<PAGE> 1
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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, 1998
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _____________ to ______________
<TABLE>
<CAPTION>
COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER
FILE NUMBER ADDRESS AND TELEPHONE NUMBER IDENTIFICATION NO.
- ----------- ---------------------------- ------------------
<S> <C> <C>
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)
1 Riverside Plaza
Columbus, Ohio 43215
Telephone (614) 223-1000
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
</TABLE>
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 [X}. No.
<PAGE> 2
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED
---------- ------------------- -------------------
<S> <C> <C>
AEP Generating Company None
American Electric Power Common Stock,
Company, Inc. $6.50 par value................................... New York Stock Exchange
Appalachian Power Cumulative Preferred Stock,
Company Voting, no par value:
4-1/2%........................................... Philadelphia Stock Exchange
8-1/4% Junior Subordinated Deferrable
Interest Debentures, Series A,
Due 2026........................................ New York Stock Exchange
8% Junior Subordinated Deferrable
Interest Debentures, Series B,
Due 2027........................................ New York Stock Exchange
7.20% Senior Notes, Series A,
Due 2038......................................... New York Stock Exchange
7.30% Senior Notes, Series B,
Due 2038...........................................New.York.Stock.Exchange
Columbus Southern 8-3/8% Junior Subordinated Deferrable
Power Company Interest Debentures, Series A,
Due 2025......................................... New York Stock Exchange
7.92% Junior Subordinated Deferrable
Interest Debentures, Series B,
Due 2027......................................... New York Stock Exchange
Indiana Michigan 8% Junior Subordinated Deferrable
Power Company Interest Debentures, Series A,
Due 2026......................................... New York Stock Exchange
7.60% Junior Subordinated Deferrable
Interest Debentures, Series B,
Due 2038...........................................New.York.Stock.Exchange
Kentucky Power 8.72% Junior Subordinated Deferrable
Company 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
7 3/8% Senior Notes, Series A,
Due 2038......................................... New York Stock Exchange
</TABLE>
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
(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 (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. [X]
<PAGE> 3
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
<TABLE>
<CAPTION>
REGISTRANT TITLE OF EACH CLASS
---------- -------------------
<S> <C>
AEP Generating Company None
American Electric Power Company, Inc None
Appalachian Power Company None
Columbus Southern Power Company None
Indiana Michigan Power Company 4-1/8% Cumulative Preferred Stock, Non-Voting, $100 par value
Kentucky Power Company None
Ohio Power Company 4-1/2% Cumulative Preferred Stock, Voting, $100 par value
</TABLE>
<TABLE>
<CAPTION>
AGGREGATE MARKET VALUE
OF VOTING AND NON-VOTING NUMBER OF SHARES
COMMON EQUITY HELD OF COMMON STOCK
BY NON-AFFILIATES OF OUTSTANDING OF
THE REGISTRANTS AT THE REGISTRANTS AT
FEBRUARY 1, 1999 FEBRUARY 1, 1999
------------------------ ------------------
<S> <C> <C>
AEP Generating Company None 1,000
($1,000 par value)
American Electric Power Company, Inc $8,177,004,087 191,835,873
($6.50 par value)
Appalachian Power Company None 13,499,500
(no par value)
Columbus Southern Power Company None 16,410,426
(no par value)
Indiana Michigan Power Company None 1,400,000
(no par value)
Kentucky Power Company None 1,009,000
($50 par value)
Ohio Power Company None 27,952,473
(no par value)
</TABLE>
NOTE ON MARKET VALUE OF COMMON EQUITY HELD BY NON-AFFILIATES
All of the common stock of AEP Generating Company, Appalachian Power
Company, Columbus Southern Power Company, Indiana Michigan Power Company,
Kentucky Power Company and Ohio Power Company is owned by American Electric
Power Company, Inc. (see Item 12 herein).
<PAGE> 4
<TABLE>
<CAPTION>
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K
INTO WHICH DOCUMENT
DESCRIPTION IS INCORPORATED
- ----------- ---------------
<S> <C>
Portions of Annual Reports of the following companies for the fiscal year Part II
ended December 31, 1998:
AEP Generating Company
American Electric Power Company, Inc.
Appalachian Power Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Ohio Power Company
Portions of Proxy Statement of American Electric Power Company, Inc. for Part III
1999 Annual Meeting of Shareholders, to be filed within 120 days after
December 31, 1998
Portions of Information Statements of the following companies for 1999 Part III
Annual Meeting of Shareholders, to be filed within 120 days after December 31,
1998
Appalachian Power Company
Ohio Power Company
</TABLE>
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THIS COMBINED FORM 10-K IS SEPARATELY FILED BY AEP GENERATING COMPANY,
AMERICAN ELECTRIC POWER COMPANY, INC., APPALACHIAN POWER COMPANY, COLUMBUS
SOUTHERN POWER COMPANY, INDIANA MICHIGAN POWER COMPANY, KENTUCKY POWER COMPANY
AND OHIO POWER COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL
REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EXCEPT FOR AMERICAN
ELECTRIC POWER COMPANY, INC., EACH REGISTRANT MAKES NO REPRESENTATION AS TO
INFORMATION RELATING TO THE OTHER REGISTRANTS.
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<TABLE>
<CAPTION>
TABLE OF CONTENTS
PAGE
NUMBER
------
<S> <C>
Glossary of Terms........................................................................ i
Forward-Looking Information.............................................................. 1
PART I
Item 1. Business............................................................. 2
Item 2. Properties........................................................... 36
Item 3. Legal Proceedings.................................................... 42
Item 4. Submission of Matters to a Vote of Security Holders.................. 43
Executive Officers of the Registrants.............................................. 43
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters............................................. 45
Item 6. Selected Financial Data.............................................. 46
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition............................... 46
Item 7A. Quantitative and Qualitative Disclosures About Market Risk .......... 47
Item 8. Financial Statements and Supplementary Data.......................... 47
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure........................... 47
PART III
Item 10. Directors and Executive Officers of the Registrants.................. 48
Item 11. Executive Compensation............................................... 50
Item 12. Security Ownership of Certain Beneficial Owners
and Management.................................................. 54
Item 13. Certain Relationships and Related Transactions....................... 55
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K..................................................... 55
Signatures............................................................................... 57
Index to Financial Statement Schedules................................................... S-1
Independent Auditors' Report............................................................. S-2
Exhibit Index............................................................................ E-1
</TABLE>
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GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this
report, they have the meanings indicated below.
<TABLE>
<CAPTION>
TERM MEANING
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<S> <C>
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.
CSW................................. Central and South West Corporation.
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.
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.
PCBs................................. 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.
</TABLE>
i
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[THIS PAGE INTENTIONALLY LEFT BLANK]
<PAGE> 8
FORWARD-LOOKING INFORMATION
- --------------------------------------------------------------------------------
This report made by AEP and certain of its subsidiaries includes
forward-looking statements within the meaning of Section 21E of the Securities
Exchange Act of 1934. These forward-looking statements reflect assumptions and
involve a number of risks and uncertainties. Among the factors that could cause
actual results to differ materially from forward-looking statements are:
o Electric load and customer growth.
o Abnormal weather conditions.
o Available sources and costs of fuels.
o Availability of generating capacity.
o The impact of the proposed merger with CSW including any regulatory
conditions imposed on the merger or the inability to consummate the merger
with CSW.
o The speed and degree to which competition is introduced to our power
generation business.
o The structure and timing of a competitive market and its impact on energy
prices or fixed rates.
o The ability to recover stranded costs in connection with possible
deregulation of generation.
o New legislation and government regulations.
o The ability of AEP to successfully control its costs.
o The success of new business ventures.
o International developments affecting AEP's foreign investments.
o The economic climate and growth in AEP's service territory.
o Unforeseen events affecting AEP's nuclear plant which is on an extended
safety related shutdown.
o Problems or failures related to Year 2000 readiness of computer software
and hardware.
o Inflationary trends.
o Electricity and gas market prices.
o Interest rates
o Other risks and unforeseen events.
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PART I ------------------------------------------------------------------------
Item 1. BUSINESS
- --------------------------------------------------------------------------------
General
AEP was incorporated under the laws of the State of New York in 1906
and reorganized in 1925. It is a public utility holding company which owns,
directly or indirectly, all of the outstanding common stock of its domestic
electric utility subsidiaries and varying percentages of other subsidiaries.
Substantially all of the operating revenues of AEP and its subsidiaries are
derived from the furnishing of electric service. In addition, in recent years
AEP has been pursuing various unregulated business opportunities 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, 1998, the subsidiaries of AEP had a total of 17,943
employees. AEP, as such, has no employees. The operating subsidiaries of AEP
are:
APCo (organized in Virginia in 1926) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
888,000 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, 1998, APCo and its wholly owned subsidiaries had
3,577 employees. Among the principal industries served by APCo are coal
mining, primary metals, chemicals and textile mill products. In addition to
its AEP System interconnections, APCo also is interconnected with the
following unaffiliated utility companies: Carolina Power & Light Company,
Duke Energy Corporation and VEPCo. A comparatively small part of the
properties and business of APCo is located in the northeastern end of the
Tennessee Valley. APCo has several points of interconnection with TVA and
has entered into agreements with TVA under which APCo and TVA interchange
and transfer electric power over portions of their respective systems.
CSPCo (organized in Ohio in 1937, the earliest direct predecessor
company having been organized in 1883) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
640,000 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, 1998, CSPCo had 1,528 employees.
CSPCo's service area is comprised of two areas in Ohio, which include
portions of twenty-five counties. One area includes the City of Columbus and
the other is a predominantly rural area in south central Ohio. Approximately
80% of CSPCo's retail revenues are derived from the Columbus area. Among the
principal industries served are food processing, chemicals, primary metals,
electronic machinery and paper products. In addition to its AEP System
interconnections, CSPCo also is interconnected with the following
unaffiliated utility companies: CG&E, DP&L and Ohio Edison Company.
I&M (organized in Indiana in 1925) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
554,000 customers in northern and eastern Indiana and southwestern Michigan,
and in supplying electric power at wholesale to other electric utility
2
<PAGE> 10
companies, rural electric cooperatives and municipalities. At December 31,
1998, I&M had 3,074 employees. Among the principal industries served are
primary metals, transportation equipment, electrical and electronic
machinery, fabricated metal products, rubber and miscellaneous plastic
products and chemicals and allied products. Since 1975, I&M has leased and
operated the assets of the municipal system of the City of Fort Wayne,
Indiana. In addition to its AEP System interconnections, I&M also is
interconnected with the following unaffiliated utility companies: Central
Illinois Public Service Company, CG&E, Commonwealth Edison Company,
Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light
Company, Louisville Gas and Electric Company, Northern Indiana Public
Service Company, PSI Energy Inc. and Richmond Power & Light Company.
KEPCo (organized in Kentucky in 1919) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 170,000 customers in an area in eastern Kentucky, and in
supplying electric power at wholesale to other utilities and municipalities
in Kentucky. At December 31, 1998, KEPCo had 541 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 44,000 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, 1998, Kingsport
Power Company had 65 employees.
OPCo (organized in Ohio in 1907 and re-incorporated in 1924) is engaged
in the generation, sale, purchase, transmission and distribution of electric
power to approximately 685,000 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, 1998, OPCo and its wholly owned subsidiaries had 4,170
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 42,000
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, 1998, Wheeling Power Company had 80
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
3
<PAGE> 11
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. Legislation was
introduced in Congress in 1997 that would repeal PUHCA and transfer certain
federal authority to the FERC as recommended in the SEC report as part of
broader legislation regarding changes in the electric industry. Such legislation
has been reintroduced in 1999. 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.
4
<PAGE> 12
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, 1998 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......... $ 0 $ 230,160 $ 335,270 $ 265,442 $ 40,190 $ 287,219 $ 1,179,792
With Electric Heating............ 0 328,623 104,905 108,950 64,516 139,052 781,659
-------- ---------- ---------- ---------- -------- ---------- ----------
Total Residential............ 0 558,783 440,175 374,392 104,706 426,271 1,961,451
Commercial.......................... 0 284,206 394,363 290,149 60,115 276,135 1,343,426
Industrial.......................... 0 381,733 148,463 370,329 94,186 670,757 1,727,109
Miscellaneous....................... 0 34,505 17,115 6,849 877 8,230 71,240
-------- ---------- ---------- ---------- -------- ---------- ----------
Total Retail.................. 0 1,259,227 1,000,116 1,041,719 259,884 1,381,393 5,103,226
Wholesale (sales for resale)........... 223,821 350,014 145,376 321,771 87,401 644,058 1,005,481
-------- ---------- ---------- ---------- -------- ---------- ----------
Total from KWH Sales.......... 223,821 1,609,241 1,145,492 1,363,490 347,285 2,025,451 6,108,707
Provision for Revenue Refunds.......... 0 (7,796) 0 0 0 0 (10,044)
-------- ---------- ---------- ---------- -------- ---------- ----------
Total Net of Provision for
Revenue Refunds........... 223,821 1,601,445 1,145,492 1,363,490 347,285 2,025,451 6,098,663
Other Operating Revenues............... 325 70,799 42,253 42,304 15,714 80,096 247,239
-------- ---------- ---------- ---------- -------- ---------- ----------
Total Electric Operating
Revenues............................... $224,146 $1,672,244 $1,187,745 $1,405,794 $362,999 $2,105,547 $6,345,902
======== ========== ========== ========== ======== ========== ==========
</TABLE>
- ----------------------------
(a) Includes revenues of other subsidiaries not shown and elimination of
intercompany transactions.
SALE OF POWER
AEP's electric utility subsidiaries own or lease generating stations
with total generating capacity of 23,759 megawatts. See Item 2 for more
information regarding the generating stations. They operate their generating
plants as a single interconnected and coordinated electric utility system and
share the costs and benefits in the AEP System Power Pool. Most of the electric
power generated at these stations is sold, in combination with transmission and
distribution services, to retail customers of AEP's utility subsidiaries in
their service territories. These sales are made at rates that are established by
the public utility commissions of the state in which they operate. See Rates and
Regulation. Some of the electric power is sold at wholesale to non-affiliated
companies.
