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(b)
INDIANA MICHIGAN POWER COMPANY
ARTICLES OF AMENDMENT
TO THE
AMENDED ARTICLES OF ACCEPTANCE, AS AMENDED
1. The name of the corporation is INDIANA MICHIGAN POWER
COMPANY.
2. The Amendment adopted is to remove in its entirety ARTICLE 6A,
Clause 7(B)(c) from the Amended Articles of Acceptance,as amended.
3. On January 30, 1997, notice of the meeting, accompanied
by a copy of the Amendment, was given in the manner provided in the
Indiana Code to each of the Corporation's shareholders of record. The
foregoing Amendment was adopted by the shareholders of the Corporation
on February 28, 1997.
4. On January 29, 1997, the foregoing Amendment was proposed by
the Board of Directors of the Corporation, which found adoption of the
Amendment to be in the Corporation's best interest and directed that
it be submitted to the shareholders of the Corporation for their approval
at a special meeting on February 28,1997.
5. Holders of the shares of the Corporation's common stock
and preferred stock were eligible to vote separately as a class in
the adoption of the Amendment. The number of shares of common stock
and preferred stock voted for the Amendment was sufficient to approve
the Amendment. The designation, the number of outstanding shares on
the record date, the number of votes entitled to be cast by each voting
group entitled to vote separately on the foregoing Amendment and the
undisputed number of votes cast for, against and abstaining from the
Amendment were as follows:
<TABLE>
Entitled
Class Outstanding to Vote For Against Abstain
<S> <C> <C> <C> <C> <C>
Cumulative
Preferred
Stock, par
value $100
per share 1,569,767 1,569,767 1,210,512 93,188 1,146
Common Stock
no par value 1,400,000 1,400,000 1,400,000 -0- -0-
</TABLE>
INDIANA MICHIGAN POWER COMPANY
By_/s/ John M. Adams, Jr.
John M. Adams, Jr.
Assistant Secretary
March 6, 1997
EXHIBIT 3(c)
[COMPOSITE]
AMENDED ARTICLES OF ACCEPTANCE
OF
INDIANA MICHIGAN POWER COMPANY
1. The name of this Corporation shall be INDIANA MICHIGAN
POWER COMPANY.
2. The purpose or purposes of the Corporation are as
follows:
I. To generate and produce electricity and to transmit,
sell and distribute the same to the public, either directly or
through the sale of electric energy to other utilities, within
and without the States of Indiana and Michigan.
II. To engage in the business of mining coal and other
minerals or substances; to purchase, lease and otherwise
acquire coal lands, mines and the products thereof; to mine,
produce, store, sell and transport coal and other minerals or
substances and, to accomplish such purposes, to take, hold and
own real estate or interests therein, including leases,
permits or licenses granted under the provisions of the
Mineral Leasing Act of February 25, 1920, as amended, and to
own, operate and maintain such machinery, works, equipment and
appliances as the carrying out of the objects above mentioned
may require.
III. To transact any or all lawful business for which
corporations may be incorporated under the Indiana General
Corporation Act.
3. The period during which it is to continue as a
corporation is unlimited.
4. The post office address of its principal office is One
Summit Square, P. O. Box 60, Ft. Wayne, Indiana 46801. The name
and post office address of its resident agent is Elio Bafile, One
Summit Square, P. O. Box 60, Ft. Wayne, Indiana 46801.
5. The total number of shares into which its authorized
capital stock is to be divided is 15,950,000 shares, consisting of
shares as follows:
2,250,000 shares having a par value of $100;
11,200,000 shares having a par value of $25; and
2,500,000 shares without par value.
6. The number of shares of the capital stock of the
Corporation is to be divided into two classes, consisting of: (a)
two million five hundred thousand (2,500,000) shares, without
nominal or par value, of Common Stock and (b) two million two
hundred fifty thousand (2,250,000) shares, of the par value of $100
each, and eleven million two hundred thousand (11,200,000) shares,
of the par value of $25 each, of Cumulative Preferred Stock, which
may be issued in series as hereinafter provided. The voting
powers, designations, preferences, relative, participating,
optional or other special rights, qualifications, limitations or
restrictions of the above classes of stock, and the power of the
Board of Directors to cause the Cumulative Preferred Stock to be
issued in series, and the designation, description and terms of the
series of Cumulative Preferred Stock heretofore created, are as
follows:
A. Cumulative Preferred Stock
(1) Subject to and in accordance with the provisions of
this paragraph and the following paragraphs (2) through (28)
hereof, the Board of Directors is hereby empowered to cause
the Cumulative Preferred Stock to be issued in different
series. The shares of different series may vary, as may be
determined by the Board of Directors prior to the issue
thereof (except in the case of the series of Cumulative
Preferred Stock classified and designated in paragraphs (9)
through (28) hereof), as to:
(a) The distinctive serial designation and number
of shares of such series;
(b) The rate of dividends (within such limits as
shall be permitted by law) payable on the shares of the
particular series;
(c) The prices (not less than the amount limited by
law) and terms upon which the shares of the particular
series may be redeemed;
(d) The amount or amounts which shall be paid to
the holders of the shares of the particular series in
case of voluntary or involuntary dissolution or any
distribution of assets;
(e) The terms and amount of sinking fund
requirements (if any) for the purchase or redemption of
the shares of the particular series.
The shares of all series of the Cumulative Preferred Stock
shall in all other respects be equal, except as to the par
value thereof and the voting rights with respect thereto as
hereinafter provided.
(2) The holders of each series of the Cumulative
Preferred Stock at the time outstanding shall be entitled to
receive, but only when and as declared by the Board of
Directors, out of funds legally available for the payment of
dividends, cumulative preferential dividends, at the annual
dividend rate for the particular series fixed as herein
provided, payable quarter-yearly on dates to be fixed by the
Board of Directors, to stockholders of record on the
respective dates, not exceeding thirty (30) days and not less
than ten (10) days preceding such dividend payment dates, to
be fixed by the Board of Directors. Where the dividend rate
of any series of the Cumulative Preferred Stock with a par
value of $100 per share is designated as a specified
percentage per annum, the holders of such series shall be
entitled to receive annually dividends thereon calculated, per
share, at the percentage specified for such series multiplied
by $100. No dividends shall be declared on any series of the
Cumulative Preferred Stock in respect of any quarter-yearly
dividend period unless there shall likewise be declared on all
shares of all series of the Cumulative Preferred Stock at the
time outstanding, like proportionate dividends, ratably, in
proportion to the respective annual dividend rates fixed
therefor, in respect of the same quarter-yearly dividend
period, to the extent that such shares are entitled to receive
dividends for such quarter-yearly dividend period. The
dividends on shares of all series of the Cumulative Preferred
Stock shall be cumulative. In the case of all shares of each
particular series, the dividends on shares of such series
shall be cumulative from the date of issue thereof unless the
Corporation shall have established regular quarter-yearly
dividend periods with respect to such series, in which case
such dividends shall be cumulative from the first day of the
current quarter-yearly dividend period in which shares of such
series shall have been issued. Unless dividends on all
outstanding shares of each series of the Cumulative Preferred
Stock, at the annual dividend rate and from the dates for
accumulation thereof fixed as herein provided, shall have been
paid for all past quarter-yearly dividend periods, but without
interest on cumulative dividends, no dividends shall be paid
or declared and no other distribution shall be made on the
Common Stock, and no Common Stock shall be purchased or
otherwise acquired for value by the Corporation. The holders
of the Cumulative Preferred Stock of any series shall not be
entitled to receive any dividends thereon other than the
dividends referred to in this paragraph (2).
(3) The Corporation, by action of its Board of
Directors, may redeem the whole or any part of any series of
the Cumulative Preferred Stock, at any time or from time to
time, by paying in cash the redemption price of the shares of
the particular series, fixed therefor as herein provided,
together with a sum in the case of each share of each series
so to be redeemed, computed at the annual dividend rate for
the series of which the particular share is a part, from the
date from which dividends on such share became cumulative to
the date fixed for such redemption, less the aggregate of the
dividends theretofore or on such redemption date paid thereon.
Notice of every such redemption shall be given by publication
at least once in one daily newspaper printed in the English
language and of general circulation in Fort Wayne, Indiana,
and in one daily newspaper printed in the English language and
of general circulation in the Borough of Manhattan, The City
of New York, the first publication in such newspapers to be at
least thirty (30) days and not more than sixty (60) days prior
to the date fixed for such redemption. At least thirty (30)
days' and not more than sixty (60) days' previous notice of
every such redemption shall also be mailed to the holders of
record of the shares of the Cumulative Preferred Stock so to
be redeemed, at their respective addresses as the same shall
appear on the books of the Corporation; but no failure to mail
such notice nor any defect therein or in the mailing thereof
shall affect the validity of the proceedings for the
redemption of any shares of the Cumulative Preferred Stock so
to be redeemed. In case of the redemption of a part only of
any series of the Cumulative Preferred Stock at the time
outstanding, the Corporation shall select by lot the shares so
to be redeemed. The Board of Directors shall have full power
and authority, subject to the limitations and provisions
herein contained, to prescribe the manner in which, and the
terms and conditions upon which, the shares of the Cumulative
Preferred Stock shall be redeemed from time to time. If such
notice of redemption shall have been duly given by
publication, and if on or before the redemption date specified
in such notice all funds necessary for such redemption shall
have been set aside by the Corporation, separate and apart
from its other funds, in trust for the account of the holders
of the shares to be redeemed, so as to be and continue to be
available therefor, then, notwithstanding that any certificate
for such shares so called for redemption shall not have been
surrendered for cancellation, from and after the date fixed
for redemption, the shares represented thereby shall no longer
be deemed outstanding, the right to receive dividends thereon
shall cease to accrue and all rights with respect to such
shares so called for redemption shall forthwith on such
redemption date cease and terminate, except only the right of
the holders thereof to receive, out of the funds so set aside
in trust, the amount payable upon redemption thereof, without
interest; provided, however, that the Corporation may, after
giving notice by publication of any such redemption as
hereinbefore provided or after giving to the bank or trust
company hereinafter referred to irrevocable authorization to
give such notice by publication, and at any time prior to the
redemption date specified in such notice, deposit in trust,
for the account of the holders of the shares to be redeemed,
so as to be and continue to be available therefor, funds
necessary for such redemption with a bank or trust company in
good standing, organized under the laws of the United States
of America or of the State of New York, doing business in the
Borough of Manhattan, The City of New York, and having
capital, surplus and undivided profits aggregating at least
$50,000,000, or a bank or trust company in good standing
organized under the laws of the State of Indiana, doing
business in Fort Wayne, Indiana, selected by the Board of
Directors of the Corporation and designated in such notice of
redemption, and, upon such deposit in trust, all shares with
respect to which such deposits shall have been made shall no
longer be deemed to be outstanding, and all rights with
respect to such shares shall forthwith cease and terminate,
except only the right of the holders thereof to receive at any
time from and after the date of such deposit, the amount
payable upon the redemption thereof, without interest.
Nothing herein contained shall limit any right of the
Corporation to purchase or otherwise acquire any shares of the
Cumulative Preferred Stock; provided, however, that the
Corporation shall not redeem, purchase or otherwise acquire
any shares of the Cumulative Preferred Stock, if, at the time
of such redemption, purchase or other acquisition, dividends
payable on the Cumulative Preferred Stock of any Series of any
series shall be in default in whole or in part, unless, prior
to or concurrently with such redemption, purchase or other
acquisition, all such defaults shall be cured or unless such
redemption, purchase or other acquisition shall have been
ordered, approved or permitted by the Securities and Exchange
Commission, or by a successor commission or other regulatory
authority of the United States of America having jurisdiction
in the premises, under the provisions of the Public Utility
Holding Company Act of 1935 as at the time in effect or any
legislation enacted in substitution therefor.
(4) Before any amount shall be paid to, or any assets
distributed among, the holders of the Common Stock upon any
liquidation, dissolution or winding up of the Corporation, and
after paying or providing for the payment of all creditors of
the Corporation, the holders of each series of the Cumulative
Preferred Stock at the time outstanding shall be entitled to
be paid in cash the amount for the particular series fixed
therefor as herein provided, together with a sum in the case
of each share of each series, computed at the annual dividend
rate for the series of which the particular share is a part,
from the date from which dividends on such share became
cumulative to the date fixed for the payment of such
distributive amount, less the aggregate of the dividends
theretofore or on such date paid thereon; but no payments on
account of such distributive amounts shall be made to the
holders of any series of the Cumulative Preferred Stock unless
there shall likewise be paid at the same time to the holders
of each other series of the Cumulative Preferred Stock at the
time outstanding like proportionate distributive amounts,
ratably, in proportion to the full distributive amounts to
which they are respectively entitled as herein provided. The
holders of the Cumulative Preferred Stock of any series shall
not be entitled to receive any amounts with respect thereto
upon any liquidation, dissolution or winding up of the
Corporation other than the amounts referred to in this para-
graph. Neither the consolidation or merger of the Corporation
with any other corporation or corporations, nor the sale or
transfer by the Corporation of all or any part of its assets,
shall be deemed to be liquidation, dissolution or winding up
of the Corporation.
(5) Whenever the full dividends on all series of the
Cumulative Preferred Stock at the time outstanding for all
past quarter-yearly dividend periods shall have been paid or
declared and set apart for payment, then, subject to the
provisions of subparagraph (7)(B)(d) hereof, such dividends
(payable in cash, stock or otherwise) as may be determined by
the Board of Directors may be declared and paid on the Common
Stock, but only out of funds legally available for the payment
of dividends; provided, however, that so long as any shares of
the Cumulative Preferred Stock of any series are outstanding,
the Corporation shall not declare or pay any dividends on the
Common Stock of the Corporation except as follows:
(a) If and so long as the Common Stock Equity at
the end of the calendar month immediately preceding the
date on which a dividend on Common Stock is declared is,
or as a result of such dividend would become, less than
20% of total capitalization, the Corporation shall not
declare such dividend in an amount which, together with
all other dividends on Common Stock paid within the year
ending with and including the date on which such dividend
is payable, exceeds 50% of the net income of the
Corporation available for dividends on the Common Stock
(less any Depreciation Deficiency) for the twelve full
calendar months immediately preceding the month in which
such dividend is declared, except in an amount not
exceeding the aggregate of dividends on Common Stock
which could have been, but have not been, declared under
this clause (a); and
(b) If and so long as the Common Stock Equity at
the end of the calendar month immediately preceding the
date on which a dividend on Common Stock is declared is,
or as a result of such dividend would become, less than
25% but not less than 20% of total capitalization, the
Corporation shall not declare such dividend in an amount
which, together with all other dividends on Common Stock
paid within the year ending with and including the date
on which such dividend is payable, exceeds 75% of the net
income of the Corporation available for dividends on the
Common Stock (less any Depreciation Deficiency) for the
twelve full calendar months immediately preceding the
month in which such dividend is declared, except in an
amount not exceeding the aggregate of dividends on Common
Stock which could have been, but have not been, declared
under clause (a) above and this clause (b); and
(c) At any time when the Common Stock Equity is 25%
or more of total capitalization, the Corporation may not
declare dividends on shares of the Common Stock which
would reduce the Common Stock Equity below 25% of total
capitalization, except to the extent provided in clause
(a) and clause (b) above.
For the purposes of this paragraph (5) only:
(i) The term "Common Stock Equity" shall
mean the sum of the par value of, or stated value
or capital represented by, the shares of Common
Stock of the Corporation outstanding, and the
surplus, earned, capital, and paid-in, of the
Corporation (including any premiums on Common Stock
but excluding any premiums on the Cumulative
Preferred Stock) whether or not available for the
payment of dividends on the Common Stock; provided,
however, that there shall be deducted from such sum
(I) the amount of any Depreciation Deficiency for
the period from December 31, 1952 to the end of the
calendar month immediately preceding the date on
which a dividend on Common Stock is declared and
(II) the amount, if any, by which the aggregate of
all amounts payable upon the involuntary
dissolution, liquidation or winding up of the
Corporation to the holders of the Cumulative
Preferred Stock and of any other class of stock
ranking prior to or on a parity with the Cumulative
Preferred Stock as to dividends or distributions
exceeds the aggregate of the capital of the
Corporation applicable to such Cumulative Preferred
Stock and class of stock ranking prior to or on a
parity with the Cumulative Preferred Stock as to
dividends or distributions;
(ii) The term "total capitalization" shall
mean the sum of the par value of, or stated value
or capital represented by, the capital stock of all
classes of the Corporation outstanding, the
surplus, earned, capital and paid-in, of the
Corporation (including any premiums on any such
capital stock), whether or not available for the
payment of dividends on the Common Stock, and the
principal amount of all debt of the Corporation
outstanding, maturing more than twelve months after
the date of the determination of the total
capitalization, less any amount required to be
deducted in the determination of Common Stock
Equity as in clause (i) above provided;
(iii) The term "dividends on Common Stock"
shall embrace dividends on Common Stock of the
Corporation (other than dividends payable only in
shares of such Common Stock), distributions on, and
purchases or other acquisitions for value of any
Common Stock of the Corporation; and
(iv) The term "Depreciation Deficiency" shall
mean, as to any specified period, the amount by
which the aggregate of (I) all amounts credited to
the depreciation reserve account of the Corporation
through charges to operating revenue deductions or
otherwise as provided in the Uniform System of
Accounts prescribed for Public Utilities and
Licensees by the Federal Energy Regulatory
Commission and of (II) all charges for maintenance,
shall have been less than 15% of all operating
revenues of the Corporation (excluding therefrom
non-operating income and revenues derived directly
from properties leased to the Corporation), less
all charges to income made by the Corporation for
purchased power and for the net amount of electric
energy received by the Corporation through
interchange.
(6) In the event of any liquidation, dissolution or
winding up of the Corporation, all assets and funds of the
Corporation remaining after paying or providing for the
payment of all creditors of the Corporation, and after paying
or providing for the payment to the holders of shares of all
series of the Cumulative Preferred Stock of the full
distributive amounts to which they are respectively entitled
as herein provided, shall be divided among and paid to the
holders of the Common Stock according to their respective
rights and interests.
(7)(A) So long as any shares of the Cumulative Preferred
Stock of any series are outstanding, the Corporation shall
not, without the consent (given by vote at a meeting called
for that purpose) of the holders of such shares entitled to
cast at least two-thirds of the total number of votes which
holders of the Cumulative Preferred Stock then outstanding are
entitled to cast:
(a) Create, authorize or issue any stock (other
than a series of the Cumulative Preferred Stock) ranking
prior to or on a parity with the Cumulative Preferred
Stock as to dividends or distributions, or any obligation
or security convertible into shares of any such stock;
provided, however, that any such stock, obligation or
security (other than stock issued in connection with the
conversion of any such obligation or security) shall not
be issued except within a period of 180 days after the
meeting at which consent to the issuance thereof shall be
given; or
(b) Amend, alter, change or repeal any of the
express terms of the Cumulative Preferred Stock or of any
series of the Cumulative Preferred Stock then outstanding
in a manner substantially prejudicial to the holders
thereof; provided, however, that if any such amendment,
alteration, change or repeal would be substantially
prejudicial to the holders of one or more, but not all,
of the series of the Cumulative Preferred Stock at the
time outstanding, only such consent of the holders of
two-thirds of the total number of shares of all series
prejudicially affected shall be required.
