 8.28% 8%-8.72% 8.16%-8.72% 315,000 200,000
OTHER LONG-TERM DEBT (d) 182,943 172,403
Unamortized Discount (net) (34,580) (33,144)
Total Long-term Debt
Outstanding (e) 4,883,710 5,057,276
Less Portion Due Within One Year 86,942 136,947
Long-term Portion $4,796,768 $4,920,329
NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
(a) For certain series of installment purchase contracts interest rates are subject to periodic adjustment.
Certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from banks
and standby bond purchase agreements support certain series.
(b) Notes payable represent outstanding promissory notes issued under term loan agreements with a number of
banks and other financial institutions. At expiration all notes then issued and outstanding are due and
payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term
interest rates.
(c) All sinking fund debentures were reacquired on March 1, 1996.
(d) Other long-term debt consists primarily of a liability along with accrued interest for disposal of spent
nuclear fuel (see Note 4 of the Notes to Consolidated Financial Statements).
(e) Long-term debt outstanding at December 31, 1996 is payable as follows:
Principal Amount (in thousands)
1997 $ 86,942
1998 224,274
1999 210,678
2000 183,652
2001 252,575
Later Years 3,960,169
Total $4,918,290
</TABLE>
<PAGE>
<PAGE>
Management's Responsibility
The management of American Electric Power Company, Inc. is responsible
for the integrity and objectivity of the information and representations in
this annual report, including the consolidated financial statements. These
statements have been prepared in conformity with generally accepted
accounting principles, using informed estimates where appropriate, to
reflect the Company's financial condition and results of operations. The
information in other sections of the annual report is consistent with these
statements.
The Company's Board of Directors has oversight responsibilities for
determining that management has fulfilled its obligation in the preparation
of the financial statements and in the ongoing examination of the Company's
established internal control structure over financial reporting. The Audit
Committee, which consists solely of outside directors and which reports
directly to the Board of Directors, meets regularly with management,
Deloitte & Touche LLP - Certified Public Accountants and the Company's
internal audit staff to discuss accounting, auditing and reporting matters.
To ensure auditor independence, both Deloitte & Touche LLP and the internal
audit staff have unrestricted access to the Audit Committee.
The financial statements have been audited by Deloitte & Touche LLP,
whose report appears on the next page. The auditors provide an objective,
independent review as to management's discharge of its responsibilities
insofar as they relate to the fairness of the Company's reported financial
condition and results of operations. Their audit includes procedures
believed by them to provide reasonable assurance that the financial
statements are free of material misstatement and includes a review of the
Company's internal control structure over financial reporting.
<PAGE>
<PAGE>
Independent Auditors' Report
To the Shareholders and Board of Directors
of American Electric Power Company, Inc.:
We have audited the accompanying consolidated balance sheets of American
Electric Power Company, Inc. 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 American Electric Power
Company, Inc. 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>
<TABLE>
EXHIBIT 21
Subsidiaries of
American Electric Power Company, Inc.
As of January 1, 1997
<CAPTION>
Percentage
of Voting
Securities
Location of Owned By
Name of Company Incorporation Immediate Parent
<S> <S> <C>
American Electric Power Service Corporation New York 100.0
AEP Communications, Inc. Ohio 100.0
AEP Energy Services, Inc.* Ohio 100.0
AEP Energy Solutions, Inc.** Ohio 100.0
AEP Generating Company Ohio 100.0
AEP Investments, Inc. Ohio 100.0
AEP Resources, Inc. Ohio 100.0
AEP Resources Australia Pty., Ltd. Australia 100.0
AEP Resources Delaware, Inc. Delaware 100.0
AEP Resources International, Ltd. Cayman Islands 100.0
AEP Pushan Power, LDC Cayman Islands 99.0 (a)
Nanyang General Light Electric Company, Ltd.People's Republic of China 70.0 (b)
AEP Resources Mauritius Company Mauritius 99.0 (a)
AEP Resources Project Management Company, Ltd. Cayman Islands 100.0
AEP Pushan Power, LDC Cayman Islands 1.0 (a)
Nanyang General Light Electric Company, Ltd.People's Republic of China 70.0 (b)
AEP Resources Mauritius Company Mauritius 1.0 (a)
Appalachian Power Company Virginia 97.8 (c)
Cedar Coal Co. West Virginia 100.0
Central Appalachian Coal Company West Virginia 100.0
Central Coal Company West Virginia 50.0 (d)
Central Operating Company West Virginia 50.0 (d)
Southern Appalachian Coal Company West Virginia 100.0
West Virginia Power Company West Virginia 100.0
Columbus Southern Power Company Ohio 100.0
Colomet, Inc. Ohio 100.0
Conesville Coal Preparation Company Ohio 100.0
Simco Inc. Ohio 100.0
Franklin Real Estate Company Pennsylvania 100.0
Indiana Franklin Realty, Inc. Indiana 100.0
Indiana Michigan Power Company Indiana 100.0
Blackhawk Coal Company Utah 100.0
Price River Coal Company Indiana 100.0
Integrated Communications Systems, Inc. Georgia 13.1 (e)
Kentucky Power Company Kentucky 100.0
Kingsport Power Company Virginia 100.0
Ohio Power Company Ohio 97.3 (f)
Cardinal Operating Company Ohio 50.0 (g)
Central Coal Company West Virginia 50.0 (d)
Central Ohio Coal Company Ohio 100.0
Central Operating Company West Virginia 50.0 (d)
Southern Ohio Coal Company West Virginia 100.0
Windsor Coal Company West Virginia 100.0
Ohio Valley Electric Corporation Ohio 44.2 (h)
Indiana-Kentucky Electric Corporation Indiana 100.0
Wheeling Power Company West Virginia 100.0
* Effective March 7, 1997 name changed to AEP Resources Engineering & Services Company.