AEP System Power Pool
APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Interconnection
Agreement, dated July 6, 1951, as amended (the Interconnection Agreement),
defining how they share the costs and benefits associated with the System's
generating plants. This sharing is based upon each company's
"member-load-ratio," which is calculated monthly on the basis of each company's
maximum peak demand in relation to the sum of the maximum peak demands of all
five companies during the preceding 12 months. In addition, since 1995, APCo,
CSPCo, I&M, KEPCo and OPCo have been parties to the AEP System Interim Allowance
Agreement which provides, among other things, for the transfer of SO2 Allowances
associated with transactions under the Interconnection Agreement.
Power marketing and trading transactions (trading activities) are
conducted by the AEP Power Pool and shared among the parties under the
Interconnection Agreement. Trading activities involve the purchase and sale of
electricity under physical forward contracts at fixed and variable prices and
the trading of electricity contracts including exchange traded futures and
options and over-the-counter options and swaps. The majority of these
transactions represent physical forward contracts in the AEP System's
traditional marketing area and are typically settled by entering into offsetting
contracts. The regulated physical forward contracts are recorded on a net basis
in the month when the contract settles.
In addition, the AEP Power Pool enters into transactions for the purchase
and sale of electricity options, futures and swaps, and for the forward purchase
and sale of electricity outside of the AEP System's traditional marketing area.
These non-regulated trading activities are accounted for on a mark-to-market
basis.
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<PAGE> 13
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, 1996, 1997 and 1998:
1996 1997 1998(a)
---- ---- -------
(IN THOUSANDS)
APCo.............. $(258,000) $(237,000) $(142,500)
CSPCo............. (145,000) (138,000) (146,800)
I&M............... 121,000 67,000 ( 86,100)
KEPCo............. 2,000 20,000 34,000
OPCo.............. 280,000 288,000 341,400
- -------------------------
(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 Power Pool 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, 1996, 1997 and 1998:
1996(a) 1997(a) 1998(a)
------- ------- -------
(IN THOUSANDS)
AEGCo(b)............ $ 26,300 $ 26,200 $ 23,500
APCo(c)............. 36,800 37,500 40,700
CSPCo(c)............ 18,100 18,300 23,000
I&M(c)(d)........... 43,000 42,400 47,800
KEPCo(c)............ 7,600 7,700 8,700
OPCo(c)............. 30,200 30,200 36,900
-------- ------- --------
Total System........ $162,000 $162,300 $180,600
======== ======== ========
- -----------------------
(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 1996, 1997 and 1998 were made on a short-term basis,
except that $33,300,000, $25,900,000 and $38,300,000 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 1996, 1997 and 1998
amounts for I&M include $20,900,000, $21,100,000 and $21,800,000 from a
long-term agreement to sell 250 megawatts of power scheduled to terminate
in 2009.
The AEP System has long-term system agreements to sell the following to
unaffiliated utilities: (1) 205 megawatts of electric power through August 2010;
and (2) 50 megawatts of electric power through August 2001.
In addition to long-term and short-term sales, APCo, CSPCo, I&M, KEPCo and
OPCo serve unaffiliated wholesale customers that are full/partial requirement
customers. The aggregate maximum demand for these customers in 1998 was 611,
109, 451, 18 and 140 megawatts for APCo, CSPCo, I&M, KEPCo and OPCo,
respectively. Although the terms of the contracts with these customers vary,
they generally can be terminated by the customer upon one to four years' notice.
Since 1996, customers have given notices of termination, effective in 1999 and
2000, for 405, 63 and 131 megawatts for APCo, I&M and OPCo, respectively.
Several wholesale customers, some of whom had previously given notice of
termination, have entered into long-term contracts, ranging from five to seven
years, with the AEP System. The expected demand under these contracts aggregates
approximately 245 megawatts.
In June 1993, certain municipal customers of APCo 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 were full-requirements contracts which precluded
the customers from purchasing power from third parties until 1998. 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
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<PAGE> 14
megawatts. Certain of these customers further reduced their purchases by an
additional 21 megawatts effective February 1996. On December 17, 1996, the U.S.
Court of Appeals reversed the FERC's order directing APCo to provide
transmission service and remanded the case to the FERC, where it remains
pending. The customers terminated their contracts with APCo in 1998.
TRANSMISSION SERVICES
AEP's electric utility subsidiaries own and operate transmission and
distribution lines and other facilities to deliver electric power. See Item 2
for more information regarding the transmission and distribution lines. AEP's
electric utility subsidiaries operate their transmission lines as a single
interconnected and coordinated system and share the cost and benefits in the AEP
System Transmission Pool. Most of the transmission and distribution services is
sold, in combination with electric power, to retail customers of AEP's utility
subsidiaries in their service territories. These sales are made at rates that
are established by the public utility commissions of the state in which they
operate. See Rates and Regulation. As discussed below, 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, 1996,
1997 and 1998:
1996 1997 1998
---- ---- ----
(IN THOUSANDS)
APCo.......... $( 6,500) $ ( 8,400) $ 2,400
CSPCo......... (30,600) (29,900) (35,600)
I&M........... 46,300 46,100 44,100
KEPCo......... 3,300 2,700 6,000
OPCo.......... (12,500) (10,500) (16,900)
Transmission Services for Non-Affiliates
APCo, CSPCo, I&M, KEPCo, OPCo and other System companies also provide
transmission services for non-affiliated companies. The following table shows
the revenues net of federal income tax expenses of the various companies from
such services during the years ended December 31, 1996, 1997 and 1998:
1996 1997 1998
---- ---- ----
(IN THOUSANDS)
APCo.................... $ 13,800 $ 18,000 $30,600
CSPCo................... 8,000 10,200 18,100
I&M..................... 7,700 10,500 19,200
KEPCo................... 2,800 3,900 6,400
OPCo.................... 17,800 27,200 42,100
-------- -------- --------
Total System............ $ 50,100 $ 69,800 $116,400
======== ======== ========
The AEP System has contracts with non-affiliated companies for
transmission of approximately 5,000 megawatts of electric power on an annual or
longer basis.
On April 24, 1996, the FERC issued orders 888 and 889. These orders
require each public utility that owns or controls interstate transmission
facilities to file an open access network and point-to-point transmission tariff
that offers services comparable to the utility's own uses of its 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.
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<PAGE> 15
During 1996 and 1997 AEP engaged in discussions with several utilities
regarding the creation of an independent system operator to operate the
transmission system in the Midwestern region of the United States. In January
1998, nine utilities or utility systems filed with the FERC a proposal to form
the Midwest Independent Transmission System Operator, Inc. ("Midwest ISO"). AEP
was not a participant in that filing and elected not to join the Midwest ISO as
a transmission owner member. AEP has since joined the Midwest ISO as a non-owner
member.
AEP is currently engaged in discussions with Consumers Energy Company,
FirstEnergy Corp. and VEPCo regarding the development of a Regional Transmission
Organization ("RTO") which may take the form of an independent system operator
("ISO") or an independent transmission company ("Transco"), depending upon the
occurrence of certain conditions. The parties envision that the Transco, if
formed, would operate transmission assets that it would own, and also would
operate other owners' transmission assets on a contractual basis. The
discussions are also open to interested stakeholders. The discussions are
expected to culminate in a FERC filing during the first part of 1999. 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 1,402,000 kilowatts. On April 1, 1999,
it is scheduled to increase to approximately 1,900,000 kilowatts. The proceeds
from the sale of power by OVEC are designed to be sufficient for OVEC to meet
its operating expenses and fixed costs and to provide a return on its equity
capital. APCo, CSPCo, I&M and OPCo, as sponsoring companies, are entitled to
receive from OVEC, and are obligated to pay for, the power not required by DOE
in proportion to their power participation ratios, which averaged 42.1% in 1998.
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 26 of the rural electric cooperatives which
operate in the State of Ohio at 318 delivery points. Buckeye is entitled under
such arrangements to receive, and is obligated to pay for, the excess of its
maximum one-hour coincident peak demand plus a 15% reserve margin over the
1,226,500 kilowatts of capacity of the generating units which Buckeye currently
owns in the Cardinal Station. Such demand, which occurred on January 16, 1997,
was recorded at 1,178,460 kilowatts.
CERTAIN INDUSTRIAL CUSTOMERS
Century Aluminum of West Virginia, Inc. (formerly Ravenswood Aluminum
Corporation), and Ormet Corporation operate major aluminum reduction plants in
the Ohio River Valley at Ravenswood, West Virginia, and in the vicinity of
Hannibal, Ohio, respectively. The power requirements of such plants presently
are approximately 357,000 kilowatts for Century and 537,000 kilowatts for Ormet.
OPCo is providing electric service to Century pursuant to a contract approved by
the PUCO for the period July 1, 1996 through July 31, 2003.
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.
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<PAGE> 16
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, 2004.
A unit power agreement among AEGCo, I&M, VEPCo, and APCo provides for,
among other things, the sale of 70% of the power and energy available to AEGCo
from Unit 1 of the Rockport Plant to VEPCo by AEGCo from January 1, 1987 through
December 31, 1999. VEPCo has agreed to pay to AEGCo in consideration for the
right to receive such power those amounts which I&M would have paid AEGCo under
the terms of the I&M Power Agreement for such entitlement. Approximately 32% of
AEGCo's operating revenue in 1998 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.
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<PAGE> 17
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 and transmission lines 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; availability of capacity; 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. 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 any stranded investment losses.
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
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<PAGE> 18
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.
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 benefited by
attracting new industrial customers to their service territories.
The legislatures and/or the regulatory commissions in many states are
considering or have adopted "retail customer choice" which, in general terms,
means the transmission by an electric utility of electric power generated by an
entity of the customer's choice over its transmission and distribution system to
a retail customer in such utility's
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<PAGE> 19
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 should 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 1999, Senate Bill 648 was introduced in the Indiana
Senate on behalf of a group of industrial customers. The bill would allow retail
electric customers to choose their electricity supply companies after December
31, 2000. The bill would provide that the IURC would determine each utility's
net stranded costs, which would be recovered by a transition charge in effect
until no later than December 31, 2005. The bill was not reported out of
committee and attempts by the sponsors to amend the bill were unsuccessful. AEP
continues to work with other utilities in Indiana to develop a consensus on
customer-choice legislation that can be enacted into law in Indiana. The outcome
of this effort is uncertain.
Kentucky: During the 1998 Regular Session of the Kentucky legislature, the
Electric Utility Restructuring Task Force was established by resolution. The
20-member Task Force includes ten members of the General Assembly and ten
officials from the Governor's office. The Task Force began monthly meetings in
August 1998. At the January 1999 meeting, AEP, the other Kentucky investor-owned
public utilities and the Kentucky electric cooperatives were requested to file
with the Task Force a description of their non-traditional, unregulated
businesses. The final report of the Task Force is due in November 1999, prior to
the next regularly scheduled legislative session in 2000.
A second Task Force was also established to study the effects of utility
restructuring on taxes. This Task Force also has been meeting monthly and will
report its findings in November 1999. Several advisory committees have been
formed to assist this Task Force in gathering and studying information. The
Kentucky investor-owned utilities, including AEP, are represented on each of
those committees. At the January meeting, the Task Force voted to retain a
consulting firm with extensive experience in utility tax issues to facilitate
the proceedings.
The KPSC Chairwoman leads 23 state public utility commissions in a
coalition entitled Low Cost States Initiative. The coalition's stated purpose is
to ensure that the U.S. Congress gives equal consideration to the issues facing
low-cost states. The coalition is focusing on the following five issues:
o A National Voice.
o Low Rates.
o Rural Electricity Rates.
o Stranded Costs and Benefits.
o Economic Development.
Michigan: In June 1995, the MPSC issued an order approving an experimental
five-year retail wheeling program and ordered Consumers Energy Company
(Consumers) and Detroit Edison Company (Detroit Edison), unaffiliated utilities,
to make retail delivery services available to a group of industrial customers,
in the amount of 60 megawatts and 90 megawatts, respectively. The experiment,
which commences when each utility needs new capacity, seeks to determine whether
a retail wheeling program best serves the public interest. During the
experiment, the MPSC will collect information regarding the effects of retail
wheeling. Consumers, Detroit Edison and other parties have appealed the MPSC's
order to the Michigan Supreme Court.
In January 1996, the Governor of Michigan endorsed a proposal of the
Michigan Jobs Commission to promote competition and customer choice in energy
and requested that the MPSC review the existing statutory and regulatory
framework governing Michigan utilities in light of increasing competition in the
utility industry. In December 1996, the MPSC staff issued a report on electric
industry restructuring which recommended
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<PAGE> 20
a phase-in program from 1997 through 2004 of direct access to electricity
suppliers applicable to all customers. On June 5, 1997, the MPSC entered an
order requiring electric utilities (including I&M) to phase in retail open
access for customers, with full customer choice by 2002 (MPSC Order). Under the
MPSC Order, customer choice is phased in from 1997 through 2001, at the rate of
2.5% of each utility's customer load per year, with all customers becoming
eligible to choose their electric supplier effective January 1, 2002. The MPSC
Order essentially adopted the December 1996 MPSC staff report that recommended
full recovery of stranded costs of utilities, including nuclear generating
investment, through the use of a transition charge applicable to customers
exercising choice. While concluding that securitization of stranded costs would
be feasible, the MPSC Order stated that legislative authorization is required
prior to the implementation of any securitization program.
As required by the MPSC Order, in July 1997, I&M filed a proposed open
access distribution tariff phasing in customer choice for all customer classes.
However, the MPSC has closed the relevant docket and taken no action with regard
to AEP's filing. The MPSC has approved, by orders dated January 14, 1998,
February 11, 1998 and March 8, 1999, after contested proceedings and with
modifications, filings made by Consumers and Detroit Edison. Detroit Edison, the
Michigan Attorney General and other parties have appealed the MPSC's orders to
the Michigan Court of Appeals.
Ohio: In March 1998, twin proposals on electric industry restructuring
were introduced in the Ohio House and Senate. Among other provisions, the bills
proposed a fully competitive marketplace in the year 2000, with no phase-in
period. The bills were the subject of hearings in the Senate Ways and Means
Committee and the House Public Utilities Committee in April-May 1998. However,
no additional action was taken with respect to the bills by the end of the
legislative session on December 31, 1998.