(B) So long as any shares of the Cumulative Preferred
Stock of any series are outstanding, the Corporation shall
not, without the consent (given by vote at a meeting called
for that purpose) of the holders of such shares entitled to
cast a majority of the total number of votes which holders of
the Cumulative Preferred Stock then outstanding are entitled
to cast:
(a) Increase the total authorized amount of the
Cumulative Preferred Stock; or
(b) Merge or consolidate with or into any other
corporation or corporations, unless such merger or
consolidation, or the issuance and assumption of all
securities to be issued or assumed in connection with any
such merger or consolidation, shall have been ordered,
approved, or permitted by the Securities and Exchange
Commission, or by any successor commission or regulatory
authority of the United States of America having juris-
diction in the premises, under the provisions of the
Public Utility Holding Company Act of 1935 as at the time
in effect or any legislation enacted in substitution
therefor, provided that the provisions of this clause (b)
shall not apply to a purchase or other acquisition by the
Corporation of franchises or assets of another
corporation in any manner which does not involve a merger
or consolidation; or
(c) Issue, sell or otherwise dispose of any shares
of the Cumulative Preferred Stock unless (i) the net
income of the Corporation, determined in accordance with
generally accepted accounting practices to be available
for the payment of dividends for a period of twelve (12)
consecutive calendar months within the fifteen (15)
calendar months immediately preceding the issuance, sale
or disposition of such stock (but less any Depreciation
Deficiency for said period), shall have been at least
equal to twice the annual dividend requirements on all
outstanding shares of the Cumulative Preferred Stock,
including the shares proposed to be issued; (ii) the
gross income of the Corporation for said period,
determined in accordance with generally accepted
accounting practices (but in any event after deducting
the amount for said period charged by the Corporation on
its books to depreciation expense and in addition thereto
any Depreciation Deficiency for said period) to be
available for the payment of interest, shall have been at
least one and one-half times the sum of (I) the annual
interest charges on all interest bearing indebtedness of
the Corporation and (II) the annual dividend requirements
on all outstanding shares of the Cumulative Preferred
Stock and of all other classes of stock ranking prior to
or on a parity with the Cumulative Preferred Stock as to
dividends or distributions, including the shares proposed
to be issued; and (iii) the aggregate of the capital of
the Corporation applicable to the Common Stock and of the
surplus of the Corporation immediately after such
issuance, sale or other disposition, less any
Depreciation Deficiency for the period from December 31,
1952 to such date, shall be not less than the amount
payable upon the involuntary dissolution, liquidation or
winding up of the Corporation to the holders of the
Cumulative Preferred Stock, excluding from the foregoing
computation all stock which is to be retired in
connection with such additional issue; provided, that the
Corporation shall not thereafter pay any dividends on the
Common Stock unless immediately thereafter the aggregate
of the capital of the Corporation applicable to the
Common Stock and of the surplus of the Corporation, less
than Depreciation Deficiency for the period from December
31, 1952 to such date, shall be not less than the amount
payable upon the involuntary dissolution, liquidation or
winding up of the Corporation to the holders of the
Cumulative Preferred Stock.
For the purposes of this subparagraph (c) only, the
term "Depreciation Deficiency" shall mean, as to any
specified period, the amount by which the aggregate of
(i) all amounts credited to the depreciation reserve
account of the Corporation through charges to operating
revenue deductions or otherwise as provided in the
Uniform System of Accounts prescribed for Public
Utilities and Licensees by the Federal Energy Regulatory
Commission and of (ii) all charges for maintenance, shall
have been less than 15% of all operating revenues of the
Corporation (excluding therefrom non-operating income and
revenues derived directly from properties leased to the
Corporation), less all charges to income made by the
Corporation for purchased power and for the net amount of
electric energy received by the Corporation through
interchange.
(8)(A) Every holder of the Common Stock shall have one
vote for each share of Common Stock held by him, for the
election of Directors and upon all other matters, except as
otherwise provided in this paragraph (8) hereof. No holder of
the Cumulative Preferred Stock shall be entitled to vote at
any meeting of stockholders or at any election of the
Corporation or otherwise to participate in any action taken by
the Corporation or the stockholders thereof, except for those
purposes, if any, for which said right to vote or otherwise to
participate cannot be denied or waived under the laws of the
State of Indiana and except as otherwise provided in
paragraphs (7), (8) and (10)(c) hereof. Whenever the holders
of the Cumulative Preferred Stock shall be entitled to vote as
a class for the election of Directors or on any other matter,
the holders of shares of Cumulative Preferred Stock with a par
value of $100 per share shall be entitled to cast one vote for
each such share and the holders of shares of Cumulative
Preferred Stock with a par value of $25 per share shall be
entitled to cast one-quarter of one vote for each such share.
(B) If and when dividends payable on the Cumulative
Preferred Stock shall be in default in any amount equivalent
to four full quarter-yearly dividends on all shares of all
series of the Cumulative Preferred Stock at the time
outstanding, and until all dividends in default on the
Cumulative Preferred Stock shall have been paid, the holders
of all shares of the Cumulative Preferred Stock, voting
separately as one class, shall be entitled to elect the
smallest number of Directors necessary to constitute a
majority of the full Board of Directors, and the holders of
the Common Stock, voting separately as a class, shall be
entitled to elect the remaining Directors of the Corporation.
The terms of office of all persons who may be Directors of the
Corporation at the time shall terminate upon the election of
a majority of the Board of Directors by the holders of the
Cumulative Preferred Stock, except that if the holders of the
Common Stock shall not have elected the remaining Directors of
the Corporation, then, and only in that event, the Directors
of the Corporation in office just prior to the election of a
majority of the Board of Directors by the holders of the
Cumulative Preferred Stock shall elect the remaining Directors
of the Corporation.
(C) If and when all dividends then in default on the
Cumulative Preferred Stock at the time outstanding shall be
paid (and such dividends shall be declared and paid out of any
funds legally available therefor as soon as reasonably
practicable), the Cumulative Preferred Stock shall thereupon
be divested of any special right with respect to the election
of Directors provided in subparagraph (B) hereof, and the
voting power of the Common Stock shall revert to the status
existing before the occurrence of such default; but always
subject to the same provisions for vesting such special rights
in the Cumulative Preferred Stock in case of further like
default or defaults in dividends thereon. Upon the
termination of any such special right the terms of office of
all persons who may have been elected Directors of the
Corporation by vote of the holders of the Cumulative Preferred
Stock, as a class, pursuant to such special right shall
forthwith terminate.
(D) In case of any vacancy in the Board of Directors
occurring among the Directors elected by the holders of the
Cumulative Preferred Stock, as a class, pursuant to subpara-
graph (B) hereof, such vacancy shall be filled by the vote of
a majority of the remaining Directors (or by the remaining
Director if there be but one) elected by the holders of the
Cumulative Preferred Stock. In case of a vacancy in the Board
of Directors occurring among the Directors elected otherwise
than by the holders of the Cumulative Preferred Stock, such
vacancy shall be filled by the vote of a majority of the
remaining Directors (or by the remaining Director if there be
but one) elected otherwise than by the holders of the
Cumulative Preferred Stock.
(E) Whenever the holders of the Cumulative Preferred
Stock, as a class, become entitled to elect Directors of the
Corporation pursuant to subparagraph (B) hereof, it shall be
the duty of the president, a vice president or the secretary
of the Corporation forthwith to call, and to cause notice to
be given to the stockholders entitled to vote at, a meeting to
be held at such time as the Corporation's officers may fix,
not less than thirty nor more than sixty days after the
accrual of such right, for the purpose of electing Directors.
The notice so given shall be mailed to each holder of record
of the Cumulative Preferred Stock at such address as appears
upon the records of the Corporation and shall set forth, among
other things, (i) that by reason of the fact that dividends
payable on the Cumulative Preferred Stock are in default in an
amount equivalent to four full quarter-yearly dividends, the
holders of the Cumulative Preferred Stock, voting separately
as a class, have the right to elect the smallest number of
Directors necessary to constitute a majority of the full Board
of Directors of the Corporation, (ii) that any holder of the
Cumulative Preferred Stock has the right, at any reasonable
time, to inspect, and make copies of, the list or lists of
holders of the Cumulative Preferred Stock maintained at the
principal office of the Corporation or at the office of any
Transfer Agent of the Cumulative Preferred Stock, and (iii)
either the entirety of this paragraph or the substance thereof
with respect to the number of shares of the Cumulative
Preferred Stock required to be represented at any meeting, or
adjournment thereof, called for the election of Directors of
the Corporation. At the first meeting of stockholders held
for the purpose of electing Directors during such time as the
holders of the Cumulative Preferred Stock shall have the
special right, voting separately as a class, to elect
Directors, the presence in person or by proxy of the holders
of a majority of the outstanding shares of Common Stock shall
be required to constitute a quorum of such class for the
election of Directors, and the presence in person or by proxy
of the holders of shares entitled to cast a majority of the
votes which holders of the outstanding Cumulative Preferred
Stock are entitled to cast shall be required to constitute a
quorum of such class for the election of Directors; provided,
however, that in the absence of a quorum of the holders of the
Cumulative Preferred Stock, no election of Directors shall be
held, but a majority of the holders of the Cumulative
Preferred Stock who are present in person or by proxy shall
have power to adjourn the election of the Directors to a date
not less than fifteen nor more than fifty days from the giving
of the notice of such adjourned meeting hereinafter provided
for; and provided, further, that at such adjourned meeting,
the presence in person or by proxy of the holders of shares
entitled to cost 35% of the total number of votes which
holders of the outstanding Cumulative Preferred Stock are
entitled to cast shall be required to constitute a quorum of
such class for the election of Directors. In the event such
first meeting of stockholders shall be so adjourned, it shall
be the duty of the president, a vice president or the
secretary of the Corporation, within ten days from the date on
which such first meeting shall have been adjourned, to cause
notice of such adjourned meeting to be given to the
stockholders entitled to vote thereat, such adjourned meeting
to be held not less than fifteen days nor more than fifty days
from the giving of such second notice. Such second notice
shall be given in the form and manner hereinabove provided for
with respect to the notice required to be given of such first
meeting of stockholders, and shall further set forth that a
quorum was not present at such first meeting and that the
holders of shares entitled to cast 35% of the total number of
votes which holders of the outstanding Cumulative Preferred
Stock are entitled to cast shall be required to constitute a
quorum of such class for the election of Directors at such
adjourned meeting. If the requisite quorum of holders of the
Cumulative Preferred Stock shall not be present at said
adjourned meeting, then the Directors of the Corporation then
in office shall remain in office until the next Annual Meeting
of the Corporation, or special meeting in lieu thereof, and
until their successors shall have been elected and shall
qualify. Neither such first meeting nor such adjourned
meeting shall be held on a date within sixty days of the date
of the next Annual Meeting of the Corporation or special
meeting in lieu thereof. At each Annual Meeting of the
Corporation, or special meeting in lieu thereof, held during
such time as the holders of the Cumulative Preferred Stock,
voting separately as a class, shall have the right to elect a
majority of the Board of Directors, the foregoing provisions
of this subparagraph shall govern such Annual Meeting, or
special meeting in lieu thereof, as if said Annual Meeting or
special meeting were the first meeting of stockholders held
for the purpose of electing Directors after the right of the
holders of the Cumulative Preferred Stock, voting separately
as a class, to elect a majority of the Board of Directors,
should have accrued, with the exception that, until the
holders of the Cumulative Preferred Stock shall have elected
a majority of the Board of Directors, if at any adjourned
Annual Meeting, or special meeting in lieu thereof, holders of
shares entitled to cast 35% of the total number of votes which
holders of the outstanding Cumulative Preferred Stock are
entitled to cast are not present in person or by proxy, all
the Directors to be elected shall be elected by a vote of the
holders of a majority of the shares of Common Stock of the
Corporation present or represented at the meeting.
(F) Except when some mandatory provision of law shall
be controlling and except as otherwise provided in
subparagraph (7)(A)(b) hereof, whenever shares of two or more
series of the Cumulative Preferred Stock are outstanding, no
particular series of the Cumulative Preferred Stock shall be
entitled to vote as a separate series on any matter and all
shares of the Cumulative Preferred Stock of all series shall
be deemed to constitute but one class for any purpose for
which a vote of the stockholders of the Corporation by classes
may now or hereafter be required.
(9) The Corporation hereby classifies $12,000,000 par
value of the Cumulative Preferred Stock as a series of such
Cumulative Preferred Stock which shall be designated as "4-
1/8% Cumulative Preferred Stock", consisting of 120,000 shares
of the par value of $100 per share.
(10) The preferences, rights, qualifications, limitations
and restrictions of the shares of the 4-1/8% Cumulative
Preferred Stock, in the respects in which the shares of such
series may vary from shares of other series of the Cumulative
Preferred Stock, shall be as follows:
(a) The annual dividend rate for such series shall
be 4-1/8% per annum;
(b) The redemption price for such series shall be
$108.125 per share until October 1, 1949, and on and
after October 1, 1949, $106.125 per share;
(c) The preferential amounts to which the holders
of shares of such series shall be entitled upon any
liquidation, dissolution or winding up of the Corporation
shall be:
$105.125 per share, upon any voluntary liquidation,
dissolution or winding up of the Corporation, except that
if such voluntary liquidation, dissolution or winding up
of the Corporation shall have been approved by the vote
in favor thereof of the holders of a majority of the
total number of shares of the 4-1/8% Cumulative Preferred
Stock then outstanding, given at a meeting called for
that purpose, the amount so payable on such voluntary
liquidation, dissolution, or winding up shall be $100 per
share; or
$100 per share, in the event of any involuntary
liquidation, dissolution or winding up of the
Corporation; and
(d) There shall not be any sinking fund provided
for the purchase or redemption of shares of the 4-1/8%
Cumulative Preferred Stock.
(11) The Corporation hereby classifies $6,000,000 par
value of the Cumulative Preferred Stock as a series of such
Cumulative Preferred Stock, which shall be designated as
"4.56% Cumulative Preferred Stock", consisting of 60,000
shares of the par value of $100 each.
(12) The relative rights, preferences, limitations, and
restrictions of the shares of the 4.56% Cumulative Preferred
Stock, shall be as follows:
(a) The annual dividend rate for such series shall
be 4.56% per annum;
(b) Such series shall not be subject to redemption
prior to October 1, 1956; the redemption price for shares
of such series shall be $104 per share on and after
October 1, 1956 but prior to October 1, 1958; $103 per
share on and after October 1, 1958 but prior to October
1, 1963; and $102 per share on October 1, 1963 and
thereafter;
(c) The preferential amounts to which the holders
of shares of such series shall be entitled upon any
voluntary or involuntary liquidation, dissolution or
winding up of the Corporation shall be $100 per share;
and
(d) There shall not be any sinking fund provided
for the purchase or redemption of shares of the 4.56%
Cumulative Preferred Stock.
(13) The Corporation hereby classifies $4,000,000 par
value of the Cumulative Preferred Stock as a series of such
Cumulative Preferred Stock, which shall be designated as
"4.12% Cumulative Preferred Stock", consisting of 40,000
shares of the par value of $100 each.
(14) The relative rights, preferences, limitations and
restrictions of the shares of the 4.12% Cumulative Preferred
Stock, shall be as follows:
(a) The annual dividend rate for such series shall
be 4.12% per annum;
(b) The redemption price for such series shall be
$105.728 per share until October 1, 1959; $104.728 per
share on and after October 1, 1959 but prior to October
1, 1964; $103.728 per share on and after October 1, 1964
but prior to October 1, 1969; and $102.728 per share on
October 1, 1969 and thereafter;
(c) The preferential amounts to which the holders
of shares of such series shall be entitled upon any
voluntary or involuntary liquidation, dissolution or
winding up of the Corporation shall be the redemption
price in effect at the date of any voluntary liquidation,
dissolution or winding up of the Corporation; or $100 per
share, in the event of any involuntary liquidation,
dissolution or winding up of the Corporation;
(d) There shall not be any sinking fund provided
for the purchase or redemption of shares of the 4.12%
Cumulative Preferred Stock.
(15) The Corporation hereby classifies $30,000,000 par
value of the Cumulative Preferred Stock as a series of such
Cumulative Preferred Stock, which shall be designated as
"7.08% Cumulative Preferred Stock", consisting of 300,000
shares of the par value of $100 each.
(16) The relative rights, preferences, limitations and
restrictions of the shares of the 7.08% Cumulative Preferred
Stock, shall be as follows:
(a) The annual dividend rate for such series shall
be 7.08% per annum;
(b) The redemption price for such series shall be
$108.22 per share prior to February 1, 1976; $106.45 per
share on and after February 1, 1976 but prior to February
1, 1981; $104.68 per share on and after February 1, 1981
but prior to February 1, 1986; $102.91 per share on and
after February 1, 1986 but prior to February 1, 1991; and
$101.85 per share on February 1, 1991 and thereafter
provided, however, that no share of such series shall be
redeemed prior to February 1, 1976 if such redemption is
for the purpose or in anticipation of refunding such
share, directly or indirectly, through the incurring of
debt, or through the issuance of capital stock ranking
equally with or prior to the shares of such series as to
dividends or assets, if such debt has an effective
interest cost to the Corporation (computed in accordance
with generally accepted financial practice), or such
capital stock has an effective dividend cost to the
Corporation (so computed), of less than 7.07% per annum;
(c) The preferential amounts to which the holders
of shares of such series shall be entitled upon any
voluntary or involuntary liquidation, dissolution or
winding up of the Corporation shall be the redemption
price in effect at the date of any voluntary liquidation,
dissolution or winding up of the Corporation; or $100 per
share in the event of any involuntary liquidation,
dissolution or winding up of the Corporation; and
(d) There shall not be any sinking fund provided
for the purchase or redemption of shares of such series.
(17) The Corporation hereby classifies $35,000,000 par
value of the Cumulative Preferred Stock as a series of such
Cumulative Preferred Stock, which shall be designated as
"7.76% Cumulative Preferred Stock", consisting of 350,000
shares of par value of $100 each.
(18) The relative rights, preferences, limitations and
restrictions of the shares of the 7.76% Cumulative Preferred
Stock, shall be as follows:
(a) The annual dividend rate for such series shall
be 7.76% per annum;
(b) The redemption price for such series shall be
$109.26 per share prior to November 1, 1976; $107.32 per
share on and after November 1, 1976 but prior to November
1, 1981; $105.38 per share on and after November 1, 1981
but prior to November 1, 1986; $103.44 per share on and
after November 1, 1986 but prior to November 1, 1991; and
$102.28 per share on November 1, 1991 and thereafter;
provided, however, that no share of such series shall be
redeemed prior to November 1, 1976 if such redemption is
for the purpose or in anticipation of refunding such
share, directly or indirectly, through the incurring of
debt, or through the issuance of capital stock ranking
equally with or prior to the shares of such series as to
dividends or assets, if such debt has an effective
interest cost to the Corporation (computed in accordance
with generally accepted financial practice), or such
capital stock has an effective dividend cost to the
Corporation (so computed), of less than 7.74% per annum;
(c) The preferential amounts to which the holders
of shares of such series shall be entitled upon any
voluntary or involuntary liquidation, dissolution or
winding up of the Corporation shall be the redemption
price in effect at the date of any voluntary liquidation,
dissolution or winding up of the Corporation; or $100 per
share in the event of any involuntary liquidation,
dissolution or winding up of the Corporation;
(d) There shall not be any sinking fund provided
for the purchase or redemption of shares of such series.
(19) The Corporation hereby classifies $30,000,000 par
value of the Cumulative Preferred Stock as a series of such
Cumulative Preferred Stock, which shall be designated as
"8.68% Cumulative Preferred Stock", consisting of 300,000
shares of the par value of $100 each.
(20) The relative rights, preferences, limitations and
restrictions of the shares of the 8.68% Cumulative Preferred
Stock, shall be as follows:
(a) The annual dividend rate for such series shall
be 8.68% per annum;
(b) The redemption price for such series shall be
$109.61 per share prior to December 1, 1978; $107.44 per
share on and after December 1, 1978 but prior to December
1, 1983; $105.27 per share on and after December 1, 1983
but prior to December 1, 1988; $103.10 per share on and
after December 1, 1988 but prior to December 1, 1993; and
$101.80 per share on December 1, 1993 and thereafter;
provided, however, that no share of such series shall be
redeemed prior to December 1, 1978 if such redemption is
for the purpose or in anticipation of refunding such
share directly or indirectly, through the incurring of
debt, or through the issuance of capital stock ranking
equally with or prior to the shares of such series as to
dividends or assets, if such debt has an effective
interest cost to the Corporation (computed in accordance
with generally accepted financial practice), or such
capital stock has an effective dividend cost to the
Corporation (so computed), of less than 8.68% per annum;
(c) The preferential amounts to which the holders
of shares of such series shall be entitled upon any
voluntary or involuntary liquidation, dissolution or
winding up of the Corporation shall be the redemption
price in effect at the date of any voluntary liquidation,
dissolution or winding up of the Corporation; or $100 per
share in the event of any involuntary liquidation,
dissolution or winding up of the Corporation;
(d) There shall not be any sinking fund provided
for the purchase or redemption of shares of such series.