** Effective March 7, 1997 name changed to AEP Energy Services, Inc.
(a) Owned 99% by AEP Resources International, Ltd. and 1% by AEP Resources Project
Management Company, Ltd.
(b) AEP Pushan Power LDC owns 70% and the remaining 30% is owned by two unaffiliated
entities.
(c) 13,499,500 shares of Common Stock, all owned by parent, have one vote each and
298,150 shares of Preferred Stock, all owned by public, have one vote each.
(d) Owned 50% by Appalachian Power Company and 50% by Ohio Power Company.
(e) American Electric Power Company, Inc. owns 13.1% of the stock and the remaining
86.9% is owned by unaffiliated companies.
(f) 27,952,473 shares of Common Stock, all owned by parent, have one vote each and
789,316 shares of Preferred Stock, all owned by public, have one vote each.
(g) Ohio Power Company owns 50% of the stock; the other 50% is owned by a corporation not
affiliated with American Electric Power Company, Inc.
(h) American Electric Power Company, Inc. and Columbus Southern Power Company own 39.9%
and 4.3% of the stock, respectively, and the remaining 55.8% is owned by unaffiliated
companies.
</TABLE>
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Post-Effective
Amendment No. 3 to Registration Statement No. 33-01052 of American
Electric Power Company, Inc. on Form S-8 and Post-Effective
Amendment No. 1 to Registration Statement No. 33-01734 of American
Electric Power Company, Inc. 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 American Electric Power Company,
Inc. for the year ended December 31, 1996.
Deloitte & Touche LLP
Columbus, Ohio
March 25, 1997
Exhibit 24
POWER OF ATTORNEY
AMERICAN ELECTRIC POWER COMPANY, INC.
Annual Report on Form lO-K for the Fiscal Year Ended
December 31, 1996
The undersigned director of AMERICAN ELECTRIC POWER COMPANY,
INC., a New York corporation (the "Company"), does hereby consti-
tute and appoint E. LINN DRAPER, JR., G. P. MALONEY and P. J.
DeMARIA, and each of them, his attorneys-in-fact and agents, to
execute for him, and in his name, and in any and all of his
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 has signed these presents
this 18th day of December, 1996.
/s/ Robert W. Fri
-------------------------------
Robert W. Fri
Exhibit 24
POWER OF ATTORNEY
AMERICAN ELECTRIC POWER COMPANY, INC.
Annual Report on Form lO-K for the Fiscal Year Ended
December 31, 1996
The undersigned directors of AMERICAN ELECTRIC POWER COMPANY,
INC., a New York 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/ Angus E. Peyton
- ------------------------------ -------------------------------
E. Linn Draper, Jr. Angus E. Peyton
/s/ Robert M. Duncan /s/ Donald G. Smith
- ------------------------------ -------------------------------
Robert M. Duncan Donald G. Smith
/s/ Arthur G. Hansen /s/ Linda Gillespie Stuntz
- ------------------------------ -------------------------------
Arthur G. Hansen Linda Gillespie Stuntz
/s/ Lester A. Hudson, Jr. /s/ Morris Tanenbaum
- ------------------------------ -------------------------------
Lester A. Hudson, Jr. Morris Tanenbaum
/s/ Leonard J. Kujawa /s/ Ann Haymond Zwinger
- ------------------------------ -------------------------------
Leonard J. Kujawa Ann Haymond Zwinger
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000004904
<NAME> AMERICAN ELECTRIC POWER COMPANY, INC.
<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> 11,420,371
<OTHER-PROPERTY-AND-INVEST> 892,674
<TOTAL-CURRENT-ASSETS> 1,354,881
<TOTAL-DEFERRED-CHARGES> 328,139
<OTHER-ASSETS> 1,889,482
<TOTAL-ASSETS> 15,885,547
<COMMON> 1,282,027
<CAPITAL-SURPLUS-PAID-IN> 1,715,554
<RETAINED-EARNINGS> 1,547,746
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4,545,327
509,900
90,323
<LONG-TERM-DEBT-NET> 4,796,768
<SHORT-TERM-NOTES> 91,293
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 228,402
<LONG-TERM-DEBT-CURRENT-PORT> 86,942
0
<CAPITAL-LEASE-OBLIGATIONS> 324,674
<LEASES-CURRENT> 89,553
<OTHER-ITEMS-CAPITAL-AND-LIAB> 5,122,365
<TOT-CAPITALIZATION-AND-LIAB> 15,885,547
<GROSS-OPERATING-REVENUE> 5,849,234
<INCOME-TAX-EXPENSE> 365,305
<OTHER-OPERATING-EXPENSES> 4,475,957
<TOTAL-OPERATING-EXPENSES> 4,841,262
<OPERATING-INCOME-LOSS> 1,007,972
<OTHER-INCOME-NET> 2,212
<INCOME-BEFORE-INTEREST-EXPEN> 1,010,184
<TOTAL-INTEREST-EXPENSE> 381,328
<NET-INCOME> 587,430
41,426<F1>
<EARNINGS-AVAILABLE-FOR-COMM> 587,430
<COMMON-STOCK-DIVIDENDS> 449,353
<TOTAL-INTEREST-ON-BONDS> 250,063
<CASH-FLOW-OPERATIONS> 1,237,062
<EPS-PRIMARY> $3.14
<EPS-DILUTED> $3.14
<FN>
<F1>Represents preferred stock dividend requirements of
subsidiaries; deducted before computation of net income.
</FN>
</TABLE>