In August 1998, four of Ohio's investor-owned electric utilities - AEP,
Cinergy Corp., FirstEnergy and DP&L - announced that they had reached a
consensus on a basic alternative framework to deregulate Ohio's electric
industry. The proposal called for:
o The introduction of customer choice on January 1, 2001.
o A freeze on rates during a five-year transition period.
o Changes in utility taxes to achieve, among other things, equalized
treatment of in-state and out-of-state electricity suppliers.
o An opportunity to recover stranded costs during a five-year transition
period.
In September 1998, the leaders of the House and Senate called for a series
of "working study group" meetings involving the various stakeholder groups. The
study group's members were encouraged to reconcile their differences and develop
a consensus position on industry restructuring. The working study group
continues to hold periodic meetings.
On January 20, 1999, two new "placeholder" bills were introduced in the
Ohio House and Senate declaring the legislature's public policy with respect to
electric industry restructuring. On March 8, 1999, a legislative working group
released a Summary of Proposed Major Provisions of Electric Restructuring
Legislation. It is expected that these provisions will be incorporated into more
extensive legislative proposals expected to supplant the placeholder bills.
Legislative leaders have publicly indicated their desire to pass restructuring
legislation during the current legislative session.
Virginia: On February 25, 1999, the legislature passed an electric utility
industry restructuring bill and tax reform bill. The restructuring bill requires
Virginia utilities to join or establish a regional transmission entity by
January 2001, to which such utilities shall transfer the management and control
of their transmission systems. The bill provides for a transition to retail
customer choice from January 1, 2002 through January 1, 2004. The Virginia SCC
can delay or accelerate the implementation of choice based on considerations of
reliability, safety, communications or market power, but in no event shall any
delay extend the implementation of customer choice beyond January 1, 2005. With
limited exceptions, the generation of electricity will no longer be subject to
regulation.
The bill provides for capped rates, effective January 1, 2001, for a
period of time ending as late as July 1, 2007. The capped rates may be
terminated
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<PAGE> 21
after January 1, 2004, upon petition of the Virginia SCC by the utility and a
finding by the Virginia SCC that an effective competitive market exists. If
capped rates continue beyond January 1, 2004, the bill provides for a one-time
change in the non-generation components of such rates upon approval by the
Virginia SCC. The Virginia SCC also may adjust the capped rates in connection
with the utility's recovery of fuel costs, changes in taxation by Virginia, and
any financial distress of the utility beyond the utility's control.
The restructuring bill provides for recovery of just and reasonable net
stranded costs to the extent that such costs exceed zero in total value for any
incumbent electric utility through either capped rates or the imposition of a
wires charge upon customers who may depart the incumbent in favor of an
alternative supplier prior to the termination of the rate cap.
A ten-member legislative task force, to serve from July 1, 1999 through
July 1, 2005, will monitor the work of the Virginia SCC, determine the
discontinuance of capped rates and review related matters. The task force will
report annually to the Governor and legislature.
The tax bill provides for replacement of gross receipts and certain other
taxes by (i) a consumption tax levied upon customers on the basis of
kilowatt-hour usage and (ii) a state corporate net income tax. The intention of
the tax bill is to achieve approximate revenue neutrality for Virginia.
West Virginia: In December 1996, the West Virginia PSC issued an order
initiating a general investigation into the restructuring of the regulated
electric industry. The Task Force established by the West Virginia PSC to study
electric industry restructuring issued its Initial Report in October 1997 and
Supplemental Report on Recommended Legislation in January 1998. On March 14,
1998, the West Virginia Legislature passed restructuring legislation authorizing
the West Virginia PSC to proceed with the development of a plan for electric
industry restructuring, if restructuring is determined by the West Virginia PSC
to be in the public interest. Any plan developed and proposed by the West
Virginia PSC must be approved by the West Virginia Legislature before such plan
can be made effective. Following the passage of the restructuring legislation,
the West Virginia PSC closed the 1996 general investigation and commenced a new
proceeding to carry out its obligations under the legislation.
On April 20, 1998, the West Virginia PSC initiated a general investigation
to determine whether West Virginia should adopt a restructuring plan. Workshops
were held throughout the summer of 1998 and on November 24, 1998, the West
Virginia PSC held a hearing at which the West Virginia PSC was advised that the
participants involved in the general investigation had been unable to reach a
consensus on a restructuring plan. The West Virginia PSC then issued a
procedural order on December 23, 1998, establishing dates beginning in June 1999
for pre-filed testimony, responsive testimony, hearing dates and briefs
regarding the issues of codes of conduct, universal service, class subsidies and
generation plant valuation.
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 has expanded its business to non-regulated energy activities through
several subsidiaries, including AEP Energy Services, Inc. (AEPES), AEP
Resources, Inc. (Resources), AEP Resources Service Company (RESCo) and AEP
Communications, LLC (AEP Communications).
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<PAGE> 22
AEPES
AEPES markets and trades natural gas and provides gas storage and
transportation services.
Resources
Resources' primary business is development of, and investment in, exempt
wholesale generators, foreign utility companies, qualifying cogeneration
facilities and other energy-related domestic and international investment
opportunities and projects. Resources has business development offices in
London, Beijing, Singapore, Sydney, Toronto, Washington and Houston.
Resources has a 50% interest in Yorkshire Electric Group plc (Yorkshire
Electricity) with an indirect wholly-owned subsidiary of New Century Energies,
Inc. Yorkshire Electricity is a United Kingdom independent regional electricity
company. It is principally engaged in the distribution of electricity to 2.2
million customers in its authorized service territory which is comprised of
3,860 square miles and located centrally in the east coast of England.
Resources' indirect subsidiary, AEP Pushan Power LDC, has a 70% interest
in Nanyang General Light Electric Co., Ltd. (Nanyang Electric), a joint venture
organized to develop and build two 125 megawatt coal-fired generating units near
Nanyang City in the Henan Province of The Peoples Republic of China. Nanyang
Electric was established in 1996 by AEP Pushan Power LDC, Henan Electric Power
Development Co. (15% interest) and Nanyang City Hengsheng Energy Development
Company Limited (formerly Nanyang Municipal Finance Development Co.) (15%
interest). Funding for the construction of the generating units has commenced
and will continue through completion. Unit 1 went into service in February 1999
and Unit 2 is expected to go into service in the third quarter of 1999.
Resources' share of the total cost of the project of $190,000,000 is estimated
to be approximately $110,000,000.
In March 1998, Resources, through AEP Resources Australia Pty., Ltd., a
special purpose subsidiary of Resources, acquired a 20% interest in Pacific
Hydro Limited for $10,000,000. Pacific Hydro is principally engaged in the
development and operation of, and ownership of interests in, hydroelectric
facilities in the Asia Pacific region. Currently, Pacific Hydro has interests in
six hydroelectric units that operate or are under construction in Australia and
the Philippines. The hydroelectric facilities in which Pacific Hydro had
interests as of December 31, 1998 (including those under construction) had total
design capacity of approximately 178 megawatts.
In December 1998, Resources, through wholly-owned subsidiaries, acquired
CitiPower Pty., an electric distribution and retail sales company in Victoria,
Australia, for $1,100,000,000. CitiPower serves approximately 240,000 customers
in the city of Melbourne. With about 3,100 miles of distribution lines in a
service area that covers approximately 100 square miles, CitiPower distributes
about 4,800 gigawatt-hours annually.
In December 1998, Resources acquired from Equitable Resources, Inc.
midstream gas operations for approximately $340,000,000 including working
capital funds. The gas trading and marketing group included in this purchase was
acquired by AEPES. Assets acquired include:
o A 2,000-mile intrastate pipeline system in Louisiana.
o Four natural gas processing plants that straddle the pipeline.
o Jefferson Island storage facility, including an existing salt dome
storage cavern and a second cavern under construction, both directly
connected to the Henry Hub, the most active gas trading area in North
America.
The pipeline and storage facility are interconnected to 15 interstate and
23 intrastate pipelines.
RESCo
RESCo offers engineering, construction, project management and other
consulting services for projects involving transmission, distribution or
generation of electric power both domestically and internationally.
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<PAGE> 23
AEP Communications
AEP Communications markets energy information, wireless tower
infrastructure and fiber optic services. In 1998, AEP Communications launched
DatapultSM, a portfolio of energy information data and analysis tools designed
to help customers identify energy- and cost-saving opportunities. AEP
Communications also is expanding its fiber optic network and marketing dedicated
telecommunications bandwidth to other carriers.
AEP Power Marketing
In July 1996, AEP Power Marketing, Inc. (AEPPM), a wholly-owned subsidiary
of AEP, requested authority from FERC to market electric power at wholesale at
market-based rates. In September 1996, the FERC accepted the filing, conditioned
upon, among other things, the utility subsidiaries of AEP refraining from (1)
selling nonpower goods or services to any affiliate at a price below its cost or
market price, whichever is higher, and (2) purchasing nonpower goods or services
from any affiliate at a price above market price. AEPPM requested FERC to
clarify that the applicability of this condition relates only to transactions
between AEP utility subsidiaries and AEPPM. In 1998, FERC granted the requested
clarification. AEPPM has not entered into any transactions to date. However, the
AEP System is engaged in regulated power marketing and trading within its
traditional marketing area through its Power Pool and in non-regulated financial
derivative power trading activities conducted by the Power Pool but recorded in
non-operating income by the AEP Power Pool member companies.
SEC Limitations
AEP has received approval from the SEC under PUHCA to issue and sell
securities in an amount up to 100% of its average quarterly consolidated
retained earnings balance (such average balance was approximately $1,674,000,000
for the twelve months ended December 31, 1998) for investment in exempt
wholesale generators and foreign utility companies. Resources expects to
continue its pursuit of new and existing energy generation and delivery projects
worldwide.
SEC Rule 58 permits AEP and other registered holding companies to invest
up to 15% of consolidated capitalization in energy-related companies. AEPES, an
energy-related company under Rule 58, is authorized to engage in energy-related
activities, including marketing electricity, gas and other energy commodities.
Risk
These continuing efforts to invest in and develop new business
opportunities offer the potential of earning returns which may exceed those of
traditional AEP rate-regulated operations. However, they also involve a higher
degree of risk which must be carefully considered and assessed. AEP may make
additional substantial investments in these and other new businesses.
Reference is made to Market Risks under Item 7A herein for a discussion of
certain market risks inherent in AEP business activities.
PROPOSED AEP-CSW MERGER
AEP and CSW entered into an Agreement and Plan of Merger, dated as of
December 21, 1997, pursuant to which CSW would, on the closing date, merge with
and into a wholly owned merger subsidiary of AEP with CSW being the surviving
corporation. As a result of the merger, each outstanding share of common stock,
par value $3.50 per share, of CSW (other than shares owned by AEP or CSW) shall
be converted into the right to receive 0.6 of a share of common stock, par value
$6.50 per share, of AEP. Based on the price of AEP's common stock on December
19, 1997, the transaction would be valued at $6.6 billion. The combined company
will be named American Electric Power Company, Inc. and will be based in
Columbus, Ohio.
Consummation of the merger is subject to certain conditions, including the
receipt of required regulatory approvals. Assuming the receipt of all required
approvals, completion of the merger is anticipated to occur by the end of 1999.
CSW is a global, diversified public utility holding company based in
Dallas, Texas. CSW owns four domestic electric utility subsidiaries serving 1.7
million customers in portions of the
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<PAGE> 24
states of Texas, Oklahoma, Louisiana and Arkansas and a regional electricity
company in the United Kingdom. CSW also owns other international energy
operations and non-regulated subsidiaries involved in energy-related
investments, energy efficiency services and financial transactions.
CONSTRUCTION PROGRAM
New Generation
The AEP System is continuously involved in assessing the adequacy of its
generation, transmission, distribution and other facilities to plan and 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, 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's generation
resources include:
o Rerating of the Smith Mountain pumped storage hydroelectric plant
(36-megawatt increase).
o Purchase from an independent power producer's hydro project with an
expected capacity value of 28 megawatts.
o Expiration of the Rockport Unit 1 sale of 455 megawatts to VEPCo on
December 31, 1999 (see AEGCo).
Apart from these changes and temporary power purchases that can be
arranged, there are no specific commitments for additions of new generation
resources on the AEP System. In this regard, the most recent resource plan filed
by AEP's electric utility subsidiaries with various state commissions indicates
no need for new generation resources until beyond the year 2003. When the time
for commitment to additional generation resources approaches, all means for
adding such resources, including self-build and external resource options, will
be considered. However, given the restructuring that is expected to take place
in the industry, the extent of the need of AEP's operating companies for any
additional generation resources in the foreseeable future is highly uncertain.
Proposed Transmission Facilities
On September 30, 1997, APCo refiled applications in Virginia and West
Virginia for certificates to build the Wyoming-Cloverdale 765,000-volt line. The
preferred route for this line is approximately 132 miles in length, connecting
APCo's Wyoming Station in southern West Virginia to APCo's Cloverdale Station
near Roanoke, Virginia. APCo's estimated cost is $263,300,000.
APCo announced this project in 1990. Since then it has been in the process
of trying to obtain federal permits and state certificates. At the federal
level, the U.S. Forest Service (Forest Service) is directing the preparation of
an Environmental Impact Statement (EIS), which is required prior to granting
permits for crossing lands under federal jurisdiction. Permits are needed from
the (i) Forest Service to cross federal forests, (ii) Army Corps of Engineers to
cross the New River and a watershed near the Wyoming Station, and (iii) National
Park Service or Forest Service to cross the Appalachian National Scenic Trail.
In June 1996, the Forest Service released a Draft EIS and preliminarily
identified a "No Action Alternative" as its preferred alternative. If this
alternative were incorporated into the Final EIS, APCo would not be authorized
to cross federal forests administered by the Forest Service. The Forest Service
stated that it would not prepare the Final EIS until after Virginia and West
Virginia determined need and routing issues.
West Virginia: On May 27, 1998, the West Virginia PSC issued an order
granting APCo's application for a certificate with respect to the preferred
route for the Wyoming-Cloverdale 765,000-volt line.
Virginia: By Hearing Examiner's Ruling of June 9, 1998, the procedural
schedule for the certificate in Virginia was suspended for 90 days to allow APCo
to conduct additional studies. On August 21, 1998, APCo filed a report stating
that a two-phased alternative project could provide electrical transmission
reinforcement comparable to the Wyoming-Cloverdale line.