(21) The Corporation hereby classifies $30,000,000 par
value of the Cumulative Preferred Stock as a series of such
Cumulative Preferred Stock, which shall be designated as "12%
Cumulative Preferred Stock", consisting of 300,000 shares of
the par value of $100 each.
(22) The relative rights preferences, limitations and
restrictions of the shares of the 12% Cumulative Preferred
Stock shall be as follows:
(a) The annual dividend rate for such series shall
be 12% per annum;
(b) The redemption price for such series shall be
$112.00 per share prior to September 1, 1985; $106.00 per
share on and after September 1, 1985 but prior to
September 1, 1990; $103.00 per share on and after
September 1, 1990 but prior to September 1, 1995; and
$101.20 per share on September 1, 1995 and thereafter;
provided, however, that no share of such series shall be
redeemed prior to September 1, 1980 if such redemption is
for the purpose or in anticipation of refunding such
share, directly or indirectly, through the incurring of
debt, or through the issuance of capital stock ranking
equally with or prior to the shares of such series as to
dividends or assets, if such debt has an effective
interest cost to the Corporation (computed in accordance
with generally accepted financial practice), or such
capital stock has an effective dividend cost to the
Corporation (so computed), of less than 12.75% per annum;
(c) the preferential amounts to which the holders
of shares of such series shall be entitled upon any
voluntary or involuntary liquidation, dissolution or
winding up of the Corporation shall be the redemption
price provided in subparagraph (b) hereof in effect at
the date of any voluntary liquidation, dissolution or
winding up of the Corporation; or $100 per share in the
event of any involuntary liquidation, dissolution or
winding up of the Corporation;
(d)(1) A sinking fund shall be established for the
retirement of the shares of such series. So long as
there shall remain outstanding any shares of such series,
the Corporation shall, to the extent permitted by law on
October 1 in each year commencing with the year 1980,
redeem as and for a sinking fund requirement, out of
funds legally available therefor, a number of shares
equal to 5% of the total number of shares classified as
12% Cumulative Preferred Stock in paragraph (21) hereof
at a redemption price of $100 per share. The sinking
fund requirement shall be cumulative so that if on any
such October 1 the sinking fund requirement shall not
have been met, then such sinking fund requirement, to the
extent not met, shall become an additional sinking fund
requirement for the next succeeding October 1 on which
such redemption may be effected.
(2) The Corporation shall have the non-
cumulative option, on any sinking fund date as provided
in subparagraph (d)(1) hereof, to redeem at a redemption
price of $100 per share, an additional number of shares
equal to 5% of the total number of shares classified as
12% Cumulative Preferred Stock in paragraph (21) hereof.
No redemption made pursuant to this subparagraph (d)(2)
shall be deemed to fulfill any sinking fund requirement
established pursuant to subparagraph (d)(1).
(3) The Corporation shall be entitled, at its
election, to credit against the sinking fund requirement
due on October 1 of any year pursuant to subparagraph
(d)(1) shares of such series theretofore purchased or
otherwise acquired by the Corporation.
(23) The Corporation hereby classifies $40,000,000 par
value of the Cumulative Preferred Stock as a series of such
Cumulative Preferred Stock, which shall be designated as
"$2.15 Cumulative Preferred Stock", consisting of 1,600,000
shares of the par value of $25 each.
(24) The relative rights, preferences, limitations and
restrictions of the shares of the $2.15 Cumulative Preferred
Stock shall be as follows:
(a) The annual dividend rate for such series shall
be $2.15 per annum;
(b) The redemption price for such series shall be
$27.15 per share prior to May 1, 1982; $26.61 per share
on and after May 1, 1982 but prior to May 1, 1987; $26.08
per share on and after May 1, 1987 but prior to May 1,
1992; $25.54 per share on and after May 1, 1992 but prior
to May 1, 1997; and $25.22 per share on May 1, 1997 and
thereafter; provided, however, that no share of such
series shall be redeemed prior to May 1, 1982 if such
redemption is for the purpose or in anticipation of
refunding such share, directly or indirectly, through the
incurring of debt, or through the issuance of capital
stock ranking equally with or prior to the shares of such
series as to dividends or assets, if such debt has an
effective interest cost to the Corporation (computed in
accordance with generally accepted financial practice),
or such capital stock has an effective dividend cost to
the Corporation (so computed), of less than 8.99% per
annum;
(c) The preferential amounts to which the holders
of shares of such series shall be entitled upon any
voluntary or involuntary liquidation, dissolution or
winding up of the Corporation shall be the redemption
price provided in subparagraph (b) hereof in effect at
the date of any voluntary liquidation, dissolution or
winding up of the Corporation; or $25 per share in the
event of any involuntary liquidation, dissolution or
winding up of the Corporation; and
(d) There shall not be any sinking fund
requirements for the purchase or redemption of the shares
of such series.
(25) The Corporation hereby classifies $40,000,000 par
value of the Cumulative Preferred Stock as a series of such
Cumulative Preferred Stock, which shall be designated as
"$2.25 Cumulative Preferred Stock", consisting of 1,600,000
shares of the par value of $25 each.
(26) The relative rights, preferences, limitations and
restrictions of the shares of the $2.25 Cumulative Preferred
Stock shall be as follows:
(a) The annual dividend rate for such series shall
be $2.25 per annum;
(b) The redemption price for such series shall be
$27.25 per share prior to March 1, 1983; $26.69 per share
on and after March 1, 1983 but prior to March 1, 1988;
$26.13 per share on and after March 1, 1988 but prior to
March 1, 1993; $25.56 per share on and after March 1,
1993 but prior to March 1, 1998; and $25.23 per share on
March 1, 1998 and thereafter; provided, however, that no
share of such series shall be redeemed prior to March 1,
1983 if such redemption is for the purpose or in
anticipation of refunding such share, directly or
indirectly, through the incurring of debt, or through the
issuance of capital stock ranking equally with or prior
to the shares of such series as to dividends or assets,
if such debt has an effective interest cost to the
Corporation (computed in accordance with generally
accepted financial practice), or such capital stock has
an effective dividend cost to the Corporation (so
computed), of less than 9.32% per annum;
(c) The preferential amounts to which the holders
of shares of such series shall be entitled upon any
voluntary or involuntary liquidation, dissolution or
winding up of the Corporation shall be the redemption
price provided in subparagraph (b) hereof in effect at
the date of any voluntary liquidation, dissolution or
winding up of the Corporation; or $25 per share in the
event of any involuntary liquidation, dissolution or
winding up of the Corporation; and
(d) There shall not be any sinking fund
requirements for the purchase or redemption of the shares
of such series.
(27) The Corporation hereby classifies $40,000,000 par
value of the Cumulative Preferred Stock as a series of such
Cumulative Preferred Stock, which shall be designated as
"$2.75 Cumulative Preferred Stock", consisting of 1,600,000
shares of the par value of $25 each.
(28) The relative rights, preferences, limitations and
restrictions of the shares of the $2.75 Cumulative Preferred
Stock shall be as follows:
(a) The annual dividend rate for such series shall
be $2.75 per annum;
(b) The redemption price for such series shall be
$27.75 per share prior to October 1, 1984; $27.07 per
share on and after October 1, 1984 but prior to October
1, 1989; $26.38 per share on and after October 1, 1989
but prior to October 1, 1994; $25.69 per share on and
after October 1, 1994 but prior to October 1, 1999;
$25.28 per share on October 1, 1999 and thereafter;
provided, however, that no share of such series shall be
redeemed prior to October 1, 1984 if such redemption is
for the purpose or in anticipation of refunding such
share, directly or indirectly, through the incurring of
debt, or through the issuance of capital stock ranking
equally with or prior to the shares of such series as to
dividends or assets, if such debt has an effective
interest cost to the Corporation (computed in accordance
with generally accepted financial practice), or such
capital stock has an effective dividend cost to the
Corporation (so computed), of less than 11.31% per annum;
(c) The preferential amounts to which the holders
of shares of such series shall be entitled upon any
voluntary or involuntary liquidation, dissolution or
winding up of the Corporation shall be the redemption
price provided in subparagraph (b) hereof in effect at
the date of any voluntary liquidation, dissolution or
winding up of the Corporation; or $25 per share in the
event of any involuntary liquidation, dissolution or
winding up of the Corporation; and
(d)(1) A sinking fund shall be established for the
retirement of the shares of such series. So long as
there shall remain outstanding any shares of such series,
the Corporation shall, to the extent permitted by law on
October 1 in each year commencing with the year 1984,
redeem as and for a sinking fund requirement, out of
funds legally available therefor, a number of shares
equal to 5% of the total number of shares classified as
$2.75 Cumulative Preferred Stock in paragraph (27) hereof
at a redemption price of $25 per share. The sinking fund
requirement shall be cumulative so that if on any such
October 1 the sinking fund requirement shall not have
been met, then such sinking fund requirement, to the
extent not met, shall become an additional sinking fund
requirement for the next succeeding October 1 on which
such redemption may be effected.
(2) The Corporation shall have the non-
cumulative option, on any sinking fund date as provided
in subparagraph (d)(1) hereof, to redeem at a redemption
price of $25 per share, an additional number of shares
equal to 5% of the total number of shares classified as
$2.75 Cumulative Preferred Stock in paragraph (27)
hereof. No redemption made pursuant to this sub-
paragraph (d)(2) shall be deemed to fulfill any sinking
fund requirement established pursuant to subparagraph
(d)(1).
(3) The Corporation shall be entitled, at its
election, to credit against the sinking fund requirement
due on October 1 of any year pursuant to subparagraph
(d)(1) shares of such series theretofore purchased or
otherwise acquired by the Corporation.
The Corporation hereby classifies $40,000,000 par
value of the Cumulative Preferred Stock as a series of
such Cumulative Preferred Stock as a series of such
Cumulative Preferred Stock, which shall be designated as
"$3.63 Cumulative Preferred Stock", consisting of
1,600,000 shares of the par value of $25 each.
The relative rights, preferences, limitations and
restrictions of the shares of the $3.63 Cumulative
Preferred Stock shall be as follows:
(a) The annual dividend rate for such series shall
be $3.63 per annum;
(b) The redemption price for such series shall be
$28.63 per share prior to November 1, 1986; $27.72 per
share on and after November 1, 1986 but prior to November
1, 1991; $26.82 per share on and after November 1, 1991
but prior to November 1, 1996; and $25.91 per share on
and after November 1, 1996 but prior to November 1, 2001;
and $25.36 per share on November 1, 2001 and thereafter;
provided, however, that no share of such series shall be
redeemed prior to November 1, 1986 if such redemption is
for the purpose or in anticipation of refunding such
share, directly or indirectly, through the incurring of
debt, or through the issuance of capital stock ranking
equally with or prior to the shares of such series as to
dividends or assets, if such debt has an effective
interest cost to the Corporation (computed in accordance
with generally accepted financial practice), or such
capital stock has an effective dividend cost to the
Corporation (so computed), of less than 15% per annum;
(c) The preferential amounts to which the holders
of shares of such series shall be entitled upon any
voluntary or involuntary liquidation, dissolution or
winding up of the Corporation shall be the redemption
price provided in paragraph (b) hereof in effect at the
date of any voluntary liquidation, dissolution or winding
up of the Corporation; or $25 per share in the event of
any involuntary liquidation, dissolution or winding up of
the Corporation; and
(d)(1) A sinking fund shall be established for the
retirement of the shares of such series. So long as
there shall remain outstanding any shares of such series,
the Corporation shall, to the extent permitted by law on
January 1 in each year commencing with the year 1987,
redeem as and for a sinking fund requirement, out of
funds legally available therefor, a number of shares
equal to 5% of the total number of shares classified as
$3.63 Cumulative Preferred Stock in this resolution at a
redemption price of $25 per share. The sinking fund
requirement shall be cumulative so that if on any such
January 1 the sinking fund requirement shall not have
been met, then such sinking fund requirement, to the
extent not met, shall become an additional sinking fund
requirement for the next succeeding January 1 on which
such redemption may be effected.
(2) The Corporation shall have the non-
cumulative option, on any sinking fund date as provided
in subparagraph (d)(1) hereof, to redeem at a redemption
price of $25 per share, an additional number of shares
equal to 5% of the total number of shares classified as
$3.63 Cumulative Preferred Stock in this resolution. No
redemption made pursuant to this subparagraph (d)(2)
shall be deemed to fulfill any sinking fund requirement
established pursuant to subparagraph (d)(1).
(3) The Corporation shall be entitled, at its
election, to credit against the sinking fund requirement
due on January 1 of any year pursuant to subparagraph
(d)(1) shares of such series theretofore purchased or
otherwise acquired by the Corporation.
(29) (a) The designation, description and terms of a new
series of 300,000 shares of Cumulative Preferred Stock,
$100 par value, are set forth in this paragraph (29).
The distinctive serial designation of such series which
is hereby created shall be "6-7/8% Cumulative Preferred
Stock".
(b) The annual dividend rate for such series shall
be 6-7/8% per share per annum, which dividend shall be
calculated, per share, at such percentage multiplied by
$100. Dividends on all shares of said series issued
prior to the record date for the initial dividend payable
on all shares of such series shall be cumulative from the
date of initial issuance of the shares of such series.
(c) Such series shall not be subject to redemption
prior to February 1, 2003; the regular redemption price
for shares of such series shall be $100 per share on or
after February 1, 2003, plus an amount equal to accrued
and unpaid dividends to the date of redemption.
(d) The preferential amounts to which the holders
of shares of such series shall be entitled upon any
voluntary or involuntary liquidation, dissolution or
winding up of the Corporation shall be $100 per share,
plus an amount equal to accrued and unpaid dividends to
the date of redemption.
(e)(1) A sinking fund shall be established for the
retirement of the shares of such series. So long as
there shall remain outstanding any shares of such series,
the Corporation shall, to the extent permitted by law, on
April 1, 2003 and on each April 1 thereafter to and
including April 1, 2007, redeem as and for a sinking fund
requirement, out of funds legally available therefor, a
number of shares equal to 5% of the total number of
shares initially classified as 6-7/8% Cumulative
Preferred Stock in this paragraph (29) at a sinking fund
redemption price of $100 per share plus accrued and
unpaid dividends to the date of redemption. The sinking
fund requirement shall be cumulative so that if on any
such April 1 the sinking fund requirement shall not have
been met, then such sinking fund requirement, to the
extent not met, shall become an additional sinking fund
requirement for the next succeeding April 1 on which such
redemption may be effected.
(2) The remaining shares of such series
outstanding on April 1, 2008 will be redeemed, to the
extent permitted by law, by mandatory redemption, out of
funds legally available therefor, on such date at a
mandatory redemption price of $100 per share plus accrued
and unpaid dividends to the date of redemption.
(3) The Corporation shall be entitled, at its
election, to credit against the sinking fund requirement
due on April 1 of any year pursuant to subparagraph
(e)(1) shares of such series theretofore purchased or
otherwise acquired by the Corporation and not previously
credited against any such sinking fund requirement.
(f) The shares of such series shall not have any
rights to convert the same into and/or purchase stock of
any other series or class or any other securities, or any
special rights other than those specified herein.
(30) (a) The designation, description and terms of a new
series of 400,000 shares of Cumulative Preferred Stock,
$100 par value, are set forth in this paragraph (30).
The distinctive serial designation of such series which
is hereby created shall be "5.90% Cumulative Preferred
Stock".
(b) The annual dividend rate for such series shall
be 5.90% per share per annum, which dividend shall be
calculated, per share, at such percentage multiplied by
$100. Dividends on all shares of said series issued
prior to the record date for the initial dividend payable
on all shares of such series shall be cumulative from the
date of initial issuance of the shares of such series.
(c) Such series shall not be subject to redemption
prior to November 1, 2003; the redemption price for
shares of such series shall be $100 per share on or after
November 1, 2003, plus an amount equal to accrued and
unpaid dividends to the date of redemption.
(d) The preferential amounts to which the holders
of shares of such series shall be entitled upon any
voluntary or involuntary liquidation, dissolution or
winding up of the Corporation shall be $100 per share,
plus an amount equal to accrued and unpaid dividends.
(e)(1) A sinking fund shall be established for the
retirement of the shares of such series. So long as
there shall remain outstanding any shares of such series,
the Corporation shall, to the extent permitted by law, on
January 1, 2004 and on each January 1 thereafter to and
including January 1, 2008, redeem as and for a sinking
fund requirement, out of funds legally available
therefor, a number of shares equal to 5% of the total
number of shares initially classified as 5.90% Cumulative
Preferred Stock in this paragraph (30) at a sinking fund
redemption price of $100 per share, plus accrued and
unpaid dividends to the date of redemption. The
remaining shares of such series outstanding on January 1,
2009 will be redeemed as a final sinking fund
requirement, to the extent permitted by law, out of funds
legally available therefor, on such date at a sinking
fund redemption price of $100 per share, plus accrued and
unpaid dividends to the date of redemption. The sinking
fund requirement shall be cumulative so that if on any
such January 1 the sinking fund requirement shall not
have been met, then such sinking fund requirement, to the
extent not met, shall become an additional sinking fund
requirement for the next succeeding January 1 on which
such redemption may be effected.
(2) The Corporation shall be entitled, at its
election, to credit against the sinking fund requirement
due on January 1 of any year pursuant to subparagraph
(e)(1) shares of such series theretofore purchased or
otherwise acquired by the Corporation and not previously
credited against any such sinking fund requirement.
(f) The shares of such series shall not have any
rights to convert the same into and/or purchase stock of
any other series or class or any other securities, or any
special rights other than those specified herein.
(31) (a) The designation, description and terms of a new
series of 300,000 shares of Cumulative Preferred Stock,
$100 par value, are set forth in this paragraph (31).
The distinctive serial designation of such series which
is hereby created shall be "6-1/4% Cumulative Preferred
Stock".
(b) The annual dividend rate for such series shall
be 6-1/4% per share per annum, which dividend shall be
calculated, per share, at such percentage multiplied by
$100. Dividends on all shares of said series issued
prior to the record date for the initial dividend payable
on all shares of such series shall be cumulative from the
date of initial issuance of the shares of such series.
(c) Such series shall not be subject to redemption
prior to December 1, 2003; the redemption price for
shares of such series shall be $100 per share on or after
December 1, 2003, plus an amount equal to accrued and
unpaid dividends to the date of redemption.
(d) The preferential amounts to which the holders
of shares of such series shall be entitled upon any
voluntary or involuntary liquidation, dissolution or
winding up of the Corporation shall be $100 per share,
plus an amount equal to accrued and unpaid dividends.
(e)(1) A sinking fund shall be established for the
retirement of the shares of such series. So long as
there shall remain outstanding any shares of such series,
the Corporation shall, to the extent permitted by law, on
April 1, 2004 and on each April 1 thereafter to and
including April 1, 2008, redeem as and for a sinking fund
requirement, out of funds legally available therefor, a
number of shares equal to 5% of the total number of
shares initially classified as 6-1/4% Cumulative
Preferred Stock in this paragraph (31) at a sinking fund
redemption price of $100 per share, plus accrued and
unpaid dividends to the date of redemption. The
remaining shares of such series outstanding on April 1,
2009 will be redeemed as a final sinking fund
requirement, to the extent permitted by law, out of funds
legally available therefor, on such date at a sinking
fund redemption price of $100 per share, plus accrued and
unpaid dividends to the date of redemption. The sinking
fund requirement shall be cumulative so that if on any
such April 1 the sinking fund requirement shall not have
been met, then such sinking fund requirement, to the
extent not met, shall become an additional sinking fund
requirement for the next succeeding April 1 on which such
redemption may be effected.
(2) The Corporation shall be entitled, at its
election, to credit against the sinking fund requirement
due on April 1 of any year pursuant to subparagraph
(e)(1) shares of such series theretofore purchased or
otherwise acquired by the Corporation and not previously
credited against any such sinking fund requirement.
(f) The shares of such series shall not have any
rights to convert the same into and/or purchase stock of
any other series or class or any other securities, or any
special rights other than those specified herein.
(32) (a) The designation, description and terms of a new
series of 350,000 shares of Cumulative Preferred Stock,
$100 par value, are set forth in this paragraph (32).
The distinctive serial designation of such series which
is hereby created shall be "6.30% Cumulative Preferred
Stock".
(b) The annual dividend rate for such series shall
be 6.30% per share per annum, which dividend shall be
calculated, per share, at such percentage multiplied by
$100. Dividends on all shares of said series issued
prior to the record date for the initial dividend payable
on all shares of such series shall be cumulative from the
date of initial issuance of the shares of such series.
(c) Such series shall not be subject to redemption
prior to March 1, 2004; the redemption price for shares
of such series shall be $100 per share on or after March
1, 2004, plus an amount equal to accrued and unpaid
dividends to the date of redemption.
(d) The preferential amounts to which the holders
of shares of such series shall be entitled upon any
voluntary or involuntary liquidation, dissolution or
winding up of the Corporation shall be $100 per share,
plus an amount equal to accrued and unpaid dividends.
(e)(1) A sinking fund shall be established for the
retirement of the shares of such series. So long as
there shall remain outstanding any shares of such series,
the Corporation shall, to the extent permitted by law, on
July 1, 2004 and on each July 1 thereafter to and
including July 1, 2008, redeem as and for a sinking fund
requirement, out of funds legally available therefor, a
number of shares equal to 5% of the total number of
shares initially classified as 6.30% Cumulative Preferred
Stock in this paragraph (32) at a sinking fund redemption
price of $100 per share, plus accrued and unpaid
dividends to the date of redemption. The remaining
shares of such series outstanding on July 1, 2009 will be
redeemed as a final sinking fund requirement, to the
extent permitted by law, out of funds legally available
therefor, on such date at a sinking fund redemption price
of $100 per share, plus accrued and unpaid dividends to
the date of redemption. The sinking fund requirement
shall be cumulative so that if on any such July 1 the
sinking fund requirement shall not have been met, then
such sinking fund requirement, to the extent not met,
shall become an additional sinking fund requirement for
the next succeeding July 1 on which such redemption may
be effected.
(2) The Corporation shall be entitled, at its
election, to credit against the sinking fund requirement
due on July 1 of any year pursuant to subparagraph (e)(1)
shares of such series theretofore purchased or otherwise
acquired by the Corporation and not previously credited
against any such sinking fund requirement.
(f) The shares of such series shall not have any
rights to convert the same into and/or purchase stock of
any other series or class or any other securities, or any
special rights other than those specified herein.
B. Common Stock
Each share of the Common Stock shall be equal in all respects
to every other share of the Common Stock.
____________________
All stock of the Corporation without par value, whether
authorized herein or upon subsequent increase of capital, may
be issued from time to time for such consideration as may be
fixed from time to time by the Board of Directors and approved
by any governmental authorities having jurisdiction in the
premises if and to the extent that such approval is required
by law.
7. As to the voting rights and powers of the shares of each
class and of each series see paragraphs (7), (8) and (10)(c) under
Article 6 above.
8. The stated capital of the Corporation at the time of
filing these Amended Articles is at least one thousand dollars
($1,000).
9. The maximum number of Directors of this Corporation shall
be fifteen (15). The exact number of Directors which shall
constitute the whole Board of Directors of this Corporation shall
be such as from time to time shall be specified by the by-laws, but
at not less than three (3) nor at more than fifteen (15). Whenever
the by-laws do not specify such exact number, then such number
shall be eleven (11). A majority in number of the Board of
Directors shall be bona fide residents and citizens of the State of
Indiana while acting as such Directors.
10. The names and post office addresses of the Directors of
the Corporation are as follows:
Frank N. Bien, 180 East Broad Street,
Columbus, Ohio 43215
William A. Black, 2101 Spy Run Avenue,
Fort Wayne, Indiana 46801
Lawrence R. Brunke, 2101 Spy Run Avenue,
Fort Wayne, Indiana 46801
Richard E. Disbrow, 180 East Broad Street,
Columbus, Ohio 43215
John E. Dolan, 180 East Broad Street,
Columbus, Ohio 43215
Gerald E. LeMasters, 2101 Spy Run Avenue,
Fort Wayne, Indiana 46801
Gerald P. Maloney, 2 Broadway,
New York, New York 10004
Richard C. Menge, 2101 Spy Run Avenue,
Fort Wayne, Indiana 46801
C. Wayne Roahrig, 419 N. Walnut Street,
Muncie, Indiana 47305
Jack F. Stark, 2101 Spy Run Avenue,
Fort Wayne, Indiana 46801
W. S. White, Jr., 180 East Broad Street,
Columbus, Ohio 43215
The names and addresses of the President and the
Secretary of the Corporation are as follows:
President: William A. Black, 2101 Spy Run Avenue,
Fort Wayne, Indiana 46801
Secretary: John R. Burton, 180 East Broad Street,
Columbus, Ohio 43215
11. All meetings of stockholders may be held within or
without the State of Indiana at such place as shall be specified in
the call thereof.
EXHIBIT 4(b)
Indenture Supplemental
to
Mortgage and Deed of Trust
(Dated as of June 1, 1939)
EXECUTED BY
INDIANA MICHIGAN POWER COMPANY
(Formerly Indiana & Michigan Electric Company)
TO
THE BANK OF NEW YORK
(Formerly Irving Trust Company)
Trustee
Dated as of February 1, 1997
$48,000,000 First Mortgage Bonds,
Designated Secured Medium Term Notes,
6.40% Series due March 1, 2000
TABLE OF CONTENTS*
Page
Parties. . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Recitals
Execution of Mortgage and supplemental indentures . . . . 1
Termination of Individual Trustee . . . . . . . . . . . . 2
Acquisition of property rights and property . . . . . . . 2
Provision for issuance of bonds in one or more series . . 2
Right to execute supplemental indenture . . . . . . . . . 2
First Mortgage Bonds heretofore issued in several series. 3
Issue of new First Mortgage Bonds, Designated Secured
Medium Term Notes, of the 50th Series . . . . . . . . . 3
First 1997 Supplemental Indenture . . . . . . . . . . . . 3
Compliance with legal requirements. . . . . . . . . . . . 3
Granting Clauses . . . . . . . . . . . . . . . . . . . . . . . 3
Description of Property. . . . . . . . . . . . . . . . . . . . 4
Appurtenances, Etc.. . . . . . . . . . . . . . . . . . . . . . 5
Habendum . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Subject to Reservations, Etc.. . . . . . . . . . . . . . . . . 5
Grant in Trust . . . . . . . . . . . . . . . . . . . . . . . . 5
Sec. 1. Supplement to Original Indenture by addition of
new Sec. 20 WW thereto . . . . . . . . . . . . . . 6
Sec. 2. Supplement to Original Indenture by addition of
new Article III BBBB . . . . . . . . . . . . . . . 8
Sec. 3. Provisions for record date for meetings of bond-
holders. . . . . . . . . . . . . . . . . . . . . . 9
Sec. 4. First 1997 Supplemental Indenture and Original
Indenture to be construed as one instrument. . . . 9
Limitation on rights of others . . . . . . . . . . 9
Trustee assumes no responsibility for
correctness of recitals of fact. . . . . . . . . . 9
Execution in counterparts. . . . . . . . . . . . . 9
Testimonium. . . . . . . . . . . . . . . . . . . . . . . . . . 9
Signatures and Seals . . . . . . . . . . . . . . . . . . . . . 10
Acknowledgments. . . . . . . . . . . . . . . . . . . . . . . . 12
Schedule I . . . . . . . . . . . . . . . . . . . . . . . . . I-1
_________________________________
*The Table of Contents shall not be deemed to be any part of the
Indenture Supplemental to Mortgage and Deed of Trust.
INDENTURE SUPPLEMENTAL, dated as of the first day of February
in the year One Thousand Nine Hundred and Ninety-Seven, made and
entered into by and between Indiana Michigan Power Company, a
corporation of the State of Indiana, the corporate title of which
was, prior to September 9, 1987, Indiana & Michigan Electric Company,
with its principal executive office and place of business located
at One Summit Square, Fort Wayne, Indiana 46801 (hereinafter
sometimes called the "Company"), party of the first part, and The
Bank of New York (formerly Irving Trust Company), a corporation of
the State of New York, with its principal corporate trust office at
101 Barclay Street, New York, N.Y. 10286 (hereinafter sometimes
called the "Corporate Trustee" or "Trustee"), as Trustee, party of
the second part.
Whereas, the Company has heretofore executed and delivered its
Mortgage and Deed of Trust, dated as of June 1, 1939, an Indenture
Supplemental to Mortgage and Deed of Trust, dated as of September 1,
1948, an Indenture Supplemental to Mortgage and Deed of Trust, dated
as of June 1, 1950, an Indenture Supplemental to Mortgage and Deed
of Trust, dated as of January 1, 1952, an Indenture Supplemental to
Mortgage and Deed of Trust, dated as of September 1, 1953, an Inden-
ture Supplemental to Mortgage and Deed of Trust, dated as of October
1, 1954, an Indenture Supplemental to Mortgage and Deed of Trust,
dated as of February 1, 1958, an Indenture Supplemental to Mortgage
and Deed of Trust, dated as of November 1, 1958, an Indenture Supple-
mental to Mortgage and Deed of Trust, dated as of August 1, 1963,
an Indenture Supplemental to Mortgage and Deed of Trust, dated as
of May 1, 1968, an Indenture Supplemental to Mortgage and Deed of
Trust, dated as of June 1, 1969, an Indenture Supplemental to Mort-
gage and Deed of Trust, dated as of April 1, 1970, an Indenture
Supplemental to Mortgage and Deed of Trust, dated as of February 1,
1971, an Indenture Supplemental to Mortgage and Deed of Trust, dated
as of December 1, 1973, an Indenture Supplemental to Mortgage and
Deed of Trust, dated as of June 1, 1974, an Indenture Supplemental
to Mortgage and Deed of Trust, dated as of March 1, 1975, an Inden-
ture Supplemental to Mortgage and Deed of Trust, dated as of
September 1, 1975, an Indenture Supplemental to Mortgage and Deed
of Trust, dated as of March 1, 1978, an Indenture Supplemental to
Mortgage and Deed of Trust, dated as of January 1, 1979, an Indenture
Supplemental to Mortgage and Deed of Trust, dated as of February 1,
1980, an Indenture Supplemental to Mortgage and Deed of Trust, dated
as of June 1, 1980, an Indenture Supplemental to Mortgage and Deed
of Trust, dated as of March 1, 1981, an Indenture Supplemental to
Mortgage and Deed of Trust, dated as of November 1, 1981, an Inden-
ture Supplemental to Mortgage and Deed of Trust, dated as of April
1, 1982, an Indenture Supplemental to Mortgage and Deed of Trust,
dated as of August 1, 1983, an Indenture Supplemental to Mortgage
and Deed of Trust, dated as of July 1, 1986, an Indenture Supplemen-
tal to Mortgage and Deed of Trust, dated as of October 1, 1986, an
Indenture Supplemental to Mortgage and Deed of Trust, dated as of
February 1, 1987, a further Indenture Supplemental to Mortgage and
Deed of Trust, dated as of February 1, 1987, an Indenture Supplemen-
tal to Mortgage and Deed of Trust, dated as of May 1, 1987, an
Indenture Supplemental to Mortgage and Deed of Trust, dated as of
July 1, 1987, an Indenture Supplemental to Mortgage and Deed of
Trust, dated as of May 1, 1991, an Indenture Supplemental to Mortgage
and Deed of Trust, dated as of June 1, 1991, an Indenture Supple-
mental to Mortgage and Deed of Trust, dated as of June 3, 1991, an
Indenture Supplemental to Mortgage and Deed of Trust, dated as of
May 1, 1992, an Indenture Supplemental to Mortgage and Deed of Trust,
dated as of October 15, 1992, an Indenture Supplemental to Mortgage
and Deed of Trust, dated as of December 1, 1992, an Indenture
Supplemental to Mortgage and Deed of Trust, dated as of June 1, 1993,
an Indenture Supplemental to Mortgage and Deed of Trust, dated as
of August 1, 1993, an Indenture Supplemental to Mortgage and Deed
of Trust, dated as of September 15, 1993, an Indenture Supplemental
to Mortgage and Deed of Trust, dated as of October 15, 1993, an
Indenture Supplemental to Mortgage and Deed of Trust, dated as of
February 1, 1994, and an Indenture Supplemental to Mortgage and Deed
of Trust, dated May 1, 1994 (hereinafter called the "Second 1994
Supplemental Indenture") (the Mortgage and Deed of Trust, as amended
and supplemented by said Supplemental Indentures, being hereinafter
called the "Original Indenture"), to the Trustee for the security
of all bonds of the Company outstanding thereunder, and by said
Original Indenture conveyed to the Trustee, upon certain trusts,
terms and conditions, and with and subject to certain provisos and
covenants therein contained, all and singular the property, rights
and franchises which the Company then owned or should thereafter
acquire, excepting any property expressly excepted by the terms of
the Original Indenture; and
Whereas, effective June 16, 1988, pursuant to Section 100G of
the Original Indenture, the Individual Trustee resigned and all
powers of the Individual Trustee then terminated, as did the Indi-
vidual Trustee's right, title and interest in and to the trust
estate, and without appointment of a new trustee as successor to said
Individual Trustee, all the right, title and powers of the Trustees
thereupon devolved upon the Corporate Trustee and its successors
alone; and
Whereas, in addition to the property described in the Original
Indenture, the Company has acquired certain property rights and
property hereinafter described and has covenanted in Section 42 of
the Original Indenture to execute and deliver such further instru-
ments and do such further acts as may be necessary or proper to make
subject to the lien thereof any property thereafter acquired and
intended to be subject to such lien; and
Whereas, the Original Indenture provides that bonds issued
thereunder may be issued in one or more series and further provides
that, with respect to each series, the rate of interest, the date
or dates of maturity, the dates for the payment of interest, the
terms and rates of optional redemption, and other terms and condi-
tions not inconsistent with the Original Indenture may be established
prior to the issue of bonds of such series by an indenture supple-
mental to the Original Indenture; and
Whereas, Section 115 of the Original Indenture provides that
any power, privilege or right expressly or impliedly reserved to or
in any way conferred upon the Company by any provision of the Origi-
nal Indenture, whether such power, privilege or right is in any way
restricted or is unrestricted, may be in whole or in part waived or
surrendered or subjected to any restriction if at the time unre-
stricted or to additional restriction if already restricted, and that
the Company may enter into any further covenants, limitations or
restrictions for the benefit of any one or more series of bonds
issued under the Original Indenture and provides that a breach
thereof shall be equivalent to a default under the Original Inden-
ture, or the Company may cure any ambiguity or correct or supplement
any defective or inconsistent provisions contained in the Original
Indenture or in any indenture supplemental to the Original Indenture,
by an instrument in writing, properly executed and acknowledged, and
that the Trustee is authorized to join with the Company in the execu-
tion of any such instrument or instruments; and
Whereas, the Company has heretofore issued, from time to time,
in accordance with the provisions of said Original Indenture, bonds
of the several series and in the respective principal amounts therein
specified, and, of the bonds so issued pursuant to the Original
Indenture, $525,000,000 aggregate principal amount are outstanding
as of the close of business on the date first above mentioned; and
Whereas, the Company, by appropriate corporate action in con-
formity with the terms of the Original Indenture, has duly determined
to create a series of bonds under the Original Indenture to be
entitled and designated as "First Mortgage Bonds, Designated Secured
Medium Term Notes, 6.40% Series due March 1, 2000" (herein sometimes
referred to as the "bonds of the 50th Series"); and
Whereas, each of the bonds of the 50th Series is to be sub-
stantially in the form set forth in Schedule I to this Indenture
Supplemental (hereinafter sometimes referred to as the "First 1997
Supplemental Indenture"); and
Whereas, the Company, in the exercise of the powers and author-
ities conferred upon and reserved to it under and by virtue of the
provisions of the Original Indenture, and pursuant to resolutions
of its Board of Directors, has duly resolved and determined to make,
execute and deliver to the Trustee a supplemental indenture, in the
form hereof, for the purposes herein provided; and
Whereas, all conditions and requirements necessary to make this
First 1997 Supplemental Indenture a valid, binding and legal instru-
ment in accordance with its terms, have been done, performed and
fulfilled, and the execution and delivery thereof have been in all
respects duly authorized;
NOW, THEREFORE, THIS INDENTURE WITNESSETH:
That Indiana Michigan Power Company, in consideration of the
premises and of the sum of One Dollar ($1.00) and other good and
valuable consideration paid to it by the Trustee at or before the
ensealing and delivery of these presents, the receipt whereof is
hereby acknowledged, and in order to secure the payment of both the
principal of and interest and premium, if any, on the bonds from time
to time issued under and secured by the Original Indenture and this
First 1997 Supplemental Indenture, according to their tenor and
effect, and the performance of all the provisions of the Original
Indenture and this First 1997 Supplemental Indenture (including any
further indenture or indentures supplemental to the Original Inden-
ture and any modification or alteration made as in the Original
Indenture provided) and of said bonds, has granted, bargained, sold,
warranted, released, conveyed, assigned, transferred, mortgaged,
pledged, set over and confirmed, and by these presents does grant,
bargain, sell, warrant, release, convey, assign, transfer, mortgage,
pledge, set over and confirm unto The Bank of New York, as Trustee,
and to its successor or successors in said trust, and to it and its
assigns forever, all of the following described properties of the
Company, that is to say: all property, real, personal and mixed,
tangible and intangible owned by the Company on the date of the
execution hereof, acquired since the execution and delivery of the
Second 1994 Supplemental Indenture (except such property as is
hereinafter expressly excepted from the lien and operation of this
First 1997 Supplemental Indenture).
The property covered by the lien of the Original Indenture and
this First 1997 Supplemental Indenture shall include particularly,
among other property, without prejudice to the generality of the
language hereinbefore or hereinafter contained, all property, whether
real, personal or mixed (except any hereinafter expressly excepted),
and wheresoever situated, now owned by the Company and acquired since
the execution and delivery of the Second 1994 Supplemental Indenture,
including (without in any wise limiting or impairing by the enumera-
tion of the same the scope and intent of the foregoing or of any
general description contained in this First 1997 Supplemental Inden-
ture) all lands, rights of way and roads; all water or riparian
rights and interests therein; all dams and dam sites and rights; all
plants for the generation of electricity, power houses, steam heat
plants, hot water plants, substations, transmission lines, dis-
tributing systems and vehicles; all offices, buildings and struc-
tures, and the equipment thereof; all machinery, engines, boilers,
turbines, dynamos, machines, regulators, meters, transformers, gener-
ators and motors; all appliances whether electrical or mechanical,
conduits, cables and lines; all mains and pipes, whether for water,
steam heat, or other purposes; all poles, wires, tools, implements,
apparatus and furniture; all municipal franchises and other fran-
chises and all permits, grants and consents; all lines for the
transmission and/or distribution of electric current, steam heat or
water for any purpose, including towers, poles, wires, cables, pipes,
conduits and all apparatus for use in connection therewith; all real
estate, lands, leases, leaseholds (excepting the last day of the term
of each lease and leasehold); all easements, servitudes, licenses,
permits, rights, powers, franchises, privileges, rights of way and
other rights in or relating to real estate or the occupancy of the
same and (except as hereinafter expressly excepted) all the right,
title and interest of the Company in and to all other property of
any kind or nature appertaining to and/or used and/or occupied and/or
enjoyed in connection with any property hereinbefore described;
Together with all and singular the tenements, hereditaments and
appurtenances belonging or in any wise appertaining to the aforesaid
property or any part thereof, with the reversion and reversions, re-
mainder and remainders and (subject to the provisions of Section 57
of the Original Indenture) the tolls, rents, revenues, issues,
earnings, income, product and profits thereof, and all the estate,
right, title and interest and claim whatsoever, at law as well as
in equity, which the Company now has or may hereafter acquire in and
to the aforesaid property and franchises and every part and parcel
thereof.