By Hearing Examiner's Ruling of September 22, 1998, the proceeding was
continued and APCo was directed to study the first phase of the alternative
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<PAGE> 25
project, involving a line running from Wyoming Station in West Virginia to
APCo's existing Jacksons Ferry Station in Virginia or any point on the Jacksons
Ferry-Cloverdale 765kV transmission line. APCo estimates that the
Wyoming-Jacksons Ferry line would be between 82-100 miles in length, including
32 miles in West Virginia previously certified. APCo must file its study by June
1, 1999. The Hearing Examiner also ordered APCo and the Virginia SCC Staff to
provide at the evidentiary hearing information on generation alternatives,
specifically natural gas generation, to APCo's proposed transmission line.
If the Virginia SCC grants a certificate for the Wyoming-Jacksons Ferry
line, APCo will have to amend its certificate from West Virginia.
Proposed Completion Schedule: If the Virginia SCC and West Virginia PSC
issue the required certificates, APCo will cooperate with the Forest Service to
complete the EIS process and obtain the federal permits. Management estimates
that neither project can be completed before the winter of 2003-2004. However,
given the findings in the Draft EIS, APCo cannot presently predict the schedule
for completion of the state and federal permitting process.
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 1996, 1997 and 1998 and their current estimate of 1999
construction expenditures, in each case including AFUDC but excluding nuclear
fuel and other assets acquired under leases. The construction expenditures for
the years 1996-1998 were, and it is anticipated that the estimated construction
expenditures for 1999 will be, approximately:
1996 1997 1998 1999
ACTUAL ACTUAL ACTUAL ESTIMATE
------ ------ ------ --------
(IN THOUSANDS)
AEP System (a).. $578,000 $762,000 $792,100 $820,100
AEGCo........ 2,200 3,900 6,600 6,300
APCo......... 192,900 218,100 204,900 254,600
CSPCo........ 93,600 108,900 115,300 94,500
I&M.......... 90,500 123,400 148,900 151,800
KEPCo........ 75,800 66,700 43,800 42,500
OPCo......... 113,800 172,700 185,200 201,000
- -----------------------
(a) Includes expenditures of other subsidiaries not shown.
Reference is made to the footnotes to the financial statements entitled
Commitments and Contingencies incorporated by reference in Item 8, for further
information with respect to the construction plans of AEP and its operating
subsidiaries for the next three years.
The System construction program is reviewed continuously and is revised
from time to time in response to changes in estimates of customer demand,
business and economic conditions, the cost and availability of capital,
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 1996, 1997 and 1998 and the current estimate for 1999 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.
1996 1997 1998 1999
ACTUAL ACTUAL ACTUAL ESTIMATE
------ ------ ------ --------
(IN THOUSANDS)
AEGCo............. $ 0 $ 0 $ 800 $ 0
APCo.............. 10,500 9,100 25,000 36,100
CSPCo............. 1,800 1,300 5,300 3,600
I&M............... 0 100 13,000 6,700
KEPCo............. 100 1,300 4,600 400
OPCo.............. 1,600 11,800 27,100 32,100
AEP System..... $14,000 $23,600 $75,800 $78,900
======= ======= ======= =======
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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 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 1998, AEP issued approximately 1,193,000
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 1996-1998, net external funds from financings and
capital contributions by AEP amounted, with respect to APCo and KEPCo, to
approximately 23% and 75%, 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 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, 1999, and the respective amounts of short-term debt outstanding on that date,
on a corporate basis, are shown in the following tabulation:
<TABLE>
<CAPTION>
TOTAL AEP
SHORT-TERM DEBT AEP AEGCO APCO CSPCO I&M KEPCO OPCO SYSTEM(a)
--------------- --- ----- ---- ----- --- ----- ---- ---------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Amount authorized........................... $500 $80 $325 $300 $300 $150 $400 $2,115
==== === ==== ==== ==== ==== ==== ======
Amount outstanding:
Notes payable......................... $ -- $24 $ 34 $ -- $ -- $ 5 $ -- $ 197
Commercial paper...................... 78 -- 42 52 109 15 123 419
---- --- ---- ---- ---- ---- ---- ------
$ 78 $24 $ 76 $ 52 $109 $ 20 $123 $ 616
==== === ==== ==== ==== ==== ==== ======
</TABLE>
- ------------------
(a) Includes short-term debt of other subsidiaries not shown.
Reference is made to the footnotes to the financial statements
incorporated by reference in Item 8 for further information with respect to
unused short-term bank lines of credit.
In order to issue additional first mortgage bonds, it is necessary for
APCo, CSPCo, I&M, KEPCo and OPCo to comply with earnings coverage requirements
contained in their respective mortgages. The most restrictive of these
provisions generally requires, 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 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 at
certain times restricted the ability of one or more of the above subsidiaries of
AEP to issue senior securities.
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<PAGE> 27
The respective mortgage coverages of APCo, CSPCo, I&M, KEPCo and OPCo
under their respective mortgage provisions, calculated on the foregoing basis
and in accordance with the respective amounts then recorded in the accounts of
the companies, were at least those stated in the following table:
DECEMBER 31,
------------
1996 1997 1998
---- ---- ----
APCo
Mortgage coverage............. 3.98 3.72 3.88
CSPCo
Mortgage coverage............. 4.44 4.95 6.36
I&M
Mortgage coverage............. 6.66 7.57 6.39
KEPCo
Mortgage coverage............. 3.22 4.23 4.40
OPCo
Mortgage coverage............. 8.27 9.74 9.40
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 in the amounts required to finance their business
may depend upon the timely approval of rate increase applications. If one or
more of the subsidiaries are unable to continue the issuance and sale of
securities on an orderly basis, such company or companies will be required to
consider the curtailment of construction and other outlays or the use of
alternative financing arrangements, if available, which may be more costly.
AEP's subsidiaries have also utilized, and expect to continue to utilize,
additional financing arrangements, such as leasing arrangements, including the
leasing of utility assets, coal mining and transportation equipment and
facilities and nuclear fuel. Pollution control revenue bonds have been used in
the past and may be used in the future in connection with the construction of
pollution control facilities; however, Federal tax law has limited the
utilization of this type of financing except for purposes of certain financing
of solid waste disposal facilities and of certain refunding of outstanding
pollution control revenue bonds issued before August 16, 1986.
New projects undertaken by AEP Resources and its subsidiaries are
generally financed through equity funds provided by AEP, non-recourse debt
incurred on a project-specific basis, debt issued by AEP Resources or through a
combination thereof. See New Business Development and Item 7 for additional
information concerning AEP Resources and its subsidiaries.
RATES AND REGULATION
General
The rates charged by the electric utility subsidiaries of AEP are approved
by the FERC or one of the state utility commissions as applicable. The FERC
regulates wholesale rates and the state commissions regulate retail rates. In
recent years the number of rate increase applications filed by the operating
subsidiaries of AEP with their respective state commissions and the FERC has
decreased. Under current rate regulation, if increases in operating,
construction and capital costs exceed increases in revenues resulting from
previously granted rate increases and increased customer demand, then it may be
appropriate for certain of AEP's electric utility subsidiaries to file rate
increase applications in the future.
Generally the rates of AEP's operating subsidiaries are determined based
upon the cost of providing service including a reasonable return on investment.
Certain states served by the AEP System allow alternative forms of rate
regulation in addition to the traditional cost-of-service approach. However, the
rates of AEP's operating subsidiaries in those states continue to be cost-based.
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
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<PAGE> 28
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. In addition, current rate regulation
may be subject to significant revision. See Competition and Business Change.
Investigations of June 1998 Pricing Abnormalities
During the week of June 22-26, 1998, wholesale electric power markets in
the Midwest exhibited unprecedented price volatility due to several market
factors, including an extended period of unseasonably hot weather, scheduled and
unplanned generating unit outages, transmission constraints, and defaults by
certain power marketers on their supply obligations. The simultaneous
culmination of these events resulted in temporary but extreme price spikes in
the hourly and daily markets.
As a result of this situation, the FERC, IURC and PUCO initiated separate
investigations into the price increase. After completing their reviews, these
commissions concluded that the pricing abnormalities were due to the unusual
conditions that occurred during that time. The FERC Staff report issued in
September 1998 did not find evidence that firm service to consumers was
compromised anywhere in the Midwest during the period of the pricing
abnormalities. The FERC reserved the right to conduct further investigations on
a company-specific basis. AEP is unable to predict what, if any, further action
may be taken by the FERC in respect of this matter. No assurance can be given
that the FERC will not take enforcement action in this connection.
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 (ALJ) issued an initial
decision affirming the terms of APCo's filing except for APCo's requested return
on common equity of 12.75% which the ALJ found should be 10.1%. On June 29,
1998, the FERC issued its order affirming the ALJ's decision except the return
on common equity, which the FERC approved at 9.95%. On July 29, 1998, APCo filed
with the FERC a request for rehearing of the FERC's order.
At December 31, 1998, APCo had accrued a refund liability, including
interest, of $42,800,000.
Virginia: In June 1997, APCo filed an application with the Virginia SCC
for approval of an alternative regulatory plan (Plan) and proposed, among other
things, an increase of $30,500,000 in base rates on an annual basis to be
effective July 13, 1997. On July 10, 1997, the Virginia SCC issued an order
suspending implementation of the proposed rates until November 11, 1997 when
these rates were placed into effect subject to refund.
On February 18, 1999, the Virginia SCC approved a stipulation and
settlement agreement among APCo, the Virginia SCC Staff and consumer and major
industrial customer representatives that provides for the following:
o Elimination of the $30,500,000 annual increase in base rates that has
been collected subject to refund since mid-November 1997.
o During the period January 1, 1998 through December 31, 2000:
o Reduction in base rates of $6,000,000 from the level in effect
prior to the November 1997 increase, with the expectation that
rates would remain at the agreed-upon levels.
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<PAGE> 29
o APCo's commitment to invest at least $90,000,000 in Virginia
distribution facilities to maintain the overall quality and
reliability of electric service.
o Benchmark rate of return on equity of 10.85% with one-third of
earnings above that level to be retained by APCo and the
remaining two-thirds to be refunded to ratepayers.
o Refund with interest of all amounts collected above the approved
rates.
At December 31, 1998, APCo had accrued a refund liability, including
interest, of $51,600,000.
West Virginia: On December 27, 1996, the West Virginia PSC approved a
settlement agreement among APCo and other parties. In accordance with that
agreement, the West Virginia PSC reduced APCo's base rates and Expanded Net
Energy Cost (ENEC) rates by $5,000,000 and $28,000,000, respectively, on a
one-time annual basis, effective November 1, 1996. Under the terms of the
agreement, APCo's rates would not increase prior to January 1, 2000 and, through
this date, ENEC cost variances will be subject to deferred accounting and a
cumulative ENEC recovery balance will be maintained. Regardless of the actual
cumulative ENEC recovery balance at December 31, 1999, ratepayers will not be
responsible for any cumulative underrecovery and any cumulative 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%).
From the in-service date of March 1991 until rates went into effect in May
1992, deferred carrying charges of $43,000,000 were recorded on the Zimmer Plant
investment. Recovery of the deferred carrying charges will be sought in the next
PUCO base rate proceeding in accordance with the PUCO accounting order that
authorized the deferral.
I&M
Reference is made to Cook Nuclear Plant --Cook Plant Shutdown under Item 2
herein for a discussion of recovery of fuel costs.
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
fixed the electric fuel component factor at 1.465 cents per kwh for the period
June 1995 through November 1998. After the first to occur of either full
recovery of these costs or November 2009, the price that OPCo can recover for
coal from its affiliated Meigs mine which supplies the Gavin Plant will be
limited to the lower of cost or the then-current market price. The agreements
provide OPCo with the opportunity to recover any operating losses incurred under
the predetermined or fixed price, as well as its investment in, and liabilities
and closing costs associated with, its affiliated mining operations attributable
to its Ohio jurisdiction, to the extent the actual cost of coal burned at the
Gavin Plant is below the predetermined price.
Based on the estimated future cost of coal burned at Gavin Plant,
management believes that the Ohio jurisdictional portion of the investment in,
and liabilities and closing costs of, the affiliated mining operations,
including deferred amounts, will be recovered under the terms of the
predetermined price agreement following shutdown. Management intends to seek
from non-Ohio jurisdictional ratepayers recovery of the non-Ohio jurisdictional
portion of any remaining investment in, and the liabilities and closing costs
of, OPCo's Muskingum, Windsor and Meigs 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 $17,000,000 for Muskingum, $14,000,000 for Windsor and
$68,000,000 for Meigs, after tax at December 31, 1998.
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<PAGE> 30
Management anticipates closing the Muskingum mine in October 1999, Windsor
mine in December 2000 and Meigs mine in December 2001. The Muskingum mine
supplies coal to Muskingum River Plant and the Windsor mine supplies coal to
Cardinal Plant Unit 1. These mines are closing, in part, as a result of
compliance with the Phase II requirements of the Clean Air Act Amendments of
1990 (see Environmental and Other Matters -- Air Pollution Control -- Acid
Rain). The mines could close earlier 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 Muskingum, Windsor
and Meigs mines, including amounts deferred, can be recovered, AEP's and OPCo's
results of operations would be adversely affected.
FUEL SUPPLY
The following table shows the sources of power generated by the AEP
System:
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
Coal..................... 91% 88% 87% 92% 99%
Nuclear.................. 8% 11% 12% 7% 0%
Hydroelectric and other.. 1% 1% 1% 1% 1%
Variations in the generation of nuclear power are primarily related to
refueling outages and, in 1997 and 1998, the shutdown of the Cook Plant to
respond to issues raised by the NRC. See Cook Nuclear Plant -- Cook Plant
Shutdown.
Coal
The Clean Air Act Amendments of 1990 provide for the issuance of annual
allowance allocations covering sulfur dioxide emissions at levels below historic
emission levels for many coal-fired generating units of the AEP System. Phase I
of this program began in 1995 and Phase II begins in 2000, with both phases
requiring significant changes in coal supplies and suppliers. The full extent of
such changes, particularly in regard to Phase II, however, has not been
determined. See Environmental and Other Matters --Air Pollution Control -- Acid
Rain for the current compliance plan.
In order to meet emission standards for existing and new emission sources,
the AEP System companies will, in any event, have to obtain coal supplies, in
addition to coal reserves now owned by System companies, through the acquisition
of additional coal reserves and/or by entering into additional supply
agreements, either on a long-term or spot basis, at prices and upon terms which
cannot now be predicted.