Provided that, in addition to the reservations and exceptions
herein elsewhere contained, the following are not and are not
intended to be granted, bargained, sold, warranted, released, con-
veyed, assigned, transferred, mortgaged, pledged, set over or
confirmed hereunder and are hereby expressly excepted from the lien
and operation of the Original Indenture and of this First 1997
Supplemental Indenture, viz: (1) cash, shares of stock and obliga-
tions (including bonds, notes and other securities) not hereafter
specifically pledged, or deposited or delivered hereunder or under
the Original Indenture or hereinafter or therein covenanted so to
be; (2) goods, wares, merchandise, equipment, materials or supplies
acquired for the purpose of sale or resale in the usual course of
business or for consumption in the operation of any properties of
the Company; (3) judgments, accounts and choses in action, the
proceeds of which the Company is not obligated as provided in the
Original Indenture or as hereinafter provided to deposit with the
Trustee hereunder or thereunder; provided, however, that the proper-
ties and rights expressly excepted from the lien and operation of
the Original Indenture and this First 1997 Supplemental Indenture
in the above subdivisions (2) and (3) shall (to the extent permitted
by law) cease to be so excepted, in the event that the Trustee or
a receiver or trustee shall enter upon and take possession of the
mortgaged and pledged property in the manner provided in Article XII
of the Original Indenture by reason of the occurrence of a completed
default, as defined in said Article XII.
To have and to hold all such properties, real, personal and
mixed, granted, bargained, sold, warranted, released, conveyed,
assigned, transferred, mortgaged, pledged, set over, or confirmed
by the Company as aforesaid, or intended so to be, unto the Trustee
and its successors in the trust.
Subject, however, to the reservations, exceptions, limitations
and restrictions contained in the several deeds, leases, servitudes,
franchises and contracts or other instruments through which the
Company acquired and/or claims title to and/or enjoys the use of the
aforesaid properties; and subject also to encumbrances of the char-
acter defined in Section 6 of the Original Indenture as "excepted
encumbrances", insofar as the same may attach to any of the property
embraced herein.
In trust nevertheless, upon the terms and trusts in the Original
Indenture and in this First 1997 Supplemental Indenture set forth,
for the benefit and security of those who shall hold the bonds and
coupons issued and to be issued hereunder and under the Original In-
denture, or any of them, in accordance with the terms of the Original
Indenture and of this First 1997 Supplemental Indenture, without
preference, priority or distinction as to lien of any of said bonds
or coupons over any others thereof by reason of priority in the time
of issue or negotiation thereof, or otherwise howsoever, subject,
however, to the conditions, provisions and covenants set forth in
the Original Indenture and in this First 1997 Supplemental Indenture.
AND THIS INDENTURE FURTHER WITNESSETH:
That in further consideration of the premises and for the con-
siderations aforesaid, the Company, for itself and its successors
and assigns, hereby covenants and agrees to and with the Trustee,
and its successor or successors in such trust, as follows:
Section 1. The Original Indenture is hereby supplemented
by adding immediately after Section 20 VV, a new Section 20 WW, as
follows:
Section 20 WW. The Company hereby creates a fiftieth
series of bonds to be issued under and secured by this Inden-
ture, to be designated and to be distinguished from the bonds
of all other series by the title "First Mortgage Bonds, Desig-
nated Secured Medium Term Notes, 6.40% Series due March 1, 2000"
(herein sometimes referred to as the "50th Series"). The form
of the bonds of the 50th Series shall be substantially as set
forth in Schedule I to the supplemental indenture creating the
bonds of the 50th Series.
Bonds of the 50th Series shall mature on the date specified
in their title. Unless otherwise determined by the Company,
the bonds of the 50th Series shall be issued in fully registered
form without coupons in denominations of $1,000 and integral
multiples thereof; the principal of and interest on each said
bond to be payable at the office or agency of the Company, in
the Borough of Manhattan, The City of New York, in lawful money
of the United States of America, provided that at the option
of the Company interest may be mailed to registered owners of
the bonds at their respective addresses that appear on the
register thereof; and the rate of interest shall be the rate
per annum specified in the title thereof, payable semi-annually
on the first days of February and August of each year
(commencing August 1, 1997) and on their maturity date.
The person in whose name any bond of the 50th Series is
registered at the close of business on any record date (as
hereinbelow defined) with respect to any regular semi-annual
interest payment date shall be entitled to receive the interest
payable on such interest payment date notwithstanding the
cancellation of such bond of the 50th Series upon any
registration of transfer or exchange thereof subsequent to the
record date and prior to such interest payment date, except,
if and to the extent that the Company shall default in the
payment of the interest due on such interest payment date, then
the registered holders of bonds of the 50th Series on such
record date shall have no further right to or claim in respect
of such defaulted interest as such registered holders on such
record date, and the persons entitled to receive payment of any
defaulted interest thereafter payable or paid on any bonds of
the 50th Series shall be the registered holders of such bonds
of the 50th Series (or any bond or bonds issued, directly or
after intermediate transactions, upon transfer or exchange or
in substitution thereof) on the date of payment of such
defaulted interest. Interest payable upon maturity shall be
payable to the person to whom principal is paid. The term
"record date" as used in this Section 20 WW, and in the form
of bonds of the 50th Series, with respect to any regular semi-
annual interest payment date shall mean the January 15 next pre-
ceding a February 1 interest payment date or the July 15 next
preceding an August 1 interest payment date, as the case may
be, or, if such January 15 or July 15 is not a Business Day (as
defined hereinbelow), the next preceding Business Day. The term
"Business Day" with respect to any bond of the 50th Series shall
mean any day, other than a Saturday or Sunday, which is not a
day on which banking institutions or trust companies in The City
of New York, New York or the city in which is located any office
or agency maintained for the payment of principal of or interest
on such bond of the 50th Series are authorized or required by
law, regulation or executive order to remain closed.
Every registered bond of the 50th Series shall be dated
the date of authentication ("Issue Date") and shall bear inter-
est computed on the basis of a 360-day year consisting of twelve
30-day months from its Issue Date or from the latest semi-annual
interest payment date to which interest has been paid on the
bonds of the 50th Series preceding the Issue Date, unless such
Issue Date be an interest payment date to which interest is
being paid on the bonds of the 50th Series, in which case it
shall bear interest from its Issue Date or unless the Issue Date
be the record date for the interest payment date first following
the date of original issuance of bonds of the 50th Series
("Original Issue Date"), or a date prior to such record date,
then from the Original Issue Date; provided, that, so long as
there is no existing default in the payment of interest on said
bonds, the holder of any bond authenticated by the Trustee
between the record date for any regular semi-annual interest
payment date and such interest payment date shall not be
entitled to the payment of the interest due on such interest
payment date and shall have no claim against the Company with
respect thereto; provided, further, that, if and to the extent
the Company shall default in the payment of the interest due
on such interest payment date, then any such bond shall bear
interest from the February 1 or August 1, as the case may be,
next preceding its Issue Date, to which interest has been paid
or, if the Company shall be in default with respect to the
interest payment date first following the Original Issue Date,
then from the Original Issue Date.
If any semi-annual interest payment date or the maturity
date is not a Business Day, payment of amounts due on such date
may be made on the next succeeding Business Day, and, if such
payment is made or duly provided for on such Business Day, no
interest shall accrue on such amounts for the period from and
after such interest payment date or the maturity date, as the
case may be, to such Business Day.
Notwithstanding the provisions of Section 14 of this Inden-
ture, the bonds of the 50th Series shall be executed on behalf
of the Company by its Chairman of the Board, by its President
or by one of its Vice Presidents or by one of its officers
designated by the Board of Directors of the Company for such
purpose, whose signature may be a facsimile, and its corporate
seal shall be thereunto affixed or printed thereon and attested
by its Secretary or one of its Assistant Secretaries, and the
provisions of the penultimate sentence of said Section 14 shall
be applicable to such bonds of the 50th Series.
The bonds of the 50th Series shall not be redeemable prior
to maturity.
Notwithstanding the provisions of Section 12 of this
Indenture, the Company shall not be required to make transfers
or exchanges of bonds of the 50th Series for a period of sixteen
days next preceding any interest payment date.
Registered bonds of the 50th Series shall be transferable
upon presentation and surrender thereof, for cancellation, at
the office or agency of the Company in the Borough of Manhattan,
The City of New York, and at such other office or agency of the
Company as the Company may designate, by the registered holders
thereof, in person or by duly authorized attorney, in the manner
and upon payment, if required by the Company, of the charges
prescribed in this Indenture. In the manner and upon payment,
if the Company shall require it, of the charges prescribed in
this Indenture, registered bonds of the 50th Series may be
exchanged for a like aggregate principal amount of registered
bonds of the 50th Series of other authorized denominations, upon
presentation and surrender thereof, for cancellation, at the
office or agency of the Company in the Borough of Manhattan,
The City of New York and at such other office or agency of the
Company as the Company may from time to time designate.
Section 2. The Original Indenture is hereby supplemented
by adding thereto the following new Article III BBBB to be added
after Article III AAAA of the Original Indenture:
ARTICLE III BBBB.
Initial Issuance of Bonds of the 50th Series.
Section 21 BBBB. In accordance with and upon compliance with
such provisions of this Indenture as shall be selected for such
purpose by the officers of the Company duly authorized to take such
action, bonds of the 50th Series in an aggregate principal amount
not exceeding $48,000,000 shall forthwith be executed by the Company
and delivered to the Trustee and shall be authenticated by the
Trustee and delivered to or upon the order of the Company (without
awaiting the filing and recording of the supplemental indenture
creating the 50th Series except to the extent required by Section
28 of this Indenture).
Section 3. At any meeting of bondholders held as provided
for in Article XVIII of the Original Indenture at which holders of
bonds of the 50th Series are entitled to vote, all holders of bonds
of the 50th Series at the time of such meeting shall be entitled to
vote thereat; provided, however, that the Trustee may, and upon
request of the Company or of a majority of the bondholders of the
50th Series shall, fix a day not exceeding ninety days preceding the
date for which the meeting is called as a record date for the
determination of holders of bonds of the 50th Series entitled to
notice of and to vote at such meeting and any adjournment thereof
and only such registered owners who shall have been such registered
owners on the date so fixed, and who are entitled to vote such bonds
of the 50th Series at the meeting, shall be entitled to receive
notice of such meeting.
Section 4. As supplemented by this First 1997 Supplemental
Indenture, the Original Indenture is in all respects ratified and
confirmed and the Original Indenture and this First 1997 Supplemental
Indenture shall be read, taken and construed as one and the same
instrument. The bonds of the 50th Series are the original debt
secured by this First 1997 Supplemental Indenture and the Original
Indenture, and this First 1997 Supplemental Indenture and the
Original Indenture shall be, and be deemed to be, the original lien
instrument securing the bonds of the 50th Series.
Nothing contained in this First 1997 Supplemental Indenture
shall, or shall be construed to, confer upon any person other than
the owners of bonds issued under the Original Indenture and this
First 1997 Supplemental Indenture, the Company and the Trustee, any
right to avail themselves of any benefit of any provision of the
Original Indenture or of this First 1997 Supplemental Indenture.
The Trustee assumes no responsibility for the correctness of
the recitals of facts contained herein and makes no representations
as to the validity of this First 1997 Supplemental Indenture.
This First 1997 Supplemental Indenture may be simultaneously
executed in any number of counterparts, each of which when so exe-
cuted shall be deemed to be an original; but such counterparts shall
together constitute but one and the same instrument.
In Witness Whereof, Indiana Michigan Power Company, party of
the first part, has caused this instrument to be signed in its name
and behalf by its President, a Vice President, its Treasurer or an
Assistant Treasurer, and its corporate seal to be hereunto affixed
and attested by its Secretary or an Assistant Secretary, and The Bank
of New York, party of the second part, has caused this instrument
to be signed in its name and behalf by a Vice President or an
Assistant Vice President and its corporate seal to be hereunto
affixed and attested by an Assistant Treasurer. Executed and deliv-
ered in The City of New York, N.Y., as of the day and year first
above written.
INDIANA MICHIGAN POWER COMPANY
[Seal] By: /s/ A. A. Pena
(A. A. Pena)
Treasurer
Attest:
/s/ John F. Di Lorenzo, Jr.
(John F. Di Lorenzo, Jr.)
Secretary
Signed, sealed and delivered by
Indiana Michigan Power Company
in the presence of
/s/ Ann B. Graf
(Ann B. Graf)
/s/ B. M. Barber
(B. M. Barber)
The Bank of New York,
as Trustee
[Seal] By: /s/ Frederick W. Clark
(Frederick W. Clark)
Vice President
Attest:
/s/ Marie E. Trimboli
(Marie E. Trimboli)
Assistant Treasurer
Signed, sealed and delivered by
The Bank of New York in the presence of:
/s/ Jason G. Gregory
(Jason G. Gregory)
/s/ Miriam Osorio
(Miriam Osorio)
State of Ohio )
) ss.:
County of Franklin )
On this 7th day of February, 1997, personally appeared
before me, a Notary Public within and for said County in the State
aforesaid, A. A. PENA and JOHN F. DiLORENZO, JR., to me known and
known to me to be respectively the Treasurer and Secretary of INDIANA
MICHIGAN POWER COMPANY, one of the corporations named in and which
executed the foregoing instrument, who severally acknowledged that
they did sign and seal said instrument as such Treasurer and
Secretary for and on behalf of said corporation and that the same
is their free act and deed as such Treasurer and Secretary,
respectively, and the free and corporate act and deed of said
corporation.
IN WITNESS WHEREOF, I have hereunto set my hand and official
seal at Columbus, Ohio, this 7th day of February, 1997.
[Notarial Seal]
/s/ Jana Lee Brown
Jana Lee Brown
Notary Public, State of Ohio
My Commission Expires
March 15, 2000
State of New York )
) SS.:
County of New York )
I certify that on this 11th day of February, 1997, before me
Patricia M. Carillo, a Notary Public in and for said County and
State, appeared Frederick W. Clark, to me personally known and known
to me to be a Vice President of The Bank of New York and one of the
persons whose name is signed to the foregoing instrument, who, being
by me duly sworn, deposed and said that he resides at 512 Green
Mountain Road, Mahwah, New Jersey 07430, that he is a Vice President
of The Bank of New York, that he knows the corporate seal of said
corporation; that the seal affixed to the foregoing instrument is
the corporate seal of the said corporation; that it was so affixed
by order of said corporation, and that he signed his name as Vice
President of said corporation to said instrument by like order; and
thereupon said Frederick W. Clark acknowledged that he signed said
instrument as his free and voluntary act and that said corporation
executed said instrument, as Trustee, as its free and voluntary act
for the purposes and uses therein set forth.
In Witness Whereof I have hereunto set my hand and official seal
this 11th day of February, 1997.
[Seal]
/s/ Patricia M. Carillo
Patricia M. Carillo
Notary Public, State of New York
No. 41-4747732
Qualified in Queens County
Certificate Filed in New York County
Commission Expires May 31, 1997
This instrument was drafted by Ann B. Graf, Esq., whose business
address is 1 Riverside Plaza, Columbus, Ohio 43215.
SCHEDULE I
INDIANA MICHIGAN POWER COMPANY
FIRST MORTGAGE BOND, DESIGNATED
SECURED MEDIUM TERM NOTE, 6.40%
SERIES DUE MARCH 1, 2000
Bond No.
Original Issue Date: February 19, 1997
Principal Amount:
Semi-annual Interest Payment Dates: February 1 and August 1
Record Dates: January 15 and July 15
CUSIP No.: 45489H AT 4
INDIANA MICHIGAN POWER COMPANY, a corporation of the State
of Indiana (hereinafter called the "Company"), for value received,
hereby promises to pay to ____________ or registered assigns, the
Principal Amount set forth above on the maturity date specified in
the title of this bond in lawful money of the United States of
America, at the office or agency of the Company in the Borough of
Manhattan, The City of New York, and to pay to the registered holder
hereof interest on said amount from the date of authentication of
this bond (herein called the "Issue Date") or the latest semi-annual
interest payment date to which interest has been paid on the bonds
of this series preceding the Issue Date, unless the Issue Date be
an interest payment date to which interest is being paid, in which
case from the Issue Date or unless the Issue Date be the record date
for the interest payment date first following the Original Issue Date
set forth above or a date prior to such record date, then from the
Original Issue Date (or, if the Issue Date is between the record date
for any interest payment date and such interest payment date, then
from such interest payment date, provided, however, that if and to
the extent that the Company shall default in the payment of the
interest due on such interest payment date, then from the next pre-
ceding semi-annual interest payment date to which interest has been
paid on the bonds of this series, or if such interest payment date
is the interest payment date first following the Original Issue Date
set forth above, then from the Original Issue Date), until the prin-
cipal hereof shall have become due and payable, at the rate per annum
specified in the title of this bond, payable on February 1 and August
1 of each year (commencing August 1, 1997) and on the maturity date
specified in the title of this bond; provided that, at the option
of the Company, such interest may be paid by check, mailed to the
registered owner of this bond at such owner's address appearing on
the register hereof.
This bond is one of a duly authorized issue of bonds of the
Company, issuable in series, and is one of a series known as its
First Mortgage Bonds, of the series designated in its title, all
bonds of all series issued and to be issued under and equally secured
(except in so far as any sinking fund, established in accordance with
the provisions of the Mortgage hereinafter mentioned, may afford
additional security for the bonds of any particular series) by a
Mortgage and Deed of Trust (herein, together with any indentures
supplemental thereto, called the Mortgage), dated as of June 1, 1939,
executed by the Company to IRVING TRUST COMPANY (now THE BANK OF NEW
YORK) and FREDERICK G. HERBST, as Trustees, to which Mortgage refer-
ence is made for a description of the property mortgaged and pledged,
the nature and extent of the security, the rights of the holders of
the bonds and of the Trustee in respect thereof, the duties and
immunities of the Trustee, and the terms and conditions upon which
the bonds are secured. With the consent of the Company and to the
extent permitted by and as provided in the Mortgage, the rights and
obligations of the Company and/or of the holders of the bonds and/or
coupons and/or the terms and provisions of the Mortgage and/or of
any instruments supplemental thereto may be modified or altered by
the affirmative vote of the holders of at least seventy-five per
centum (75%) in principal amount of the bonds affected by such modi-
fication or alteration, then outstanding under the Mortgage
(excluding bonds disqualified from voting by reason of the Company's
interest therein as provided in the Mortgage); provided that without
the consent of the holder hereof no such modification or alteration
shall permit the extension of the maturity of the principal of or
interest on this bond or the reduction in the rate of interest hereon
or any other modification in the terms of payment of such principal
or interest or the creation of a lien on the mortgaged and pledged
property ranking prior to or on a parity with the lien of the Mort-
gage or the deprivation of the holder hereof of a lien upon such
property or reduce the above percentage.
As provided in said Mortgage, said bonds may be for various
principal sums and are issuable in series, which may mature at
different times, may bear interest at different rates and may other-
wise vary as therein provided. This bond is created by an Indenture
Supplemental dated as of February 1, 1997 (the "First 1997 Supplemen-
tal Indenture"), as provided for in said Mortgage.
The interest payable on any February 1 or August 1 will, subject
to certain exceptions provided in said First 1997 Supplemental Inden-
ture, be paid to the person in whose name this bond is registered
at the close of business on the record date, which shall be the
January 15 or July 15, as the case may be, next preceding such
interest payment date, or, if such January 15 or July 15 is not a
Business Day (as hereinbelow defined), the next preceding Business
Day. Interest payable upon maturity shall be payable to the person
to whom principal is paid. The term "Business Day" means any day,
other than a Saturday or Sunday, which is not a day on which banking
institutions or trust companies in The City of New York, New York
or the city in which is located any office or agency maintained for
the payment of principal of or interest on bonds of this series are
authorized or required by law, regulation or executive order to
remain closed.
If any semi-annual interest payment date or the maturity date
is not a Business Day, payment of amounts due on such date may be
made on the next succeeding Business Day, and, if such payment is
made or duly provided for on such Business Day, no interest shall
accrue on such amounts for the period from and after such interest
payment date or the maturity date, as the case may be, to such
Business Day.
The Company and the Trustee may deem and treat the person in
whose name this bond is registered as the absolute owner hereof for
the purpose of receiving payment of or on account of principal or
(subject to the provisions hereof) interest hereon and for all other
purposes and the Company and the Trustee shall not be affected by
any notice to the contrary.
The Company shall not be required to make transfers or exchanges
of bonds of this series for a period of sixteen days next preceding
any interest payment date.
The bonds of this series shall not be redeemable prior to
maturity.
The principal hereof may be declared or may become due prior
to the express date of the maturity hereof on the conditions, in the
manner and at the time set forth in the Mortgage, upon the occurrence
of a completed default as in the Mortgage provided.
This bond is transferable as prescribed in the Mortgage by the
registered owner hereof in person, or by his duly authorized
attorney, at the office or agency of the Company in the Borough of
Manhattan, The City of New York, and at such other office or agency
of the Company as the Company may designate, upon surrender and
cancellation of this bond and upon payment, if the Company shall
require it, of the transfer charges prescribed in the Mortgage, and,
thereupon, a new registered bond or bonds of authorized denominations
of the same series for a like principal amount will be issued to the
transferee in exchange herefor as provided in the Mortgage. In the
manner and upon payment, if the Company shall require it, of the
charges prescribed in the Mortgage, registered bonds of this series
may be exchanged for a like aggregate principal amount of registered
bonds of other authorized denominations of the same series, upon
presentation and surrender thereof, for cancellation, at the office
or agency of the Company in the Borough of Manhattan, The City of
New York, or at such other office or agency of the Company as the
Company may designate.
No recourse shall be had for the payment of the principal of
or interest on this bond against any incorporator or any past,
present or future stockholder, officer or director, as such, of the
Company, or of any successor corporation, either directly or through
the Company or any successor corporation, under any rule of law,
statute or constitution or by the enforcement of any assessment or
otherwise, all such liability of incorporators, stockholders,
officers and directors, as such, being waived and released by the
holder or owner hereof by the acceptance of this bond and being
likewise waived and released by the terms of the Mortgage.
This bond shall not become valid or obligatory for any purpose
until THE BANK OF NEW YORK, the Trustee under the Mortgage, or its
successor thereunder, shall have signed the form of Authentication
Certificate endorsed hereon.
In Witness Whereof, Indiana Michigan Power Company has caused
this instrument to be duly executed under its corporate seal.
Dated:
INDIANA MICHIGAN POWER COMPANY
By:
Vice President
(SEAL)
Attest:
Assistant Secretary
TRUSTEE'S AUTHENTICATION CERTIFICATE
This bond is one of the bonds,
of the series herein designated,
described in the within-mentioned
Mortgage.
THE BANK OF NEW YORK,
as Trustee,
By:
Authorized Officer
FOR VALUE RECEIVED, the undersigned hereby sell(s),
assign(s) and transfer(s) unto
(PLEASE INSERT SOCIAL SECURITY OR OTHER
IDENTIFYING NUMBER OF ASSIGNEE)
_______________________________________
________________________________________________________________
________________________________________________________________
(PLEASE PRINT OR TYPE NAME AND ADDRESS, INCLUDING ZIP CODE, OF
________________________________________________________________
ASSIGNEE) the within Bond and all rights thereunder, hereby
________________________________________________________________
irrevocably constituting and appointing such person attorney to
________________________________________________________________
transfer such bond on the books of the Issuer, with full power of
________________________________________________________________
substitution in the premises.
Dated: ______________________ ____________________________
NOTICE: The signature to this assignment must correspond with the
name as written upon the face of the within Bond in every
particular without alteration or enlargement or any change
whatsoever.
<PAGE>
<TABLE>
EXHIBIT 12
INDIANA MICHIGAN POWER COMPANY
Computation of Consolidated Ratio of Earnings to Fixed Charges
(in thousands except ratio data)
<CAPTION>
Year Ended December 31,
1992 1993 1994 1995 1996
<S> <C> <C> <C> <C> <C>
Fixed Charges:
Interest on First Mortgage Bonds. . . . . . . . $ 56,965 $ 53,771 $ 43,564 $ 43,410 $ 41,209
Interest on Other Long-term Debt. . . . . . . . 26,330 23,504 24,725 23,564 20,100
Interest on Short-term Debt . . . . . . . . . . 1,614 1,085 1,883 2,003 2,982
Miscellaneous Interest Charges. . . . . . . . . 2,866 3,039 3,520 3,472 3,262
Estimated Interest Element in Lease Rentals . . 84,800 84,300 85,000 82,700 82,600
Total Fixed Charges. . . . . . . . . . . . $172,575 $165,699 $158,692 $155,149 $150,153
Earnings:
Net Income. . . . . . . . . . . . . . . . . . . $123,983 $129,344 $157,502 $141,092 $157,153
Plus Federal Income Taxes . . . . . . . . . . . 28,191 38,826 32,303 55,990 76,899
Plus State Income Taxes . . . . . . . . . . . . 1,547 7,492 6,063 7,058 9,270
Plus Fixed Charges (as above) . . . . . . . . . 172,575 165,699 158,692 155,149 150,153
Total Earnings . . . . . . . . . . . . . . $326,296 $341,361 $354,560 $359,289 $393,475
Ratio of Earnings to Fixed Charges. . . . . . . . 1.89 2.06 2.23 2.31 2.62
</TABLE>
I&M 1996 ANNUAL REPORT
<PAGE>
<PAGE>
<TABLE>
Selected Consolidated Financial Data
<CAPTION>
Year Ended December 31,
1996 1995 1994 1993 1992
(in thousands)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENTS DATA:
Operating Revenues $1,328,493 $1,283,157 $1,251,309 $1,202,643 $1,196,755
Operating Expenses 1,108,076 1,077,434 1,029,340 992,485 1,000,967
Operating Income 220,417 205,723 221,969 210,158 195,788
Nonoperating Income (Loss) 2,729 6,272 7,428 (234) 14,115
Income Before Interest Charges 223,146 211,995 229,397 209,924 209,903
Interest Charges 65,993 70,903 71,895 80,580 85,920
Net Income 157,153 141,092 157,502 129,344 123,983
Preferred Stock Dividend Requirement 10,681 11,791 11,681 14,256 15,452
Earnings Applicable to Common Stock $ 146,472 $ 129,301 $ 145,821 $ 115,088 $ 108,531
<CAPTION>
December 31,
1996 1995 1994 1993 1992
(in thousands)
<S> <C> <C> <C> <C> <C>
BALANCE SHEETS DATA:
Electric Utility Plant $4,377,669 $4,319,564 $4,269,306 $4,290,957 $4,266,480
Accumulated Depreciation and
Amortization 1,861,893 1,751,965 1,659,940 1,714,829 1,631,438
Net Electric Utility Plant $2,515,776 $2,567,599 $2,609,366 $2,576,128 $2,635,042
Total Assets $3,897,484 $3,928,337 $3,878,035 $3,723,648 $3,608,645
Common Stock and Paid-in Capital $ 787,856 $ 787,686 $ 790,234 $ 790,625 $ 781,818
Retained Earnings 269,071 235,107 216,658 177,638 171,309
Total Common Shareholder's Equity $1,056,927 $1,022,793 $1,006,892 $ 968,263 $ 953,127
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption $ 21,977 $ 52,000 $ 52,000 $ 87,000 $ 197,000
Subject to Mandatory Redemption (a) 135,000 135,000 135,000 100,000 -
Total Cumulative Preferred Stock $ 156,977 $ 187,000 $ 187,000 $ 187,000 $ 197,000
Long-term Debt (a) $1,042,104 $1,040,101 $1,069,887 $1,073,154 $1,211,623
Obligations Under Capital Leases (a) $ 130,965 $ 142,506 $ 152,589 $ 98,753 $ 126,689
Total Capitalization and Liabilities $3,897,484 $3,928,337 $3,878,035 $3,723,648 $3,608,645
(a) Including portion due within one year.
</TABLE>
<PAGE>
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
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 the American Electric Power (AEP) System,
Indiana Michigan Power Company and our changing industry. The industry's
adjustment to greater competition in generation and sales of electricity,
customer choice and the ability to fully recover costs will probably be the
most significant factors affecting the Company's future profitability.
Although the Company, as a member of the AEP System, has the financial
strength, geographic reach, location and cost structure to be an able
competitor, no assurance can be given that this position can be maintained.
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 maintaining a strong financial position.
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 AEP's
transmission grid at 143 interconnections to all parties under the same terms
and conditions available to AEP affiliates. This has provided greater
opportunities for transmission service sales.
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 changes, if any. We are actively involved in discussions on the
state and federal level regarding whether to and how best to transition to
competition in order to represent the best interests of our customers,
shareholders and employees. We favor an orderly and smooth transition to a
more competitive energy market because we believe that AEP will do better in
the long term if it is free to compete.
If the electric energy market evolves from cost-of-service rate-making
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 recovery 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 the Company 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,"
regulatory assets (deferred expenses) and regulatory 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 and assets tested for possible impairment. Whether an
impairment exists would depend on how low the market price of energy is in
competition relative to the cost of energy.
Among other requirements the application of SFAS 71 requires that the
rates charged customers be cost based. Our generation business is still
cost-based regulated and should remain so for the foreseeable future. Should
enabling state legislation be enacted we believe there should be at least a
three to five year transition 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 our firm wholesale sales are still
under cost-of-service contracts. We believe that enabling state
legislation if enacted 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. However, if the Company were to
no longer be cost-based regulated and recovery of stranded costs were not
possible, results of operations and financial condition 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, are aggressively pursuing deregulation. The
states the Company operates in, however, are generally addressing the call
for customer choice more cautiously.
Restructuring/Functional Unbundling
In 1996 we took some major steps to maintain and enhance the Company's
competitive strength. We restructured our management and operations to allow
us to comply with the new FERC orders which required separation of generation
and energy sales operations from our energy transmission and delivery
operations. This has achieved and should continue to achieve staffing,
managerial and operating efficiencies. The generation and marketing business
units are preparing for the possibility of competition in an open market for
customers. Our energy delivery business expects to remain regulated and
ultimately be subject to some form of incentive or performance-based
ratemaking. If competition never replaces regulation we will be a more
efficient and productive business as a result of our preparations which
should benefit all concerned.
Marketing and customer service efforts have been enhanced with programs
like the Key Accounts Program which strives to build strong partnerships with
key customers in order to build customer loyalty. In 1996 we also launched a
series of new television commercials to inform our customers that we will be
operating under the name, American Electric Power. The commercials are
intended to position AEP as more than just a supplier of electricity. We
want to be the energy and energy services provider of choice; AEP: America's
Energy Partner.
<PAGE>
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, 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. 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 programs,
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 the
Company to maintain its position as a low-cost producer.
Fuel Costs
Coal is 30% of the production cost of electricity. Although our coal
costs per unit of electricity (per kwh) have declined we recognize that we
must continue to manage our coal costs to maintain our competitive position.
As long-term coal supply contracts expire we are negotiating with non-affiliated
suppliers to lower purchased coal costs. We intend to continue to
prudently supplement our long-term coal supplies with spot market purchases
as long as favorable spot market prices exist.
Nuclear Cost
Significant efforts have been made to enhance our competitiveness by
improving the efficiency of the Company's nuclear operations. 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 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 3 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.
<PAGE>
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 nondiscounted dollars. This estimate could increase 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, the Company'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 Matters
We take great pride in our efforts to economically produce and deliver
electricity while minimizing the impact on the environment. Indiana Michigan
Power Company has spent hundreds of millions of dollars to equip our
facilities with the latest economical clean air and water technologies and to
research possible new technologies. We intend to continue to take a
leadership role to foster economically prudent efforts to protect and
preserve the environment.
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 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. The Company is 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, I&M
is currently involved in litigation with respect to two sites, and has been
named by the Federal EPA as a "Potentially Responsible Party" (PRP) for two
other sites. There are five additional sites for which the Company has
received information requests which could lead to PRP designation as well as
information requests for two state administered sites. I&M's liability has
been resolved for a number of sites with no significant effect on results of
operations. The Company's present estimates do not anticipate material
cleanup costs for identified sites for which I&M has been declared a PRP.
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.
<PAGE>
Results of Operations
In 1996 net income increased $16 million or 11%. The increase is mainly
attributable to increased wholesale sales, a reduction in maintenance expense
and reduced financing costs. Also contributing to the 1996 increase were
severance pay charges recorded in 1995 in connection with realigning
operations and management and gains recorded in 1996 from emission allowance
transactions. Although revenues increased 2.5% in 1995, net income declined
$16 million or 10% as the result of increased operating expenses, including
the unfavorable effect of a provision for severance benefits in connection
with the realignment of operations, and increased federal income tax expense.
Operating Revenues and Energy Sales Increase
Operating revenues increased 3.5% in 1996 following a 2.5% increase in
1995. The price, volume analysis of revenue variances which accounted for the
improved results are:
Increase (Decrease)
From Previous Year
(dollars in millions) 1996 1995
Amount % Amount %
Retail:
Price Variance $(25.9) $ (0.7)
Volume Variance 32.8 29.9
6.9 0.8 29.2 3.3
Wholesale:
Price Variance (55.6) (116.9)
Volume Variance 89.6 121.4
34.0 9.5 4.5 1.3
Other Operating Revenues 4.4 (1.9)
Total $ 45.3 3.5 $ 31.8 2.5
Operating revenues increased in 1996 primarily as a result of increased
wholesale sales attributable to increased internal generation being supplied
to the AEP System Power Pool (Power Pool) and unaffiliated utilities. The
Company's share of Power Pool allocated sales increased 40% due to increased
transactions with other utilities and power marketers. During 1996 the
Company provided a new product, coal conversion services, to power marketers
and unaffiliated utilities resulting in 1.2 billion kilowatthours of
electricity being generated under a new FERC-approved interruptible tariff.
Under this tariff the Company converts the coal of a wholesale customer to
electricity for a fee.
The increase in 1995 operating revenues resulted from increased energy
usage by retail and unaffiliated wholesale customers. Retail energy sales
increased 3% reflecting warmer summer weather and a colder fourth quarter in
1995 than in 1994 and continued growth in the number of retail customers.
While wholesale energy sales increased 34%, wholesale revenues increased by
only 1% in 1995. The substantial increase in wholesale energy sales was
primarily due to a 69% increase in energy sales to the Power Pool reflecting
the increased availability of the Company's lower cost nuclear generating
capacity in 1995. During 1995 one nuclear generating unit was out of service
for refueling while both units were refueled in 1994. Sales to the Company's
municipal and cooperative customers and to unaffiliated utilities by the
Power Pool increased primarily due to weather related factors in 1995 versus
1994. The increase in wholesale sales did not lead to a corresponding
increase in revenues due to reduced capacity credits from the Power Pool and
increasing competition in the wholesale energy market. Capacity credits,
which are designed to allocate the cost of the AEP System's generating
capacity among the members of the Power Pool based on their relative peak
demands and generating reserves, were lower reflecting the effect of an
increase in the Company's peak demand during 1995.
Operating Expenses Increase
Total operating expenses increased 2.8% in 1996 or $30.6 million mainly
due to the increased operation of the Company's nuclear units, increased
Power Pool wholesale transactions, and higher income taxes partially offset
by significant reductions in maintenance expense. In 1995, total operating
expenses rose 4.7% or $48.1 million reflecting the increased operation of the
Company's nuclear units and severance pay accruals. The significant changes
in operating expenses were:
Increase (Decrease)
From Previous Year
dollars in millions) 1996 1995
Amount % Amount %
Fuel $ 13.3 6.0 $ 21.2 10.5
Purchased Power 13.3 10.6 (5.8) (4.4)
Other Operation 3.5 1.2 10.3 3.5
Maintenance (26.5) (18.7) 2.4 1.7
Federal Income Taxes 23.5 43.5 15.7 40.9
Fuel expense increased in 1996 due to a 17% increase in nuclear
generation made possible by the shorter refueling outage in 1996 versus an
extended refueling and maintenance outage in 1995. This increase was
partially offset by a lower average price per ton of coal consumed from a
favorable settlement of a coal transportation dispute. Fuel expense increased
substantially in 1995 due to a 51% increase in nuclear generation reflecting
the increased availability from having only one refueling outage in 1995
versus two in 1994.
The 1996 rise in purchased power expense was mainly due to additional
power purchases under an agreement with the Ohio Valley Electric Corporation,
an affiliated company which is not a member of the Power Pool, and increased
purchases from the Power Pool to support the Company's allocated share of
higher Power Pool wholesale transactions with non-affiliated utilities. The
1995 reduction in purchased power expense can be attributed to increased
availability of the Company's nuclear generation.
Other operation expense increased in 1995 primarily due to a provision
for severance pay related to the functional realignment of operations and
costs related to the development of a new activity based budgeting system.
Maintenance expense was substantially lower in 1996 due to
cost-reduction measures at the Company's nuclear plant, which reduced the
number of employees performing maintenance and lowered payments for contract
maintenance labor.
The increase in 1996 federal income taxes resulted from an increase in
pre-tax operating income and changes in certain book/tax differences
accounted for on a flow-through basis for rate-making purposes. Federal
income taxes increased in 1995 primarily due to changes in certain book/tax
timing differences accounted for on a flow-through basis and the effects of
favorable accrual adjustments recorded in 1994 in connection with the
resolution of the audit of prior years' tax returns.
<PAGE>
Financing Costs
A decline in interest charges occurred in 1996 due to debt repayments
and a refinancing program which lowered interest rates.
Construction Spending
Gross plant and property additions were $144 million in 1996 and $151
million in 1995. Management estimates construction expenditures for the next
three years to be $340 million with no major new generating plant
construction planned. The funds for construction of new facilities and
improvement of existing facilities can come from a combination of internally
generated funds, short-term and long-term borrowings, preferred stock
issuances and investments in common equity by the Company's parent, American
Electric Power Company, Inc. (AEP Co., Inc.) However, all of the
construction expenditures for the next three years are expected to be
financed with internally generated funds.
Liquidity and Capital Resources
When necessary the Company generally issues short-term debt to provide
for interim financing of capital expenditures that exceed internally
generated funds. At December 31, 1996, $409 million of unused short-term
lines of credit shared with other AEP System companies were available.
Short-term debt borrowings are limited by provisions of the Public Utility
Holding Company Act of 1935 to $175 million. Periodic reductions of
outstanding short-term debt are made through issuances of long-term debt and
preferred stock and through additional capital contributions by the parent
company.
The Company's earnings coverage presently exceeds all minimum coverage
requirements for the issuance of mortgage bonds and preferred stock. The
minimum coverage ratios are 2.0 for mortgage bonds and 1.5 for preferred
stock. At December 31, 1996, the mortgage bonds and preferred stock coverage
ratios were 6.66 and 3.07, respectively.
In January 1997 a tender offer was announced for all of the Company's
preferred stock in conjunction with a special meeting scheduled to be held on
February 28, 1997. The special meeting's purpose is to consider amendments
to the Company's articles of incorporation to remove certain capitalization
ratio requirements. These restrictions limit the Company's financial
flexibility and could place it at a competitive disadvantage in the future.
The amount paid to redeem the preferred stock that is tendered could total as
much as $154 million. A combination of short-term debt and unsecured
long-term debt is expected to be used to pay for the preferred stock tendered.
Litigation
The Company 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.
Effects of Inflation
Inflation affects the Company's cost of replacing utility plant and the
cost of operating and maintaining plant. The rate-making process generally
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 result from the repayment of
long-term debt with inflated dollars partly offset the negative impact of
inflation.