No representation is made that any of the coal rights owned or controlled
by the System will, in future years, produce for the System any major portion of
the overall coal supply needed for consumption at the coal-fired generating
units of the System. Although AEP believes that in the long run it will be able
to secure coal of adequate quality and in adequate quantities to enable existing
and new units to comply with emission standards applicable to such sources, no
assurance can be given that coal of such quality and quantity will in fact be
available. No assurance can be given either that statutes or regulations
limiting emissions from existing and new sources will not be further revised in
future years to specify lower sulfur contents than now in effect or other
restrictions. See Environmental and Other Matters herein.
The FERC has adopted regulations relating, among other things, to the
circumstances under which, in the event of fuel emergencies or shortages, it
might order electric utilities to generate and transmit electric power to other
regions or systems experiencing fuel shortages, and to rate-making principles by
which such electric utilities would be compensated. In addition, the Federal
Government is authorized, under prescribed conditions, to allocate coal and to
require the transportation thereof, for the use of power plants or major
fuel-burning installations.
System companies have developed programs to conserve coal supplies at
System plants which involve, on a progressive basis, limitations on sales of
power and energy to neighboring utilities, appeals to customers for voluntary
limitations of electric usage to essential needs, curtailment of sales to
certain industrial customers, voltage reductions and, finally, mandatory
reductions in cases where current coal supplies fall below minimum levels. Such
programs have been filed and reviewed with officials of Federal and state
agencies and, in some cases, the state regulatory agency has prescribed actions
to be taken under specified circumstances by System companies, subject to the
jurisdiction of such agencies.
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<PAGE> 31
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 an
affiliated terminal on the Ohio River for transloading to barges for delivery to
generating stations on the river. Subsidiaries of AEP lease approximately 3,593
coal hopper cars to be used in unit train movements, as well as 14 towboats, 352
jumbo barges and 145 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>
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Total coal delivered to
AEP operated plants (thousands of tons)....................... 49,024 46,867 51,030 54,292 54,004
Sources (percentage):
Subsidiaries.................................................. 15% 14% 13% 14% 14%
Long-term contracts........................................... 65% 75% 71% 66% 66%
Spot or short-term purchases.................................. 20% 11% 16% 20% 20%
Average price per ton of spot-purchased coal..................... $23.00 $25.15 $23.85 $24.38 $25.05
</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>
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
DOLLARS PER TON
---------------
<S> <C> <C> <C> <C> <C>
AEP System Companies........................................... $ 33.95 $ 32.52 $ 31.70 $ 31.77 $ 32.60
AEGCo....................................................... 18.59 18.80 18.22 19.30 19.37
APCo........................................................ 39.89 38.86 37.60 36.09 34.81
CSPCo....................................................... 32.80 33.23 31.70 31.69 31.63
I&M......................................................... 22.85 23.25 22.99 23.68 22.61
KEPCo....................................................... 26.83 26.91 27.25 26.76 27.42
OPCo........................................................ 41.10 37.58 35.96 36.00 38.94
<CAPTION>
CENTS PER MILLION BTU'S
-----------------------
<S> <C> <C> <C> <C> <C>
AEP System Companies........................................... 152.41 145.26 140.48 140.23 143.51
AEGCo....................................................... 112.06 112.87 109.25 115.21 112.63
APCo........................................................ 161.37 156.96 152.54 146.54 141.76
CSPCo....................................................... 140.45 140.79 134.60 134.44 134.15
I&M......................................................... 123.62 125.50 121.16 123.36 118.02
KEPCo....................................................... 113.40 114.77 114.42 110.37 112.15
</TABLE>
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<PAGE> 32
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, 1998, the
System's coal inventory was approximately 38 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 1998 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 1998 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 1998 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).............. 4,966 253 0.3% 0.7
APCo................... 11,813 454 0.8% 1.3
CSPCo.................. 6,359(b) 249(b) 2.8% 4.7
I&M (c)................ 6,956 293 0.8% 1.5
KEPCo.................. 3,044 94 1.2% 1.9
OPCo................... 20,648 654 2.3% 3.9
</TABLE>
- ------------------------
(a) Reflects AEGCo's 50% interest in the Rockport Plant
(b) Includes coal requirements for CSPCo's interest in Beckjord, Stuart and
Zimmer Plants.
(c) Includes I&M's 50% interest in the Rockport Plant.
AEGCo: See Fuel Supply -- I&M for a discussion of the coal supply for the
Rockport Plant.
APCo: Substantially all of the coal consumed at APCo's generating plants is
obtained from unaffiliated suppliers under long-term contracts and/or on a spot
purchase basis.
The average sulfur content by weight of the coal received by APCo at its
generating stations approximated 0.8% during 1998, 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 2,400,000 tons per year through 1999. 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 48,685,543 tons expires on
December 31, 2014 and another contract with remaining deliveries of 37,785,000
tons expires on December 31, 2004.
25
<PAGE> 33
All of the coal consumed at I&M's Tanners Creek Plant is obtained from
unaffiliated suppliers under long-term contracts and/or on a spot purchase
basis.
KEPCo: Substantially all of the coal consumed at KEPCo's Big Sandy Plant
is obtained from unaffiliated suppliers under long-term contracts and/or on a
spot purchase basis. KEPCo has coal supply agreements with unaffiliated
suppliers pursuant to which KEPCo will receive approximately 2,300,000 tons of
coal in 1999. 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 containing approximately 190,000,000 tons of clean
recoverable coal and ranging in sulfur content between 3.4% and 4.5% sulfur by
weight (weighted average, 3.8%), which reserves are presently being mined. 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 2.7%).
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 101,000,000
tons of clean recoverable coal ranging in sulfur content between 1.4% and 4.0%
sulfur by weight (weighted average, 2.1%) of which approximately 24,000,000 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:
o Mining and milling of uranium ore to uranium concentrates.
o Conversion of uranium concentrates to uranium hexafluoride.
o Enrichment of uranium hexafluoride.
o Fabrication of fuel assemblies.
o Utilization of nuclear fuel in the reactor.
o 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. AEP anticipates that the Cook Plant has storage capacity to permit
normal operations through 2012.
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 $72,000,000,
exclusive of interest of $118,000,000 at December 31, 1998. The aggregate amount
has been recorded as
26
<PAGE> 34
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, 1998, funds collected from
customers to pay the pre-April 1983 fee and accrued interest approximated the
long-term liability. In November 1996, the IURC and MPSC issued orders approving
flexible funding procedures in which any excess funds collected for pre-April 7,
1983 spent nuclear fuel 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 for DOE, reciprocal to the utilities'
obligation to pay, to start disposing of the spent nuclear fuel and high level
radioactive waste no later than January 31, 1998. The court remanded the case to
DOE, holding that determination of a remedy was premature, since DOE had not yet
defaulted on its obligations.
In December 1996, I&M received a letter from DOE advising that DOE
anticipates that it will be unable to begin acceptance of spent nuclear fuel and
high level radioactive waste for disposal in a repository or interim storage
facility by January 31, 1998. On January 31, 1997, in anticipation of DOE's
breach of their statutory and contractual obligations, I&M along with 35
unaffiliated utilities and 33 states filed joint petitions for review in the
U.S. Court of Appeals for the District of Columbia Circuit requesting that the
court permit the utilities to suspend further payments into the nuclear waste
fund, authorize escrow of the payments, and order further action on the part of
DOE to meet its obligations under the NWPA. On November 12, 1997, the Court of
Appeals issued a decision granting in part and denying in part the utilities'
request for relief. The court ordered DOE to proceed with contractual remedies
and to refrain from concluding that DOE's delay is unavoidable due to the lack
of a repository or the lack of interim storage authority. The court, however,
declined to order DOE to begin disposing of fuel. On January 31, 1998, the
deadline for DOE's performance, the DOE failed to begin disposing of the
utilities' spent nuclear fuel.
On June 8, 1998, I&M filed a complaint in the U.S. Court of Federal Claims
seeking damages in excess of $150,000,000 due to the U.S. Department of Energy's
partial material breach of its unconditional contractual deadline to begin
disposing of spent nuclear fuel and high level nuclear waste generated by the
Cook Nuclear Plant. Similar lawsuits have been filed by other utilities.
Studies completed in 1997 estimate decommissioning and low-level
radioactive waste disposal costs for the Cook Plant to range from $700,000,000
to $1.152 billion in 1997 nondiscounted dollars. The wide range is caused by
variables in assumptions, including the estimated length of time spent nuclear
fuel must be stored at the Cook Plant subsequent to ceasing operations, which
depends on future developments in the federal government's spent nuclear fuel
disposal program. Continued delays in the federal fuel disposal program can
result in increased decommissioning costs. I&M is recovering decommissioning
costs in its three rate-making jurisdictions based on at least the lower end of
the range in the most recent respective decommissioning study available at the
time of the rate proceeding (the study range utilized in the Indiana rate case,
I&M's primary jurisdiction, was $588,000,000 to $1.102 billion in 1991 dollars).
I&M records decommissioning costs in other operation expense and records a
noncurrent liability equal to the decommissioning cost recovered in rates which
was $29,000,000 in 1998, $28,000,000 in 1997, and $27,000,000 in 1995. At
December 31, 1998, I&M had recognized a decommissioning liability of
$446,000,000. I&M will continue to reevaluate periodically the cost of
decommissioning and to seek regulatory approval to revise its rates as
necessary.
Funds recovered through the rate-making process for disposal of spent
nuclear fuel consumed prior to April 7, 1983 and for nuclear decommissioning
have been segregated and deposited in external funds for the future payment of
such costs. Trust fund earnings decrease the amount to be recovered from
ratepayers.
27
<PAGE> 35
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 the:
o Type of decommissioning plan selected.
o Escalation of various cost elements (including, but not limited to,
general inflation).
o Further development of regulatory requirements governing
decommissioning.
o Limited availability to date of significant experience in
decommissioning such facilities.
o Technology available at the time of decommissioning differing
significantly from that assumed in these studies.
o Availability of nuclear waste disposal facilities.
Accordingly, management is unable to provide assurance that the ultimate cost of
decommissioning the Cook Plant will not be significantly greater than current
projections.
The Low-Level Waste Policy Act of 1980 (LLWPA) mandates that the
responsibility for the disposal of low-level waste rests with the individual
states. Low-level radioactive waste consists largely of ordinary refuse and
other items that have come in contact with radioactive materials. To facilitate
this approach, the LLWPA authorized states to enter into regional compacts for
low-level waste disposal subject to Congressional approval. The LLWPA also
specified that, beginning in 1986, approved compacts may prohibit the
importation of low-level waste from other regions, thereby providing a strong
incentive for states to enter into compacts. Michigan, the state where the Cook
Plant is located, was a member of the Midwest Compact, but its membership was
revoked in 1991. As a result, Michigan is responsible for developing a disposal
site for the low-level waste generated in Michigan.
Although Michigan amended its law regarding low-level waste site
development in 1994 to allow a volunteer to host a facility, little progress has
been made to date. A bill was introduced in 1996 to further address the issue
but no action was taken. Development of required legislation and 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.
Energy Policy Act -- Nuclear Fees
The Energy Policy Act of 1992 (Energy Act), contains a provision to fund
the decontamination and decommissioning of uranium enrichment facilities
formerly owned by DOE. Funding is to be provided from a combination of sources
including assessments against electric utilities which purchased enrichment
services from DOE facilities. I&M's remaining estimated liability is
$35,521,000, subject to inflation adjustments, and is payable in annual
assessments over the next eight years. I&M recorded a regulatory asset
concurrent with the recording of the liability. The payments are being recorded
and recovered as fuel expense over a 15-year period ending in 2007.
I&M joined with 22 other utility plaintiffs in filing a complaint in the
U.S. District Court for the Southern District of New York seeking a declaratory
judgment that the annual decontamination and decommissioning assessments are
unconstitutional. I&M's claims for refund of previously paid assessments remain
pending in the U.S. Court of Federal Claims. I&M is seeking to stay the Court of
Federal Claims action pending the outcome of the District Court action.
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. In
addition to imposing continuing compliance obligations, these laws and
regulations authorize the imposition of substantial penalties for noncompliance,
including fines, injunctive relief and other sanctions.
28
<PAGE> 36
It is expected that costs related to environmental requirements will
eventually be reflected in the rates of AEP's electric utility subsidiaries and
that AEP's electric utility subsidiaries will be able to provide for required
environmental controls. However, some customers may curtail or cease operations
as a consequence of higher energy costs. There can be no assurance that all such
costs will be recovered. Moreover, legislation currently being proposed at the
state and federal levels governing restructuring of the electric utility
industry may also affect the recovery of certain costs. See Competition and
Business Change.
Except as noted herein, AEP's subsidiaries which own or operate
generating, transmission and distribution facilities are in substantial
compliance with pollution control laws and regulations.
Air Pollution Control
For the AEP System, compliance with the Clean Air Act (CAA) is requiring
substantial expenditures that generally are being recovered through increases in
the rates of AEP's operating subsidiaries. However, there can be no assurance
that all such costs will be recovered. See Construction Program -- Construction
Expenditures.
Acid Rain: The Acid Rain Program (Title IV) of the Clean Air Act
Amendments of 1990 (CAAA) created an emission allowance program pursuant to
which utilities are authorized to emit a designated quantity of sulfur dioxide
(SO2), measured in tons per year, on a system wide or aggregate basis. Emission
reductions are required by virtue of the establishment of annual allowance
allocations at levels substantially below historical emission levels for most
utility units. There are two phases of SO2 control under the Acid Rain Program.
Phase I, effective January 1, 1995, requires SO2 emission reductions from
certain units that emitted SO2 above a rate of 2.5 pounds per million Btu heat
input in 1985. Phase I unit allowance allocations were calculated based on 1985
utilization rates and an emission rate of 2.5 pounds of SO2 per million Btu heat
input. Phase I permits have been issued for all Phase I affected units in the
AEP System.
Phase II, which affects all fossil fuel-fired steam generating units with
capacity greater than 25 megawatts imposes more stringent SO2 emission control
requirements beginning January 1, 2000. If a unit emitted SO2 in 1985 at a rate
in excess of 1.2 pounds per million Btu heat input, the Phase II allowance
allocation is premised upon an emission rate of 1.2 pounds at 1985 utilization
levels. If actual SO2 emissions for a Phase II affected unit in 1985 were less
than 1.2 pounds per million Btu, the allowance allocation is, in most instances,
based on the actual 1985 emission rate.