Corporate Owned Life Insurance
In connection with the audit of the AEP System's 1991, 1992 and 1993
consolidated federal income tax returns the Internal Revenue Service (IRS)
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 approximately $51 million (including interest). Management
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 Rule
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 Company 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, the Company 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 the Company cannot determine its ultimate impact.
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Indiana Michigan Power Company:
We have audited the accompanying consolidated balance sheets of Indiana
Michigan Power Company and its subsidiaries as of December 31, 1996 and 1995,
and the related consolidated statements of income, retained earnings, and
cash flows for each of the three years in the period ended December 31, 1996.
These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Indiana Michigan Power Company
and its subsidiaries as of December 31, 1996 and 1995, and the results of
their operations and their cash flows for each of the three years in the
period ended December 31, 1996 in conformity with generally accepted
accounting principles.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 25, 1997
<PAGE>
<PAGE>
<TABLE>
Consolidated Statements of Income
<CAPTION>
Year Ended December 31,
1996 1995 1994
(in thousands)
<S> <C> <C> <C>
OPERATING REVENUES $1,328,493 $1,283,157 $1,251,309
OPERATING EXPENSES:
Fuel 236,237 222,967 201,739
Purchased Power 138,687 125,413 131,234
Other Operation 310,513 306,967 296,625
Maintenance 115,300 141,813 139,423
Depreciation and Amortization 140,437 138,814 136,244
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals 15,644 15,644 15,644
Taxes Other Than Federal Income Taxes 73,729 71,791 70,078
Federal Income Taxes 77,529 54,025 38,353
Total Operating Expenses 1,108,076 1,077,434 1,029,340
OPERATING INCOME 220,417 205,723 221,969
NONOPERATING INCOME 2,729 6,272 7,428
INCOME BEFORE INTEREST CHARGES 223,146 211,995 229,397
INTEREST CHARGES 65,993 70,903 71,895
NET INCOME 157,153 141,092 157,502
PREFERRED STOCK DIVIDEND REQUIREMENTS 10,681 11,791 11,681
EARNINGS APPLICABLE TO COMMON STOCK $ 146,472 $ 129,301 $ 145,821
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
Consolidated Statements of Cash Flows
<CAPTION>
Year Ended December 31,
1996 1995 1994
(in thousands)
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net Income $ 157,153 $ 141,092 $ 157,502
Adjustments for Noncash Items:
Depreciation and Amortization 148,123 148,441 146,966
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals 15,644 15,644 15,644
Amortization (Deferral) of Incremental Nuclear
Refueling Outage Expenses (net) 7,662 8,684 (18,779)
Deferred Federal Income Taxes (24,687) (23,564) (19,775)
Deferred Investment Tax Credits (8,729) (9,004) (13,877)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (10,235) 4,121 (7,200)
Fuel, Materials and Supplies 903 (6,255) (3,423)
Accrued Utility Revenues 5,642 (3,355) (5,940)
Accounts Payable 1,186 (2,431) 5,219
Taxes Accrued (6,296) 8,075 9,148
Other (net) 7,975 (23,099) (12,145)
Net Cash Flows From Operating Activities 294,341 258,349 253,340
INVESTING ACTIVITIES:
Construction Expenditures (95,046) (117,785) (118,094)
Long-term Receivable from Customer
for Construction of Facilities 62 (18,733) -
Proceeds from Sales of Property and Other 2,714 9,325 2,038
Net Cash Flows Used For Investing Activities (92,270) (127,193) (116,056)
FINANCING ACTIVITIES:
Issuance of Cumulative Preferred Stock - - 34,618
Issuance of Long-term Debt 38,579 96,819 89,221
Retirement of Cumulative Preferred Stock (30,568) - (35,798)
Retirement of Long-term Debt (46,091) (141,122) (101,833)
Change in Short-term Debt (net) (46,475) 39,375 525
Dividends Paid on Common Stock (112,508) (110,852) (106,608)
Dividends Paid on Cumulative Preferred Stock (10,498) (11,560) (11,254)
Net Cash Flows Used For Financing Activities (207,561) (127,340) (131,129)
Net Increase (Decrease) in Cash and
Cash Equivalents (5,490) 3,816 6,155
Cash and Cash Equivalents January 1 13,723 9,907 3,752
Cash and Cash Equivalents December 31 $ 8,233 $ 13,723 $ 9,907
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
Consolidated Balance Sheets
<CAPTION>
December 31,
1996 1995
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production $2,525,969 $2,507,667
Transmission 881,407 867,541
Distribution 696,069 666,810
General (including nuclear fuel) 189,619 186,959
Construction Work in Progress 84,605 90,587
Total Electric Utility Plant 4,377,669 4,319,564
Accumulated Depreciation and Amortization 1,861,893 1,751,965
NET ELECTRIC UTILITY PLANT 2,515,776 2,567,599
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
FUEL DISPOSAL TRUST FUNDS 490,778 433,619
OTHER PROPERTY AND INVESTMENTS 154,265 150,994
CURRENT ASSETS:
Cash and Cash Equivalents 8,233 13,723
Accounts Receivable:
Customers 90,656 82,434
Affiliated Companies 13,727 21,881
Miscellaneous 21,439 11,450
Allowance for Uncollectible Accounts (156) (334)
Fuel - at average cost 23,977 29,093
Materials and Supplies - at average cost 77,074 72,861
Accrued Utility Revenues 38,295 43,937
Prepayments 10,271 10,191
TOTAL CURRENT ASSETS 283,516 285,236
REGULATORY ASSETS 421,692 458,525
DEFERRED CHARGES 31,457 32,364
TOTAL $3,897,484 $3,928,337
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
December 31,
1996 1995
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares $ 56,584 $ 56,584
Paid-in Capital 731,272 731,102
Retained Earnings 269,071 235,107
Total Common Shareholder's Equity 1,056,927 1,022,793
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 21,977 52,000
Subject to Mandatory Redemption 135,000 135,000
Long-term Debt 1,042,104 1,034,048
TOTAL CAPITALIZATION 2,256,008 2,243,841
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 313,845 269,392
Other 174,903 184,103
TOTAL OTHER NONCURRENT LIABILITIES 488,748 453,495
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 6,053
Short-term Debt 43,500 89,975
Accounts Payable - General 31,015 37,744
Accounts Payable - Affiliated Companies 30,877 22,962
Taxes Accrued 65,400 71,696
Interest Accrued 15,281 16,158
Obligations Under Capital Leases 29,740 31,776
Other 66,436 74,463
TOTAL CURRENT LIABILITIES 282,249 350,827
DEFERRED INCOME TAXES 594,879 612,147
DEFERRED INVESTMENT TAX CREDITS 146,473 155,202
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 96,125 99,832
DEFERRED CREDITS 33,002 12,993
COMMITMENTS AND CONTINGENCIES (Note 3)
TOTAL $3,897,484 $3,928,337
</TABLE>
<PAGE>
<PAGE>
<TABLE>
Consolidated Statements of Retained Earnings
<CAPTION>
Year Ended December 31,
1996 1995 1994
(in thousands)
<S> <C> <C> <C>
Retained Earnings January 1 $235,107 $216,658 $177,638
Net Income 157,153 141,092 157,502
392,260 357,750 335,140
Deductions:
Cash Dividends Declared:
Common Stock 112,508 110,852 106,608
Cumulative Preferred Stock:
4-1/8% Series 495 495 495
4.56% Series 273 273 273
4.12% Series 165 165 165
5.90% Series 2,360 2,360 2,360
6-1/4% Series 1,875 1,875 1,875
6.30% Series 2,205 2,205 1,978
6-7/8% Series 2,063 2,063 2,063
7.08% Series 531 2,124 2,124
7.76% Series - - 317
Total Cash Dividends Declared 122,475 122,412 118,258
Capital Stock Expense 714 231 224
Total Deductions 123,189 122,643 118,482
Retained Earnings December 31 $269,071 $235,107 $216,658
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Organization
Indiana Michigan Power Company (the Company or I&M) is a wholly-owned
subsidiary of American Electric Power Company, Inc. (AEP Co., Inc.), a public
utility holding company. The Company is engaged in the generation, purchase,
transmission and distribution of electric power to 542,000 retail customers
in its service territory of northern and eastern Indiana and a portion of
southwestern Michigan. Wholesale electric power is supplied to neighboring
utility systems, power marketers and the American Electric Power (AEP) System
Power Pool (Power Pool). As a member of the Power Pool and a signatory
company to the AEP Transmission Equalization Agreement, its facilities are
operated in conjunction with the facilities of certain other AEP affiliated
utilities as an integrated utility system.
The Company has two wholly-owned subsidiaries, which are consolidated in
these financial statements, Blackhawk Coal Company and Price River Coal
Company, that were formerly engaged in coal-mining operations. Blackhawk
Coal Company currently leases and subleases portions of its Utah coal rights,
land and related mining equipment to unaffiliated companies. Price River
Coal Company, which owns no land or mineral rights, is inactive.
Regulation
As a subsidiary of AEP Co., Inc., I&M is subject to regulation by the
Securities and Exchange Commission (SEC) under the Public Utility Holding
Company Act of 1935 (1935 Act). Retail rates are regulated by the Indiana
Utility Regulatory Commission (IURC) and the Michigan Public Service Commis-
sion (MPSC). The Federal Energy Regulatory Commission (FERC) regulates
wholesale rates.
Principles of Consolidation
The consolidated financial statements include I&M and its wholly-owned
subsidiaries. Significant intercompany items are eliminated in consolidation.
Basis of Accounting
As a cost-based rate-regulated entity, I&M's financial statements reflect
the actions of regulators that result in the recognition of revenues and
expenses in different time periods than enterprises that are not cost-based
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 sal-vage, are deducted from
accumulated depreciation.
The costs of labor, materials and overheads incurred to operate and
maintain utility plant are included in operating expenses.
Allowance for Funds Used During Construction (AFUDC)
AFUDC is a noncash nonoperating income item that is recovered with
regulator approval over the service life of utility plant through
depreciation and represents the estimated cost of borrowed and equity funds
used to finance construction projects. The amounts of AFUDC for 1996, 1995
and 1994 were not significant.
Depreciation and Amortization
Depreciation of electric utility plant is provided on a straight-line
basis over the estimated useful lives of utility plant and is calculated
largely through the use of composite rates by functional class as follows:
Composite
Functional Class Depreciation
of Property Annual Rates
Production:
Steam-Nuclear 3.4%
Steam-Fossil-Fired 4.4%
Hydroelectric-Conventional 3.2%
Transmission 1.9%
Distribution 4.2%
General 3.8%
Amounts to be used for demolition of non-nuclear plant are presently
recovered through depreciation charges included in rates. The accounting and
rate-making treatment afforded nuclear decommissioning costs and nuclear fuel
disposal costs are discussed in Note 3.
Cash and Cash Equivalents
Cash and cash equivalents include temporary cash investments with original
maturities of three months or less.
Operating Revenues
Revenues include the accrual of electricity consumed but unbilled at
month-end as well as billed revenues.
<PAGE>
Fuel Costs
Fuel costs are matched with revenues in accordance with rate commission
orders. Revenues are accrued related to unrecovered fuel in both retail
jurisdictions and for replacement power costs in the Michigan jurisdiction
until approved for billing. If the Company's earnings exceed the allowed
return in the Indiana jurisdiction, based on a twenty quarter rolling
average, the fuel clause mechanism provides for the refunding of the excess
earnings to ratepayers. 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 the Donald C. Cook Nuclear Plant (Cook Plant) are deferred
commensurate with their rate-making treatment 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, regulatory assets and
liabilities are recorded in accordance with SFAS 71.
Investment Tax Credits
Based on directives of regulatory commissions, the Company reflected
investment tax credits in rates on a deferral basis. Deferred investment tax
credits, which represent a regulatory liability, are being amortized over the
life of the related plant investment commensurate with recovery in rates.
The Company's policy with regard to investment tax credits for nonutility
property is to practice the flow-through method of accounting.
Debt and Preferred Stock
Gains and losses on reacquired debt are deferred and amortized over the
remaining term of the reacquired debt in accordance with rate-making
treatment. If the debt is refinanced the reacquisition costs are deferred
and amortized over the term of the replacement debt commensurate with their
recovery in rates.
In accordance with rate-making treatment debt discount or premium and debt
issuance expenses are amortized over the term of the related debt, with the
amortization included in interest charges.
Redemption premiums paid to reacquire preferred stock are deferred,
debited to paid-in capital and amortized to reduce retained earnings in
accordance with rate-making treatment. The excess of par value over costs of
preferred stock reacquired is credited to paid-in capital and amortized to
retained earnings.
Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds
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 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.
Other Property and Investments
Other property and investments are stated at cost.
2. 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. Among other things , application
of SFAS 71 requires that the Company's rates be cost-based regulated. The
Company has reviewed all the evidence currently available and concluded that
it continues to meet the requirements to apply SFAS 71. In the event a
portion of the Company's business were to no longer meet those requirements
net regulatory assets would have to be written off for that portion of the
business and assets would have to be tested for possible impairment.
Regulatory assets and liabilities are comprised of the following:
December 31,
1996 1995
(in thousands)
Regulatory Assets:
Amounts Due From Customers for
Future Income Taxes $317,059 $309,640
Department of Energy
Decontamination and
Decommissioning Assessment 45,994 48,862
Rate Phase-in Plan Deferrals 11,871 27,515
Nuclear Refueling
Outage Cost Levelization 15,805 23,467
Unamortized Loss On
Reacquired Debt 19,388 20,827
Other 11,575 28,214
Total Regulatory Assets $421,692 $458,525
Regulatory Liabilities:
Deferred Investment Tax Credits $146,473 $155,202
Other* 16 1,576
Total Regulatory Liabilities $146,489 $156,778
* Included in Deferred Credits on Consolidated Balance Sheets.
The Rockport Plant consists of two 1,300 megawatt (mw) coal-fired units.
I&M and AEP Generating Company (AEGCo), an affiliate, each own 50% of one
unit (Rockport 1) and each 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 the Company's Indiana and FERC jurisdictions for its
share of Rockport 1 provide for the recovery and straight-line amortization
through 1997 of prior-year 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 $15.6 million in 1996, 1995 and 1994.
3. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Substantial construction commitments have been made. Such commitments do
not include any expenditures for new generating capacity. The aggregate
construction program expenditures for 1997-1999 are estimated to be $340
million.
Long-term fuel supply contracts contain clauses that provide for periodic
price adjustments. The retail 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 extends to 2014, and contain various clauses that would release the
Company from its obligation under certain force majeure conditions.
Unit Power Agreements
The Company is committed under unit power agreements to purchase 70% of
AEGCo's 1,300 mw Rockport Plant capacity unless it is sold to unaffiliated
utilities. AEGCo has one long-term contract with an unaffiliated utility
that expires in 1999 for 455 mw of Rockport Plant capacity.
The Company sells under contract up to 250 mw of Rockport Plant capacity
to an unaffiliated utility. The contract expires in 2009.
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.
Nuclear Plant
I&M owns and operates the two-unit 2,110 mw Donald C. 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 is not
possible, results of operations and financial condition would 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
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. The Company could be
assessed up to $35.8 million annually 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 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. The Company 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. The Company 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. Decom-
missioning 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 the Company has recognized a decommissioning liability of $314 million
which is included in other noncurrent liabilities.
4. RELATED PARTY TRANSACTIONS:
Benefits and costs of the AEP System's generating plants are shared by
members of the Power Pool. Under the terms of the AEP System Interconnection
Agreement, capacity charges and credits are designed to allocate the cost of
the AEP System's capacity among the Power Pool members based on their
relative peak demands and generating reserves. Power Pool members are also
compensated for the out-of-pocket costs of energy delivered to the Power Pool
and charged for energy received from the Power Pool. The Company is a net
supplier to the pool and, therefore, receives capacity credits from the Power
Pool.
Operating revenues include revenues for capacity and energy supplied to
the Power Pool as follows:
Year Ended December 31,
1996 1995 1994
(in thousands)
Capacity Revenues $ 57,594 $ 59,918 $ 88,183
Energy Revenues 98,162 83,799 52,274
Total $155,756 $143,717 $140,457
Purchased power expense includes charges of $34.5 million in 1996, $25.4
million in 1995 and $33.1 million in 1994 for energy received from the Power
Pool.
Power Pool members share in wholesale sales to unaffiliated entities
made by the Power Pool. The Company's share of the wholesale power pool
sales included in operating revenues were $73.4 million in 1996, $52.6
million in 1995 and $54.1 million in 1994.
In addition, the Power Pool purchases power from unaffiliated companies
for immediate resale to other unaffiliated utilities. The Company's share of
these purchases was included in purchased power expense and totaled $8.1
million in 1996, $10.7 million in 1995 and $14.2 million in 1994. Revenues
from these transactions including a transmission fee are included in the
above Power Pool wholesale operating revenues.
The cost of power purchased from AEGCo, an affiliated company that is
not a member of the Power Pool, was included in purchased power expense in
the amounts of $85.4 million, $85.2 million and $82.4 million in 1996, 1995
and 1994, respectively.
The cost of power purchased from Ohio Valley Electric Corporation, an
affiliated but non-associated Company that is not a member of the Power
Pool, was included in purchased power expense in the amounts of $10.7
million, $4.0 million and $.9 million in 1996, 1995 and 1994, respectively.
The Company operates the Rockport Plant and bills AEGCo for its share of
operating costs.
AEP System companies participate in a transmission equalization
agreement. This agreement combines certain AEP System companies' investments
in transmission facilities and shares the costs of owner-ship in proportion
to the AEP System companies' respective peak demands. Pursuant to the terms
of the agreement, other operation expense includes equalization credits of
$46.3 million, $46.7 million and $50.3 million in 1996, 1995 and 1994,
respectively.
<PAGE>
Revenues from providing barging services were recorded in nonoperating
income as follows:
Year Ended December 31,
1996 1995 1994
(in thousands)
Affiliated Companies $22,740 $23,160 $24,001
Unaffiliated Companies 6,776 6,992 5,021
Total $29,516 $30,152 $29,022
American Electric Power Service Corporation (AEPSC) provides certain
managerial and professional services to AEP System companies. The costs of
the services are billed by AEPSC on a direct-charge basis to the extent
practicable and on reasonable bases of proration for indirect costs. The
charges for services are made at cost and include no compensation for the use
of equity capital, which is furnished to AEPSC by AEP Co., Inc. Billings
from AEPSC are capitalized or expensed depending on the nature of the
services rendered. AEPSC and its billings are subject to the regulation of
the SEC under the 1935 Act.
5. BENEFIT PLANS:
The Company and its subsidiaries participate in the AEP System pension
plan, a trusteed, noncontributory defined benefit plan covering all employees
meeting eligibility requirements. Benefits are based on service years and
compensation levels. Pension costs are allocated by first charging each
System company with its service cost and then allocating the remaining
pension cost in proportion to its share of the projected benefit obligation.
The funding policy is to make annual trust fund contributions equal to the
net periodic pension cost up to the maximum amount deductible for federal
income taxes, but not less than the minimum required contribution in
accordance with the Employee Retirement Income Security Act of 1974. Net
pension costs for the years ended December 31, 1996, 1995 and 1994 were $4.1
million, $2.7 million and $5 million, respectively.
An employee savings plan is offered which allows participants to
contribute up to 17% of their salaries into various investment alternatives,
including AEP Co., Inc. common stock. An employer matching contribution,
equaling one-half of the employees' contribution to the plan up to a maximum
of 3% of the employees' base salary, is invested in AEP Co., Inc. common
stock. The employer's annual contributions totaled $3.7 million in 1996 and
$3.9 million in 1995 and 1994.
Postretirement benefits other than pensions (OPEB) are provided for
retired employees under an AEP System plan. Substantially all employees are
eligible for postretirement health care and life insurance if they retire
from active service after reaching age 55 and have at least 10 service years.
The funding policy for OPEB cost is to make contributions to an external
Voluntary Employees Beneficiary Association trust fund equal to the
incremental OPEB costs (i.e., the amount that the total postretirement
benefits cost under SFAS 106, "Employers Accounting for Postretirement
Benefits Other Than Pensions," exceeds the pay-as-you-go amount).