In addition to regulating SO2 emissions, Title IV of the CAAA contains
provisions regulating emissions of nitrogen oxides (NOx). In April 1995, Federal
EPA promulgated NOx emission limitations for tangentially fired boilers and dry
bottom wall-fired boilers for Phase I and Phase II units. In addition, on
December 19, 1996, Federal EPA published final NOx emission limitations for wet
bottom wall-fired boilers, cyclone boilers, units applying cell burner
technology and all other types of boilers. The regulations also revised downward
the NOx limitations applicable to tangentially fired and wall-fired boilers in
Phase II. These emission limitations are to be achieved by January 1, 2000.
Title I National Ambient Air Quality Standards Attainment: The CAA
contains additional provisions, other than the Acid Rain Program, which could
require reductions in emissions of NOx and other pollutants from fossil
fuel-fired power plants. See NOx SIP Call below.
In July 1997, Federal EPA revised the ozone and particulate matter
National Ambient Air Quality Standards (NAAQS), creating a new eight-hour ozone
standard and establishing a new standard for particulate matter less than 2.5
microns in diameter (PM2.5). Both of these new standards have the potential to
affect adversely the operation of AEP System generating units. Substantial
reductions in NOx emissions from fossil fuel-fired power plants may be required
as part of a state's plan to attain the eight-hour ozone standard. The actual
implementation of the new PM2.5 NAAQS has been delayed for five years.
Substantial reductions in SO2 and/or other emissions from fossil fuel-fired
power plants may be required as part of a state's plan to attain the PM2.5
NAAQS. In August and September 1997 the AEP System operating companies joined
with certain other utilities to appeal the revised NAAQS by filing petitions for
review in the U.S. Court of Appeals for the District of Columbia Circuit. Oral
argument was held in December 1998.
29
<PAGE> 37
In September 1998, Federal EPA issued revisions to the New Source
Performance Standards applicable to new and modified fossil fuel-fired power
plants. Federal EPA characterized its proposal as "fuel neutral" since it would
impose the same stringent NOx emission limit (1.35lb. per megawatt-hour net
energy output) for coal-fired boilers as for gas-fired boilers. The emission
limit is set at a level which cannot currently be achieved by combustion
controls and will require the use of post combustion control equipment. The
final rule effectively requires selective catalytic reduction or comparable
technology to control NOx emissions from new or modified coal-fired boilers.
Imposition of this standard to existing sources which might become subject to
the rule based on an administrative finding that an existing source had been
modified or reconstructed could result in substantial capital and operating
expenditures. On October 30, 1998, the AEP System operating companies joined
with certain other utilities to appeal the revised regulations by filing
petitions for review in the U.S. Court of Appeals for the District of Columbia
Circuit.
NOx SIP Call: On October 27, 1998, Federal EPA published in the Federal
Register a final rule (NOx transport SIP call) concluding that certain State
Implementation Plans are deficient because they allow NOx emissions that
contribute excessively to ozone nonattainment in downwind states. Federal EPA's
NOx transport SIP call establishes state-by-state NOx emission budgets for the
five-month ozone season to be met by the year 2003. The NOx budgets apply to 22
eastern states and are premised mainly on the assumption of controlling power
plant NOx emissions to 0.15 lb. per million Btu (approximately 85% below 1990
levels). The NOx transport SIP call purports to implement both the new
eight-hour ozone standard and the one-hour ozone standard. The SIP call was
accompanied by a proposed Federal Implementation Plan which could be implemented
in any state which fails to submit an approvable SIP by September 1999. The NOx
reductions called for by Federal EPA are targeted at coal-fired electric
utilities and may adversely impact the ability of electric utilities to obtain
new and modified source permits or to operate affected facilities without making
significant capital expenditures. In October 1998, the AEP System operating
companies joined with certain other utilities to appeal the final NOx SIP Call
rule by filing a petition for review in the U.S. Court of Appeals for the
District of Columbia Circuit.
Preliminary estimates indicate that compliance costs could result in
required capital expenditures as follows:
(IN MILLIONS)
-------------
AEP System.......................... $1,200
APCo............................. 325
CSPCo............................ 140
I&M.............................. 169
KEPCo............................ 105
OPCo............................. 452
Compliance costs cannot be estimated with certainty and the actual costs
incurred to comply could be significantly different from this preliminary
estimate depending upon the compliance alternatives selected to achieve
reductions in NOx emissions. Unless such costs are recovered from customers,
they would have a material adverse effect on results of operations, cash flows
and possibly financial condition.
Section 126 Petitions: In August 1997, eight northeastern states (New
York, New Hampshire, Maine, Massachusetts, Rhode Island, Pennsylvania,
Connecticut, and Vermont) filed petitions with Federal EPA under Section 126 of
the Clean Air Act, claiming that NOx emissions from certain named sources in
midwestern states, including all the coal-fired plants of AEP's operating
subsidiaries, prevent those states from attaining the ozone NAAQS. Among other
things, the petitioners generally seek NOx emission reductions 85% below 1990
levels from the utility sources in midwestern states, as in the NOx SIP call. On
October 21, 1998, Federal EPA published in the Federal Register proposed
conditional remedial action requiring NOx emission reductions from named utility
sources.
Federal EPA is seeking comment on the effect on the Section 126 petitions
of a proposed determination by Federal EPA that the one-hour ozone standard no
longer applies to non-attainment areas in Maine, New Hampshire, Rhode Island and
a portion of Massachusetts. In a separate Notice of Proposed Rulemaking, Federal
EPA is seeking comment with respect to its proposed determination
30
<PAGE> 38
that eight-hour ozone non-attainment in New Hampshire and Maine is being
significantly affected by sources of NOx emissions in the northeastern U.S. as
well as certain sources in the midwestern and southern U.S.
In December 1997 Federal EPA entered into a Memorandum of Agreement (MOA)
with the petitioning states that establishes a schedule for taking final action
on the Section 126 petitions on approximately the same time frame as Federal
EPA's final action on the NOx transport SIP call. The MOA called for a proposed
rulemaking on the Section 126 petitions by September 30, 1998 and a technical
determination by April 30, 1999. Final action would be deferred pending
satisfaction of the NOx SIP call requirements. In October 1998, the U.S.
District Court for the Southern District of New York entered an order directing
Federal EPA to conform to the schedule set forth in the MOA.
Hazardous Air Pollutants: Hazardous air pollutant emissions from utility
boilers are potentially subject to control requirements under Title III of the
CAAA. The CAAA specifically directed Federal EPA to study potential public
health impacts of hazardous air pollutants emitted from electric utility steam
generating units. Federal EPA was required to report the results of this study
to Congress by November 1993 and to regulate emissions of these hazardous
pollutants if necessary. On February 25, 1998, Federal EPA issued a final report
to Congress citing as potential health and environmental threats, mercury and
three other hazardous air pollutants present in power plant emissions. Noting
uncertainty regarding health effects and the absence of control technology for
mercury, no immediate regulatory action was proposed regarding emission
reductions.
In addition, Federal EPA is required to study the deposition of hazardous
pollutants in the Great Lakes, the Chesapeake Bay, Lake Champlain, and other
coastal waters. As part of this assessment, Federal EPA is authorized to adopt
regulations to prevent serious adverse effects to public health and serious or
widespread environmental effects. It is possible that this assessment of water
body deposition may result in additional regulation of electric utility steam
generating units.
Federal EPA was also required to study mercury emissions and report its
findings to Congress by 1994. Federal EPA presented that report to Congress in
December 1997. The report identifies electric utilities as being the third
leading emitter of mercury. Presently, mercury emissions from electric utilities
are not regulated under the CAA. However, Federal EPA intends to engage in
further studies of mercury emissions, which may lead to additional regulation in
the future.
Permitting and Enforcement: The CAAA expanded the enforcement authority
of the federal government by increasing the range of civil and criminal
penalties for violations of the CAA and enhancing administrative civil
provisions, adding a citizen suit provision and imposing a national operating
permit system, emission fee program and enhanced monitoring, recordkeeping and
reporting requirements for existing and new sources. On February 13, 1997,
Federal EPA issued the Credible Evidence rule, which allows Federal EPA to use
any credible evidence or information in lieu of, or in addition to, the test
methods prescribed by the regulation for determining compliance with emission
limits. This rule has the potential to expand significantly Federal EPA's
ability to bring enforcement actions and to increase the stringency of the
emission limits to which AEP System plants are subject. In March 1997, a number
of industries, including AEP System operating companies, filed petitions for
review of the Credible Evidence Rule with the U.S. Court of Appeals for the
District of Columbia Circuit. In August 1998, the court held that the appeal was
not ripe for review. A petition for writ of certiori was filed with the U.S.
Supreme Court.
Global Climate Change: In December 1997, delegates from 167 nations,
including the United States, agreed to a treaty, known as the "Kyoto Protocol,"
establishing legally-binding emission reductions for gases suspected of causing
climate change. If the U.S. becomes a party to the treaty it will be bound to
reduce emissions of carbon dioxide (CO2), methane and nitrous oxides by 7% below
1990 levels and emissions of hydrofluorcarbons, perfluorocarbons and sulfur
hexafluoride 7% below 1995 levels in the years 2008-2012. The Protocol was
available for signature from March 16, 1998 to March 15, 1999 and requires
ratification by at least 55 nations that account for at least 55% of developed
countries' 1990 emissions of CO2 to enter into force.
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<PAGE> 39
Although the United States has agreed to the treaty and signed it on
November 12, 1998, President Clinton has indicated that he will not submit the
treaty to the Senate for ratification until it contains requirements for
"meaningful participation by key developing countries" and the rules,
procedures, methodology and guidelines of the treaty's market-based policy
instruments, joint implementation programs and compliance enforcement provisions
have been negotiated. At the Fourth Conference of the Parties, held in Buenos
Aires, Argentina, in November 1998, the parties agreed to a work plan to
complete negotiations on outstanding issues with a view toward approving them at
the Sixth Conference of the Parties to be held in December 2000.
Since the AEP System is a significant emitter of carbon dioxide, its
results of operations, cash flows and financial condition could be adversely
affected by the imposition of limitations on CO2 emissions if compliance costs
cannot be fully recovered from customers. In addition, any such severe program
to reduce CO2 emissions could impose substantial costs on industry and society
and erode the economic base that AEP's operations serve.
West Virginia SO2 Limits: West Virginia promulgated SO2 limitations which
Federal EPA approved in February 1978. The emission limitations for the Mitchell
Plant have been approved by Federal EPA for primary ambient air quality
(health-related) standards only. West Virginia is obligated to reanalyze SO2
emission limits for the Mitchell Plant with respect to secondary ambient air
quality (welfare-related) standards. Because the CAA provides no specific
deadline for approval of emission limits to achieve secondary ambient air
quality standards, it is not certain when Federal EPA will take dispositive
action regarding the Mitchell Plant.
West Virginia has had a request to increase the SO2 emission limitation
for Kammer pending before Federal EPA for many years, although the change has
not been acted upon by Federal EPA. On August 4, 1994, however, Federal EPA
issued a Notice of Violation to OPCo alleging that Kammer Plant was operating in
violation of the applicable federally enforceable SO2 emission limit. On May 20,
1996, the Notice of Violation and an enforcement action subsequently filed by
Federal EPA were resolved through the entry of a consent decree in the U.S.
District Court for the Northern District of West Virginia. The decree provides
for compliance with an interim emission limit of 6.5 pounds of SO2 per million
Btu actual heat input on a three-hour basis and 5.8 pounds of SO2 per million
Btu on an annual basis. West Virginia and industrial sources in the area of the
Kammer Plant are developing a revision to the State Implementation Plan with
respect to SO2 emission limitations which is to be submitted no later than
October 1, 1999. The interim emission limit for Kammer will remain in effect
until after that time.
Short Term SO2 Limits: On January 2, 1997, Federal EPA proposed a new
intervention level program under the authority of Section 303 of the CAA to
address five minute peak SO2 concentrations believed to pose a health risk to
certain segments of the population. The proposal establishes a "concern" level
and an "endangerment" level. States must investigate exceedances of the concern
level and decide whether to take corrective action. If the endangerment level is
exceeded, the state must take action to reduce SO2 levels. The effects of this
proposed intervention program on AEP operations cannot be predicted at this
time.
Regional Haze: On July 31, 1997, Federal EPA proposed new rules to
regulate regional haze attributable to anthropogenic emissions. The primary goal
of the new regional haze program is to address visibility impairment in and
around "Class I" protected areas, such as national parks and wilderness areas.
Because regional haze precursor emissions are believed by Federal EPA to travel
long distances, Federal EPA proposes to regulate such precursor emissions in
every state. Under the proposal, each state must develop a regional haze control
program that imposes controls necessary to steadily reduce visibility impairment
in Class I areas on the worst days and that ensures that visibility remains good
on the best days.
The AEP System is a significant emitter of fine particulate matter and its
precursors that could be linked to the creation of regional haze. The
finalization of Federal EPA's proposed rule to control regional haze may have an
adverse financial impact on AEP as it may trigger the requirement to install
costly new pollution control devices to control emissions of fine particulate
matter and its precursors (including SO2 and NOx). The actual impact of the
regional haze regulations cannot be determined at this time.
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<PAGE> 40
New Source Review: On July 21, 1992, Federal EPA published final
regulations in the Federal Register governing application of new source rules to
generating plant repairs and pollution control projects undertaken to comply
with the CAA. Generally, the rule provides that plants undertaking pollution
control projects will not trigger New Source Review requirements. The Natural
Resources Defense Council and a group of utilities, including five AEP System
companies, have filed petitions in the U.S. Court of Appeals for the District of
Columbia Circuit seeking a review of the regulations. In July 1998, Federal EPA
requested comment on proposed revisions to the New Source Review rules which
would change New Source Review applicability criteria by eliminating exemptions
contained in the current regulation.
On February 4, 1999, Federal EPA (Regions III and V) issued a request
under Section 114 of the Clean Air Act seeking documents and information
regarding capital and maintenance expenditures at AEP's Muskingum River, Gavin,
Cardinal, Sporn and Mitchell plants. Federal EPA conducted a review of the
accounting records of AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo in the summer of
1998 and made site visits to Sporn, Muskingum River and Mitchell plants in the
summer and fall of 1998. These activities are focused on assessing compliance
with the New Source Review and New Source Performance Standard provisions of the
Clean Air Act.
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 1999.
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.
33
<PAGE> 41
In March 1995, Federal EPA finalized a set of rules which establish
minimum water quality standards, anti-degradation policies and implementation
procedures for more stringently controlling releases of toxic pollutants into
the Great Lakes system. This regulatory package is called the Great Lakes Water
Quality Initiative (GLWQI). The most direct compliance cost impact could be
related to I&M's Cook Plant. Based on Federal EPA's current policy on intake
credits and site specific variables and Michigan's implementation strategy,
management does not presently expect the GLWQI will have a significant adverse
impact on Cook Plant operations. If Indiana and Ohio eventually adopt the GLWQI
criteria for statewide application, AEP System plants located in those states
could be adversely affected, although the significance depends on the
implementation strategy of those states.
The Oil Pollution Act of 1990 (OPA) defines certain facilities that, due
to oil storage volume and location, could reasonably be expected to cause
significant and substantial harm to the environment by discharging oil. Such
facilities must operate under approved spill response plans and implement spill
response training and drill programs. OPA imposes substantial penalties for
failure to comply. AEP companies with oil handling and storage facilities
meeting the OPA criteria have in place required response plans, training and
drill programs.
Solid and Hazardous Waste
Section 311 of the Clean Water Act imposes substantial penalties for
spills of Federal EPA-listed hazardous substances into water and for failure to
report such spills. The Comprehensive Environmental Response, 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 PCBs contained in certain capacitors and transformers, but the
occurrence and ramifications of a spill or release of such substances cannot be
predicted.
CERCLA, RCRA 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, joint and several, 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
three cases involving cost-recovery lawsuits at Federal EPA-identified CERCLA
sites. OPCo is involved at two of these sites and I&M at the other site. AEP
System companies are identified as Potentially Responsible Parties (PRPs) for
three additional federal sites, including CSPCo at one site and I&M at two
sites. Management's present estimates do not anticipate material cleanup costs
for identified sites for which AEP subsidiaries have been declared PRPs or are
defendants in CERCLA cost recovery litigation. However, if for reasons not
currently identified significant costs are incurred for cleanup, future results
of operations and possibly financial condition would be adversely affected
unless the costs can be recovered through rates.
Regulations issued by Federal EPA under the Toxic Substances Control Act
govern the use, distribution and disposal of PCBs, including PCBs in electrical
equipment. Deadlines for removing certain PCB-containing electrical equipment
from service have been met.
In addition to handling hazardous substances, the System companies
generate solid waste associated with the combustion of coal, the vast majority
of which is fly ash, bottom ash and flue gas desulfurization wastes. These
wastes presently are considered to be non-hazardous under RCRA and applicable
state law and the wastes are treated and disposed in surface impoundments or
landfills in accordance with state permits or authorization or beneficially
utilized. As required by RCRA, EPA evaluated whether high volume coal combustion
wastes (such as fly ash, bottom ash and flue gas desulfurization wastes) should
be regulated as hazardous waste. In August, 1993 EPA issued a regulatory
determination that such high volume coal combustion wastes should not be
regulated as hazardous waste. For low volume coal combustion wastes, such as
metal and boiler cleaning wastes, Federal EPA will gather additional information
and make a regulatory determination by April 1999. Until that time, these low
volume wastes are
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<PAGE> 42
provisionally excluded from regulation under the hazardous waste provisions of
RCRA. All presently generated hazardous waste is being disposed of at permitted
off-site facilities in compliance with applicable Federal and state laws and
regulations. For System facilities which generate such wastes, System companies
have filed the requisite notices and are complying with RCRA and applicable
state regulations for generators. Nuclear waste produced at the Cook Plant
regulated under the Atomic Energy Act is excluded from regulation under RCRA.
Federal EPA's technical requirements for underground storage tanks
containing petroleum will require retrofitting or replacement of an appreciable
number of tanks. Compliance costs for tank replacement and site remediation have
not been significant to date.
Electric and Magnetic Fields (EMF)
EMF is found everywhere there is electricity. Electric fields are created
by the presence of electric charges. Magnetic fields are produced by the flow of
those charges. This means that EMF is created by electricity flowing in
transmission and distribution lines, household wiring, and appliances.
A number of studies in the past several years have examined the
possibility of adverse health effects from EMF. While some of the
epidemiological studies have indicated some association between exposure to EMF
and health effects, the majority of studies have indicated no such association.
In 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..."
In 1997, the results of a five-year study by the National Cancer Institute
(NCI) were released. The NCI researchers found no evidence that EMF in the home
increases the risk of childhood cancer.
The Energy Policy Act of 1992 established a coordinated Federal EMF
research program which ended in 1998. The program funding was $65,000,000, half
of which was provided by private parties including utilities. The National
Institute of Environmental Health Sciences will provide a report to Congress
this year, summarizing the results of this program. AEP contributed over
$400,000 to this program. AEP has also supported an extensive EMF research
program coordinated by the Electric Power Research Institute, working closely
with its staff and contributing more than $500,000 to this effort in 1998. See
Research and Development.
AEP's participation in these programs is a continuation of its efforts to
monitor and support further research and to communicate with its customers and
employees about this issue. Residential customers of AEP are provided
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 against
electric utilities. A suit was filed on May 23, 1990 against I&M involving
claims that EMF from a 345 KV transmission line caused adverse health effects.
No specific amount has been requested for damages in this case and no trial date
has been set.
Some states have enacted regulations to limit the strength of magnetic
fields at the edge of transmission line rights-of-way. No state which the AEP
System serves has done so. In March 1993, The Ohio Power Siting Board issued its
amended rules providing for additional consideration of the possible effects of
EMF in the certification of electric transmission facilities. Applicants are
required to address possible health effects and discuss the consideration of
design alternatives with respect to estimates of EMF levels. These rules were
reissued in 1998 with no change to EMF language.
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.
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<PAGE> 43
RESEARCH AND DEVELOPMENT
AEP and its subsidiaries are involved in over 100 research projects which
are directed toward:
o Developing more efficient methods of burning coal.
o Reducing the emissions resulting from the combustion of coal.
o Utilizing combustion by-products of coal.
o Exploring new methods of generating electricity.
o Exploring the application of new electrotechnologies.
o Improving the efficiency and reliability of power transmission,
distribution and utilization.
AEP System operating companies are members of the Electric Power Research
Institute (EPRI), an organization founded in 1973 that manages research and
development initiatives, primarily on behalf of the U.S. electric utility
industry. These initiatives include technical programs to improve power
production, delivery and use. EPRI's more than 700 members represent over 90% of
the kilowatt sales in the U.S., but also include competitive power producers,
international organizations and others. Total AEP dues to EPRI were $15,400,000
for 1998, $15,300,000 for 1997 and $9,900,000 for 1996.
Total research and development expenditures by AEP and its subsidiaries,
including EPRI dues, were approximately $24,100,000 for the year ended December
31, 1998, $23,600,000 for the year ended December 31, 1997 and $16,400,000 for
the year ended December 31, 1996. This includes expenditures of $3,300,000 for
1998, $4,600,000 for 1997 and $3,300,000 for 1996 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, 1998, 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
</TABLE>
36
<PAGE> 44
<TABLE>
<CAPTION>
NET KILOWATT
OWNER, PLANT TYPE AND NAME LOCATION (NEAR) CAPABILITY
-------------------------- --------------- ----------
<S> <C> <C>
APPALACHIAN POWER COMPANY, CONT.:
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
----------
</TABLE>
37
<PAGE> 45
<TABLE>
<CAPTION>
NET KILOWATT
OWNER, PLANT TYPE AND NAME LOCATION (NEAR) CAPABILITY
-------------------------- --------------- ----------
<S> <C> <C>
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 overhead 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 OVERHEAD
CIRCUIT MILES OF
TRANSMISSION CIRCUIT MILES
AND OF
DISTRIBUTION 765,000-VOLT
LINES LINES
----- -----
AEP System (a).............. 128,983(b) 2,022
APCo..................... 49,793 641
CSPCo (a)................ 15,578 --
I&M...................... 20,899 614
KEPCo.................... 10,223 258
OPCo .................... 29,406 509
- ----------------------
(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.
38
<PAGE> 46
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 121 high-voltage transmission
interconnections with 25 neighboring electric utility systems. The all-time and
1998 one-hour peak System demands were 25,940,000 and 23,192,000 kilowatts,
respectively (which included 7,314,000 and 3,732,000 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 June 22, 1998, respectively. The net dependable capacity to
serve the System load on such date, including power available under contractual
obligations, was 23,457,000 and 23,761,000 kilowatts, respectively. The all-time
and 1998 one-hour internal peak demands were 19,557,000 and 19,414,000
kilowatts, respectively, and occurred on February 5, 1996 and July 21, 1998,
respectively. The net dependable capacity to serve the System load on such date,
including power dedicated under contractual arrangements, was 23,765,000 and
23,749,000 kilowatts, respectively. The all-time one-hour integrated and
internal net system peak demands and 1998 peak demands for AEP's generating
subsidiaries are shown in the following tabulation:
ALL-TIME ONE-HOUR INTEGRATED 1998 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 6,739 March 12, 1998
CSPCo...... 4,172 June 17, 1994 4,027 July 21, 1998
I&M........ 5,027 June 17, 1994 4,778 July 14, 1998
KEPCo...... 1,711 January 17, 1997 1,444 August 25, 1998
OPCo....... 7,291 June 17, 1994 6,642 August 28, 1998
ALL-TIME ONE-HOUR INTEGRATED 1998 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 6,135 March 13, 1998
CSPCo...... 3,551 July 21, 1998 3,551 July 21, 1998
I&M........ 3,926 July 14, 1997 3,870 July 21, 1998
KEPCo..... 1,418 February 5, 1996 1,299 March 13, 1998
OPCo....... 5,641 August 14, 1995 5,588 June 25, 1998
HYDROELECTRIC PLANTS
AEP has 17 facilities, of which 16 are licensed through FERC. 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. The application was
filed in 1998. The license for the Mottville hydroelectric plant in Michigan
expires in 2003. A notice of intent to relicense was filed in 1998.
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 -0-% during 1998 and 52.6% during 1997. 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 -0-% during 1998 and 65.1% during 1997. The Cook Plant was shut down
in September 1997 to respond to issues raised regarding the operability of
certain safety systems. See Cook Plant Shutdown.
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 of greater significance and less predictable than costs
associated with other sources of generation, in large part due to changing
39
<PAGE> 47
regulatory requirements and safety standards, availability of nuclear waste
disposal facilities 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. 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, any unamortized investment at the end of the Cook Plant's
useful life (whether scheduled or premature), the carrying costs of that
investment and retirement costs, is not assured.
Cook Plant Shutdown
On September 9 and 10, 1997, during a NRC architect engineer design
inspection, questions regarding the operability of certain safety systems caused
AEP operations personnel to shut down Units 1 and 2 of the Cook Plant. On
September 19, 1997, the NRC issued a Confirmatory Action Letter requiring AEP to
address the issues identified in the letter. AEP is working with the NRC to
resolve the remaining open issue in the letter.
In April 1998 the NRC notified I&M that it had convened a Restart Panel
for Cook Plant. In July 1998 the NRC provided a list of the required restart
activities and in October the NRC expanded the list. In order to identify and
resolve the issues necessary to restart the Cook units, AEP is meeting with the
Panel on a regular basis until the units are returned to service.
In January 1999 AEP announced that it will conduct additional engineering
reviews at the Cook Plant that will delay restart of the units. Previously, the
units were scheduled to return to service at the end of the first and second
quarters of 1999. The decision to delay restart resulted from internal
assessments that indicated a need to conduct expanded system readiness reviews.
A new restart schedule will be developed based on the results of the expanded
reviews and should be available in June 1999. When maintenance and other
activities required for restart are complete, AEP will seek concurrence from the
NRC to return the Cook Plant to service. Until these additional reviews are
completed, management is unable to determine when the units will be returned to
service. Unless the costs of the extended outage and restart efforts are
recovered from customers, there would be a material adverse effect on results of
operations, cash flows and possibly financial condition.
In July 1998 AEP received an "adverse trend letter" from the NRC
indicating that NRC senior managers determined that there had been a slow
decline in performance at the Cook Plant during the 18-month period preceding
the letter. The letter indicated that the NRC will closely monitor efforts to
address issues at Cook Plant through additional inspection activities.
In October 1998 the NRC issued AEP a Notice of Violation and proposed a
$500,000 civil penalty for alleged violations at the Cook Plant discovered
during five inspections conducted between August 1997 and April 1998. AEP paid
the penalty.
The cost of electricity supplied to certain retail customers rose due to
the outage of the Cook Plant because higher cost coal-fired generation and
coal-based purchased power were substituted for lower cost nuclear generation.
AEP's Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms
permit the recovery, subject to regulatory commission review and approval, of
changes in fuel costs. This includes the fuel component of purchased power in
the Indiana jurisdiction and changes in replacement power in the Michigan
jurisdiction. Under these fuel cost recovery mechanisms, retail rates contain a
fuel cost adjustment factor that reflects estimated fuel costs for the period
during which the factor will be in effect subject to reconciliation to actual
fuel costs in a future proceeding. When actual fuel costs exceed the estimated
costs reflected in the billing factor a regulatory asset is recorded and
revenues are accrued. Consequently, AEP has recorded a regulatory asset and
accrued revenues in anticipation of the future reconciliation and billing, under
the fuel cost recovery mechanisms, of the higher fuel costs to replace Cook
energy during the extended outage. At December 31, 1998, the regulatory asset
was $65,000,000.
The IURC approved, subject to future reconciliation or refund, agreements
authorizing AEP, during the billing months of July 1998 through March 1999, to
include in rates a fuel cost adjustment factor less than that requested by AEP.