Contributions were $8.4 million in 1996, $10.3 million in 1995, and $6.6
million in 1994. OPEB costs are determined by the application of AEP System
actuarial assumptions to each company's employee complement. The Company's
annual accrued costs for 1996, 1995 and 1994 required by SFAS 106 for
employees and retirees were $12.8 million, $13.6 million and $13.2 million,
respectively.
<PAGE>
6. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1996 1995 1994
(in thousands)
Cash was paid for:
Interest (net of
capitalized amounts) $ 64,117 $71,457 $68,946
Income Taxes 125,707 88,675 85,854
Noncash Acquisitions
Under Capital
Leases were 48,305 32,073 92,199
In connection with the 1996 early termination of a western coal land
sublease the Company will receive cash payments from the lessee of $30.8
million over a ten year period which has been recorded at a net present value
of $22.8 million. In connection with the 1995 sale of western coal land and
equipment the Company will receive cash payments from the buyer of $31.5
million over a six year period which has been recorded at a net present value
of $26.9 million. In connection with construction of facilities in 1995 to
provide service to a new customer the Company will receive cash payments of
$21.4 million plus accrued interest over 20 years. The long-term portion of
these receivables is recorded as other property and investments and the
current portion is recorded as miscellaneous accounts receivable.
<PAGE>
7. FEDERAL INCOME TAXES:
<TABLE>
The details of federal income taxes as reported are as follows:
<CAPTION>
Year Ended December 31,
1996 1995 1994
(in thousands)
<S> <C> <C> <C>
Charged (Credited) to Operating Expenses (net):
Current $110,133 $ 75,686 $ 64,565
Deferred (24,730) (13,732) (18,057)
Deferred Investment Tax Credits (7,874) (7,929) (8,155)
Total 77,529 54,025 38,353
Charged (Credited) to Nonoperating Income (net):
Current 182 12,872 1,390
Deferred 43 (9,832) (1,718)
Deferred Investment Tax Credits (855) (1,075) (5,722)
Total (630) 1,965 (6,050)
Total Federal Income Taxes as Reported $ 76,899 $ 55,990 $ 32,303
The following is a reconciliation of the difference between the amount of
federal income taxes computed by multiplying book income before federal
income taxes by the statutory tax rate, and the amount of federal income
taxes reported.
<CAPTION>
Year Ended December 31,
1996 1995 1994
(in thousands)
<S> <C> <C> <C>
Net Income $157,153 $141,092 $157,502
Federal Income Taxes 76,899 55,990 32,303
Pre-tax Book Income $234,052 $197,082 $189,805
Federal Income Tax on Pre-tax Book Income at
Statutory Rate (35%) $81,918 $68,979 $ 66,432
Increase (Decrease) in Federal Income Tax
Resulting From the Following Items:
Depreciation 13,880 8,954 (1,033)
Corporate Owned Life Insurance (2,178) (5,187) (4,521)
Nuclear Fuel Disposal Costs (3,096) (3,060) (4,498)
Investment Tax Credits (net) (8,729) (9,004) (13,875)
Other (4,896) (4,692) (10,202)
Total Federal Income Taxes as Reported $76,899 $55,990 $ 32,303
Effective Federal Income Tax Rate 32.9% 28.4% 17.0%
</TABLE>
<PAGE>
The following tables show the elements of the net deferred tax liability
and the significant temporary differences giving rise to such deferrals:
December 31,
1996 1995
(in thousands)
Deferred Tax Assets $ 241,842 $ 221,604
Deferred Tax Liabilities (836,721) (833,751)
Net Deferred Tax Liabilities $(594,879) $(612,147)
Property Related
Temporary Differences $(480,818) $(490,986)
Amounts Due From Customers
For Future Federal
Income Taxes (79,658) (83,277)
Deferred State Income Taxes (89,471) (71,712)
Deferred Net Gain -
Rockport Plant Unit 2 33,644 34,941
All Other (net) 21,424 (1,113)
Total Net Deferred
Tax Liabilities $(594,879) $(612,147)
The Company and its subsidiaries join in the filing of a consolidated
federal income tax return with their affiliates in the AEP System. The
allocation of the AEP System's current consolidated federal income tax to the
AEP System companies is in accordance with SEC rules under the 1935 Act.
These rules permit the allocation of the benefit of current tax losses to the
AEP System companies giving rise to them in determining their current tax
expense. The tax loss of the parent company, AEP Co., Inc., is allocated to
its subsidiaries with taxable income. With the exception of the loss of the
parent company, the method of allocation approximates a separate return
result for each company in the consolidated group.
The AEP System has settled with the Internal Revenue Service (IRS) all
issues from the audits of the consolidated federal income tax returns for the
years prior to 1991. Returns for the years 1991 through 1993 are presently
being audited by the IRS. During the audit the IRS agents requested a ruling
from their National Office that certain interest deductions relating to
corporate owned life insurance (COLI) claimed by the Company for 1991 through
1993 should not be allowed. The COLI program was established in 1990 as part
of the Company's strategy to fund and reduce the cost of medical benefits for
retired employees. AEP filed a brief with the IRS National Office refuting
the agents' position. Although no adjustments have been proposed, a
disallowance of the COLI interest deductions through December 31, 1996 would
reduce earnings by approximately $51 million (including interest).
Management believes it will ultimately prevail on this issue and will
vigorously contest any adjustments that may be assessed. Accordingly, no
provision for this amount has been recorded. In the opinion of management,
the final settlement of open years will not have a material effect on results
of operations.
<PAGE>
8. FAIR VALUE OF FINANCIAL INSTRUMENTS:
Nuclear Trust Funds Recorded at Market Value
The trust 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 trust investments were
$491 million and $434 million, respectively. Accumulated gross unrealized
holding gains were $22 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 Interest Accrued 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 stocks
subject to mandatory redemption were $137 million and $140 million at
December 31, 1996 and 1995, respectively, and for long-term debt were $1.1
billion at each year end. The carrying amounts for preferred stock subject to
mandatory redemption were $135 million at each year end and for long-term
debt were $1.0 billion at December 31, 1996 and 1995. 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 estimated fair value.
9. LEASES:
Leases of property, plant and equipment are for periods of 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 for both operating and capital leases are generally
charged to operating expenses in accordance with rate-making treatment. The
components of rental costs are as follows:
Year Ended December 31,
1996 1995 1994
(in thousands)
Operating Leases $ 96,096 $ 96,472 $104,519
Amortization of
Capital Leases 55,789 45,843 30,875
Interest on
Capital Leases 10,624 9,987 7,643
Total Rental
Costs $162,509 $152,302 $143,037
Properties under capital leases and related obligations recorded on the
Consolidated Balance Sheets are as follows:
December 31,
1996 1995
(in thousands)
Electric Utility Plant:
Production $ 7,410 $ 9,346
Distribution 14,699 14,753
General:
Nuclear Fuel
(net of amortization) 59,681 69,442
Other 60,949 54,554
Total Electric Utility
Plant 142,739 148,095
Accumulated Amortization 28,598 24,933
Net Electric Utility
Plant 114,141 123,162
Other Property 19,035 22,361
Accumulated Amortization 2,211 3,017
Net Other Property 16,824 19,344
Net Properties under
Capital Leases $130,965 $142,506
Capital Lease Obligations:*
Noncurrent Liability $101,225 $110,730
Liability Due Within
One Year 29,740 31,776
Total Capital
Lease Obligations $130,965 $142,506
* Represents the present value of future minimum lease payments.<PAGE>
The noncurrent portion of capital lease obligations is included in other
noncurrent liabilities in the Consolidated Balance Sheets.
Properties under operating leases and related obligations are not
included in the Consolidated Balance Sheets.
Future minimum lease payments consisted of the following at December 31,
1996:
Non-
Cancelable
Capital Operating
Leases Leases
(in thousands)
1997 $ 14,685 $ 96,294
1998 12,474 91,397
1999 11,027 91,551
2000 9,848 91,403
2001 8,281 90,802
Later Years 36,371 1,749,187
Total Future Minimum
Lease Payments 92,686(a) $2,210,634
Less Estimated
Interest Element 21,402
Estimated Present
Value of Future
Minimum Lease
Payments 71,284
Unamortized Nuclear
Fuel 59,681
Total $130,965
(a) Excludes nuclear fuel rentals which 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.
10. CUMULATIVE PREFERRED STOCK:
At December 31, 1996, authorized shares of cumulative preferred stock were
as follows:
Par Value Shares Authorized
$100 2,250,000
25 11,200,000
The cumulative preferred stock is callable at the price indicated plus ac-
crued dividends. The involuntary liquidation preference is par value.
Unissued shares of the cumulative preferred stock may or may not possess
mandatory redemption characteristics upon issuance. During 1994 the Company
redeemed and cancelled 350,000 shares of the 7.76% series.
In January 1997 a tender offer for all series of preferred stock was
announced. In conjunction with the tender offer a special shareholders'
meeting was scheduled to be held on February 28, 1997 for the purpose of
considering amendments to the Company's articles of incorporation to remove
certain capitalization ratio requirements.
<PAGE>
<TABLE>
A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
<CAPTION>
Call Price Shares Amount
December 31, Par Number of Shares Redeemed Outstanding December 31,
Series 1996 Value Year Ended December 31, December 31, 1996 1996 1995
1996 1995 1994 (in thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
4-1/8% $106.125 $100 233 - - 119,767 $ 11,977 $ 12,000
4.56% 102 100 - - - 60,000 6,000 6,000
4.12% 102.728 100 - - - 40,000 4,000 4,000
7.08% N/A 100 300,000 - - - - 30,000
$ 21,977 $ 52,000
B. Cumulative Preferred Stock Subject to Mandatory Redemption:
<CAPTION>
Shares Amount
Par Outstanding December 31.
Series(a) Value December 31, 1996 1996 1995
(in thousands)
<S> <C> <C> <C> <C>
5.90% (b) $100 400,000 $ 40,000 $ 40,000
6-1/4%(c) 100 300,000 30,000 30,000
6.30% (d) 100 350,000 35,000 35,000
6-7/8%(e) 100 300,000 30,000 30,000
$135,000 $135,000
</TABLE>
(a) Not callable until after 2002. There are no aggregate sinking fund
provisions through 2002.
(b) Commencing in 2004 and continuing through the year 2008, a sinking fund
will require the redemption of 20,000 shares each year and the redemption of
the remaining shares outstanding on January 1, 2009, in each case at $100 per
share.
(c) Commencing in 2004 and continuing through the year 2008, a sinking fund
will require the redemption of 15,000 shares each year and the redemption of
the remaining shares outstanding on April 1, 2009, in each case at $100 per
share.
(d) Commencing in 2004 and continuing through the year 2008, a sinking fund
will require the redemption of 17,500 shares each year and the redemption of
the remaining shares outstanding on July 1, 2009, in each case at $100 per
share.
(e) Commencing in 2003 and continuing through the year 2007, a sinking fund
will require the redemption of 15,000 shares each year and the redemption of
the remaining shares outstanding on April 1, 2008, in each case at $100 per
share.
<PAGE>
11. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1996 1995
(in thousands)
First Mortgage Bonds $ 522,507 $ 562,017
Installment Purchase
Contracts 309,120 308,971
Other Long-term Debt (a) 171,706 163,060
Junior Subordinated
Deferrable Interest
Debentures (b) 38,771 -
Sinking Fund Debentures (c) - 6,053
1,042,104 1,040,101
Less Portion Due Within
One Year - 6,053
Total $1,042,104 $1,034,048
(a) Nuclear Fuel Disposal Costs including interest accrued. See Note 3.
(b) 8% - Due March 31, 2026 - $40,000,000 Outstanding less $1,228,500
discount.
(c) Called for redemption on March 1, 1996.
First mortgage bonds outstanding were as follows:
December 31,
1996 1995
(in thousands)
% Rate Due
7 1998 - May 1 $ 35,000 $ 35,000
7.30 1999 - December 15 35,000 35,000
7.63 2001 - June 1 40,000 40,000
7.60 2002 - November 1 50,000 50,000
7.70 2002 - December 15 40,000 40,000
6.80 2003 - July 1 20,000 20,000
6.55 2003 - October 1 20,000 20,000
6.10 2003 - November 1 30,000 30,000
6.55 2004 - March 1 25,000 25,000
9.50 2021 - May 1 - 10,000
9.50 2021 - May 1 - 10,000
9.50 2021 - May 1 - 20,000
8.75 2022 - May 1 50,000 50,000
8.50 2022 - December 15 75,000 75,000
7.80 2023 - July 1 20,000 20,000
7.35 2023 - October 1 20,000 20,000
7.20 2024 - February 1 40,000 40,000
7.50 2024 - March 1 25,000 25,000
Unamortized Discount (net) (2,493) (2,983)
Total $522,507 $562,017
Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
<PAGE>
Installment purchase contracts have been entered into in connection with
the issuance of pollution control revenue bonds by governmental authorities
as follows:
December 31,
1996 1995
(in thousands)
% Rate Due
City of Lawrenceburg, Indiana:
7 2015 - April 1 $ 25,000 $ 25,000
5.9 2019 - November 1 52,000 52,000
City of Rockport, Indiana:
(a) 2014 - August 1 50,000 50,000
7.6 2016 - March 1 40,000 40,000
6.55 2025 - June 1 50,000 50,000
(b) 2025 - June 1 50,000 50,000
City of Sullivan, Indiana:
5.95 2009 - May 1 45,000 45,000
Unamortized Discount (2,880) (3,029)
Total $309,120 $308,971
(a) The variable interest rate is determined weekly. The average weighted
interest rate was 3.5% for 1996 and 4.6% for 1995.
(b) The adjustable interest rate can be a daily, weekly, commercial paper or
term rate as designated by the Company. A weekly rate was selected which
ranged from 2.4% to 5.0% in 1996 and from 2.9% to 5% in 1995 and averaged
3.4% and 4.0% during 1996 and 1995, respectively.
Under the terms of certain installment purchase contracts, the Company is
required to pay amounts sufficient to enable the cities to pay interest on
and the principal (at stated maturities and upon mandatory redemption) of
related pollution control revenue bonds issued to finance the construction of
pollution control facilities at certain generating plants. On the two
variable rate series the principal is payable at the stated maturities or on
the demand of the bondholders at periodic interest adjustment dates which
occur weekly. The variable rate bonds due in 2014 are supported by a bank
letter of credit which expires in 2002. I&M has agreements that provide for
brokers to remarket the adjustable rate bonds due in 2025 tendered at
interest adjustment dates. In the event certain bonds cannot be remarketed,
I&M has a standby bond purchase agreement with a bank that provides for the
bank to purchase any bonds not remarketed. The purchase agreement expires in
2000. Accordingly, the variable and adjustable rate installment purchase
contracts have been classified for repayment purposes based on the expiration
dates of the standby purchase agreement and the letter of credit.
<PAGE>
At December 31, 1996, future annual long-term debt payments, excluding
premium or discount, are as follows:
Principal Amount
(in thousands)
1998 $ 35,000
1999 35,000
2000 50,000
2001 40,000
Later Years 888,706
Total $1,048,706
Short-term debt borrowings are limited by provisions of the 1935 Act to
$175 million. Lines of credit are shared with AEP System companies and at
December 31, 1996 and 1995 were available in the amounts of $409 million and
$372 million, respectively. Commitment fees of approximately 1/8 of 1% of
the unused short-term lines of credit are paid each year to the banks to
maintain the lines of credit.
Outstanding short-term debt consisted of:
Year-end
Balance Weighted
Outstanding Average
(in thousands) Interest Rate
December 31, 1996:
Note Payable $ 3,900 5.5%
Commercial Paper 39,600 7.2
Total $43,500 7.0
December 31, 1995:
Note Payable $52,200 6.1%
Commercial Paper 37,775 6.1
Total $89,975 6.1
<PAGE>
12. COMMON SHAREHOLDER'S EQUITY:
Mortgage indentures, charter provisions and orders of regulatory
authorities place various restrictions on the use of retained earnings for
the payment of cash dividends on common stock. At December 31, 1996, $5.9
million of retained earnings were restricted. Regulatory approval is
required to pay dividends out of paid-in capital.
In 1996 and 1995 net changes in paid-in capital of $170,000 and
$(2,548,000), respectively, represented gains and expenses associated with
cumulative preferred stock transactions.
13. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
(in thousands)
1996
March 31 $329,883 $53,018 $35,767
June 30 323,494 50,430 33,507
September 30 339,847 61,123 44,546
December 31 335,269 55,846 43,333
1995
March 31 327,177 56,311 38,388
June 30 307,820 51,386 33,780
September 30 334,846 54,400 37,404
December 31 313,314 43,626 31,520
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration
Statement No. 33-50521 and Registration Statement No. 333-22171 of
Indiana Michigan Power Company on Form S-3 of our reports dated
February 25, 1997, appearing in and incorporated by reference in
this Annual Report on Form 10-K of Indiana Michigan Power Company
for the year ended December 31, 1996.
Deloitte & Touche LLP
Columbus, Ohio
March 25, 1997
Exhibit 24
POWER OF ATTORNEY
INDIANA MICHIGAN POWER COMPANY
Annual Report on Form lO-K for the Fiscal Year Ended
December 31, 1996
The undersigned directors of INDIANA MICHIGAN POWER COMPANY,
an Indiana 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/ C. R. Boyle, III /s/ James J. Markowsky
- ------------------------------ -------------------------------
C. R. Boyle, III James J. Markowsky
/s/ G. A. Clark /s/ D. B. Synowiec
- ------------------------------ -------------------------------
G. A. Clark D. B. Synowiec
/s/ P. J. DeMaria /s/ D. M. Trenary
- ------------------------------ -------------------------------
P. J. DeMaria D. M. Trenary
/s/ W. N. D'Onofrio /s/ J. H. Vipperman
- ------------------------------ -------------------------------
W. N. D'Onofrio J. H. Vipperman
/s/ E. Linn Draper, Jr. /s/ W. E. Walters
- ------------------------------ -------------------------------
E. Linn Draper, Jr. W. E. Walters
/s/ Wm. J. Lhota /s/ E. H. Wittkamper
- ------------------------------ -------------------------------
Wm. J. Lhota E. H. Wittkamper
/s/ G. P. Maloney
- ------------------------------
G. P. Maloney
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000050172
<NAME> INDIANA MICHIGAN POWER COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,515,776
<OTHER-PROPERTY-AND-INVEST> 645,043
<TOTAL-CURRENT-ASSETS> 283,516
<TOTAL-DEFERRED-CHARGES> 31,457
<OTHER-ASSETS> 421,692
<TOTAL-ASSETS> 3,897,484
<COMMON> 56,584
<CAPITAL-SURPLUS-PAID-IN> 731,272
<RETAINED-EARNINGS> 269,071
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,056,927
135,000
21,977
<LONG-TERM-DEBT-NET> 1,042,104
<SHORT-TERM-NOTES> 3,900
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 39,600
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 101,225
<LEASES-CURRENT> 29,740
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,467,011
<TOT-CAPITALIZATION-AND-LIAB> 3,897,484
<GROSS-OPERATING-REVENUE> 1,328,493
<INCOME-TAX-EXPENSE> 86,799
<OTHER-OPERATING-EXPENSES> 1,021,277
<TOTAL-OPERATING-EXPENSES> 1,108,076
<OPERATING-INCOME-LOSS> 220,417
<OTHER-INCOME-NET> 2,729
<INCOME-BEFORE-INTEREST-EXPEN> 223,146
<TOTAL-INTEREST-EXPENSE> 65,993
<NET-INCOME> 157,153
10,681
<EARNINGS-AVAILABLE-FOR-COMM> 146,472
<COMMON-STOCK-DIVIDENDS> 112,508
<TOTAL-INTEREST-ON-BONDS> 41,209
<CASH-FLOW-OPERATIONS> 294,341
<EPS-PRIMARY> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1> All common stock owned by parent company; no EPS required.
</FN>
</TABLE>