40
<PAGE> 48
On March 16, 1999, a settlement agreement was filed with the IURC
resolving all matters related to the recovery of replacement energy costs due to
the extended Cook Plant outage. The settlement agreement, which is subject to
IURC approval, provides for, among other things:
o A credit of $55,000,000 to Indiana retail customers to be refunded
through customer bills during the months of July, August and September
1999. The credit returns to customers Cook replacement fuel costs
previously recovered.
o Authorization to defer any unrecovered fuel revenues accrued between
September 9, 1997 and December 31, 1999, including the $55,000,000
credited to customers.
o Authorization to defer up to $150,000,000 in incremental operation and
maintenance restart costs for the Cook Plant above the base rate level
incurred during 1999.
o Amortization of the fuel recoveries and restart cost deferrals over a
five-year period ending December 31, 2003.
o Subject to certain force majeure provisions, a freeze in base rates
through December 31, 2003 and a cap on fuel recovery charges through
March 1, 2004.
o Incremental nuclear decommissioning trust fund deposits of $2,500,000
annually over a five-year period ending December 31, 2003.
If the IURC does not approve this settlement, the recovery of Cook Plant
replacement energy costs would then become subject to regulatory hearings.
Nuclear Incident Liability
The Price-Anderson Act limits public liability for a nuclear incident at
any licensed reactor in the United States to $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 $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 $176,000,000 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 $3.0 billion. Coverage is provided by Energy Insurance Bermuda (EIB)
and Nuclear Electric Insurance Limited (NEIL). If EIB's and NEIL's losses exceed
their available resources, I&M would be subject to a total retrospective premium
assessment of up to $16,792,035. 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
decommissioning costs in excess of funds already collected for decommissioning
and for property damage up to $3.0 billion less any amounts used for
stabilization and decontamination. See Fuel Supply -- Nuclear Waste.
The NEIL extra-expense programs provide 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 17 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 $6,405,535.
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
41
<PAGE> 49
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 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. In January 1997 OPCo and the
Service Corporation filed an answer and counterclaims in the District Court and
in February 1998 they filed a motion for summary judgment. On March 1, 1999, the
District Court issued an opinion and order granting OPCo and the Service
Corporation's motion for summary judgment and dismissing the case.
----------------------
The Internal Revenue Service (IRS) agents auditing the AEP System's consolidated
federal income tax returns requested a ruling from their National Office that
certain interest deductions claimed by AEP relating to its corporate owned life
insurance (COLI) program should not be allowed. As a result of a suit filed in
U.S. District Court (discussed below) this request for ruling was withdrawn by
the IRS agents. Adjustments have been or will be proposed by the IRS disallowing
COLI interest deductions for taxable years 1991-96. A disallowance of the COLI
interest deductions through December 31, 1998 would reduce earnings (including
interest) as follows:
(in millions)
-------------
AEP System..................................... $316
APCo........................................ 79
CSPCo....................................... 43
I&M......................................... 66
KEPCo....................................... 8
OPCo........................................ 117
AEP System companies have made no provision for any possible adverse earnings
impact from this matter.
In 1998 AEP made payments of taxes and interest attributable to COLI
interest deductions for taxable years 1991-97 to avoid the potential assessment
by the IRS of any additional above- market rate interest on the contested
amount. The payments to the IRS are included on the balance sheet in other
property and investments pending the resolution of this matter. AEP will seek
refund, either administratively or through litigation, of all amounts paid plus
interest. In order to resolve this issue without further delay, on March 24,
1998, AEP filed suit against the U.S. in the U.S. District Court for the
Southern District of Ohio. Management believes that it has a meritorious
position and will vigorously pursue this lawsuit. In the event the resolution of
this matter is unfavorable, it will have a material adverse impact on results of
operations and cash flows.
----------------------
See Item 1 for a discussion of certain environmental and rate matters.
42
<PAGE> 50
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 1, 1999.
<TABLE>
<CAPTION>
NAME AGE OFFICE (a)
- ---- --- ----------
<S> <C> <C>
E. Linn Draper, Jr............ 57 Chairman of the Board, President and Chief Executive Officer of AEP and of the
Service Corporation
Donald M. Clements, Jr........ 49 Executive Vice President-Corporate Development of the Service
Corporation
Henry W. Fayne................ 52 Executive Vice President-Financial Services of the Service Corporation
William J. Lhota.............. 59 Executive Vice President of the Service Corporation
James J. Markowsky............ 54 Executive Vice President-Power Generation of the Service Corporation
J. H. Vipperman............... 58 Executive Vice President-Corporate Services 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 for Mr.
Clements. Prior to joining the Service Corporation in 1994 as Senior Vice
President-Corporate Development, Mr. Clements was Senior Vice President of
External Affairs of Gulf States Utilities Company (1993-1994). 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 1, 1999, 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............ 57 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
Henry W. Fayne................ 52 Director 1995-Present
Vice President 1998-Present
Vice President and Chief Financial Officer of AEP 1998-Present
Executive Vice President-Financial Services of the
Service Corporation 1998-Present
Senior Vice President-Corporate Planning & Budgeting
of the Service Corporation 1995-1998
Senior Vice President-Controller of the
Service Corporation 1993-1995
</TABLE>
43
<PAGE> 51
<TABLE>
<CAPTION>
NAME AGE POSITION (a) PERIOD
- ---- --- ------------ ------
<S> <C> <C> <C>
William J. Lhota.............. 59 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
James J. Markowsky............ 54 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
J. H. Vipperman............... 58 Director 1985-Present
Vice President 1996-Present
President and Chief Operating Officer 1990-1995
Executive Vice President-Corporate Services of the
Service Corporation 1998-Present
Executive Vice President-Energy Delivery of the
Service Corporation 1996-1997
</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 1, 1999, 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.......... 57 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
Henry W. Fayne.............. 52 Director 1993-Present
Vice President 1998-Present
Vice President and Chief Financial Officer of AEP 1998-Present
Executive Vice President-Financial Services of the
Service Corporation 1998-Present
Senior Vice President-Corporate Planning & Budgeting
of the Service Corporation 1995-1998
Senior Vice President-Controller of the
Service Corporation 1993-1995
</TABLE>
44
<PAGE> 52
<TABLE>
<CAPTION>
NAME AGE POSITION (a) PERIOD
- ---- --- ------------ ------
<S> <C> <C> <C>
William J. Lhota............ 59 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
James J. Markowsky............ 54 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
J. H. Vipperman............. 58 Director and Vice President 1996-Present
Executive Vice President-Corporate Services of the
Service Corporation 1998-Present
Executive Vice President-Energy Delivery of the
Service Corporation 1996-1997
President and Chief Operating Officer of APCo 1990-1995
</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
- ------------- ---- --- --------
March 1997........................... 43-3/16 40 .60
June 1997............................ 42-1/2 39-1/8 .60
September 1997....................... 46-5/8 41-1/2 .60
December 1997........................ 52 45-1/4 .60
March 1998........................... 51-11/16 47-13/16 .60
June 1998............................ 50-3/4 44-11/16 .60
September 1998....................... 48 13/16 42 1/16 .60
December 1998........................ 53 5/16 45 5/16 .60
At December 31, 1998, AEP had approximately 134,000 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.
45
<PAGE> 53
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
1998 Annual Report (for the fiscal year ended December 31, 1998).
APCO. The information required by this item is incorporated herein by
reference to the material under Selected Consolidated Financial Data in the APCo
1998 Annual Report (for the fiscal year ended December 31, 1998).
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
1998 Annual Report (for the fiscal year ended December 31, 1998).
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
1998 Annual Report (for the fiscal year ended December 31, 1998).
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 1998
Annual Report (for the fiscal year ended December 31, 1998).
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 1998 Annual Report (for the
fiscal year ended December 31, 1998).
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 1998 Annual Report (for the
fiscal year ended December 31, 1998).
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 1998
Annual Report (for the fiscal year ended December 31, 1998).
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 1998 Annual Report (for the
fiscal year ended December 31, 1998).
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 1998
Annual Report (for the fiscal year ended December 31, 1998).
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 1998 Annual Report (for the
fiscal year ended December 31, 1998).
46
<PAGE> 54
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- --------------------------------------------------------------------------------
AEGCO. The information required by this item is incorporated herein by
reference to the material under Management's Narrative Analysis of Results of
Operations in the AEGCo 1998 Annual Report (for the fiscal year ended December
31, 1998).
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 1998 Annual Report (for the
fiscal year ended December 31, 1998).
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 1998 Annual Report (for the
fiscal year ended December 31, 1998).
CSPCO. The information required by this item is incorporated herein by
reference to the material under Management's Narrative Analysis of Results of
Operations in the CSPCo 1998 Annual Report (for the fiscal year ended December
31, 1998).
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 1998 Annual Report (for the
fiscal year ended December 31, 1998).
KEPCO. The information required by this item is incorporated herein by
reference to the material under Management's Narrative Analysis of Results of
Operations in the KEPCo 1998 Annual Report (for the fiscal year ended December
31, 1998).
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 1998 Annual Report (for the
fiscal year ended December 31, 1998).
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- --------------------------------------------------------------------------------
AEGCO, AEP, APCO, CSPCO, I&M, KEPCO, AND 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.
47
<PAGE> 55
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 for the 1999 annual meeting of shareholders, to be filed within 120 days
after December 31, 1998. 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 1999 annual meeting of stockholders, to be
filed within 120 days after December 31, 1998. 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 1, 1999, 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............ 57 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
Henry W. Fayne................ 52 Director and Vice President 1998-Present
Vice President and Chief Financial Officer of AEP 1998-Present
Executive Vice President-Financial Services of the
Service Corporation 1998-Present
Senior Vice President-Corporate Planning &
Budgeting of the Service Corporation 1995-1998
Senior Vice President-Controller of the
Service Corporation 1993-1995
William J. Lhota.............. 59 Director 1989-Present
President and Chief Operating Officer 1996-Present
Vice President 1989-1995
Executive Vice President of the Service Corporation 1993-Present
</TABLE>
48
<PAGE> 56
<TABLE>
<CAPTION>
NAME AGE POSITION (a)(b)(c) PERIOD
- ---- --- ------------------ ------
<S> <C> <C> <C>
James J. Markowsky............ 54 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
Armando A. Pena............... 54 Director, Vice President and Chief Financial Officer 1998-Present
Treasurer 1995-Present
Chief Financial Officer of the Service Corporation 1998-Present
Senior Vice President-Finance of the Service
Corporation 1996-Present
Treasurer of AEP and the Service Corporation 1995-Present
J. H. Vipperman............... 58 Director and Vice President 1996-Present
Executive Vice President-Corporate Services of the
Service Corporation 1998-Present
Executive Vice President-Energy Delivery of the 1996-1997
Service Corporation
President and Chief Operating Officer of APCo 1990-1995
K. G. Boyd.................... 47 Director 1997-Present
Indiana Region Manager 1997-Present
Fort Wayne District Manager 1994-1997
C. R. Boyle, III.............. 50 Director 1996-Present
Vice President 1996-1999
Vice President-Regulatory Services of the
Service Corporation 1999-Present
President and Chief Operating Officer of KEPCo 1990-1995
G. A. Clark.................. 47 Director 1995-Present
Governmental Affairs Manager 1996-Present
General Counsel 1994-1995
General Attorney 1991-1993
J. A. Kobyra.................. 46 Director 1998-Present
Cook Plant Steam Generator Project Manager 1998-Present
Cook Plant Chief Nuclear Engineer 1994-1998
D. B. Synowiec................ 55 Director 1995-Present
Plant Manager 1990-Present
W. E. Walters................. 51 Director 1991-Present
Michiana Region Manager 1994-Present
Executive Assistant to President 1987-1994
E. H. Wittkamper.............. 60 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 CellNet Data Systems,
Inc. and Mr. Lhota is a director of Huntington Bancshares Incorporated and
State Auto Financial Corporation.
(c) Drs. Draper and Markowsky and Messrs. Fayne, Lhota and Pena are directors
of AEGCo, APCo, CSPCo, KEPCo and OPCo. Dr. Draper is also a director of
AEP. Mr. Vipperman is a director of APCo, CSPCo, KEPCo and OPCo.
49
<PAGE> 57
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 1999 annual meeting of
shareholders, to be filed within 120 days after December 31, 1998. 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 Directors Compensation and Stock Ownership
Guidelines, Executive Compensation and the performance graph of the definitive
proxy statement of AEP for the 1999 annual meeting of shareholders to be filed
within 120 days after December 31, 1998.
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 1999 annual meeting of stockholders, to be
filed within 120 days after December 31, 1998.
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 1999 annual meeting of shareholders, to be
filed within 120 days after December 31, 1998.
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 1998, 1997 and 1996 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, 1998.
Summary Compensation Table
<TABLE>
<CAPTION>
LONG TERM
ANNUAL COMPENSATION
COMPENSATION ---------------------
------------------- PAYOUTS ALL OTHERN
SALARY BONUS --------------------- COMPENSATION
NAME AND PRINCIPAL POSITION YEAR ($) ($)(1) LTIP PAYOUTS ($)(1) ($)(2)
---------------------------------- ------- ------ --------- --------------------- ------------
<S> <C> <C> <C> <C> <C>
E. LINN DRAPER, JR. - Chairman of the board, 1998 780,000 194,376 345,906 104,941
president and chief executive officer of the 1997 720,000 327,744 951,132 31,620
Company and the Service Corporation; chairman 1996 720,000 281,664 675,903 31,990
and chief executive officer of other
subsidiaries
WILLIAM J. LHOTA - Executive vice president and 1998 380,000 82,859 134,266 56,493
director of the Service Corporation; 1997 355,000 141,396 364,436 20,570
president, chief operating officer and 1996 320,000 125,184 263,114 19,690
director of other subsidiaries
JAMES J. MARKOWSKY - Executive vice president - 1998 350,000 76,317 127,115 51,859
power generation and director of the Service 1997 325,000 129,447 338,382 18,020
Corporation; vice president and director of 1996 303,000 118,534 254,535 19,480
other subsidiaries
</TABLE>
50
<PAGE> 58
<TABLE>
<CAPTION>
LONG TERM
ANNUAL COMPENSATION
COMPENSATION ---------------------
------------------- PAYOUTS ALL OTHERN
SALARY BONUS --------------------- COMPENSATION
NAME AND PRINCIPAL POSITION YEAR ($) ($)(1) LTIP PAYOUTS ($)(1) ($)(2)
---------------------------------- ------- ------ --------- --------------------- ------------
<S> <C> <C> <C> <C> <C>
JOSEPH H.VIPPERMAN - Executive vice president 1998 310,000 67,595 82,859 58,435
-corporate services and director of the
Service Corporation; vice president and
director of other subsidiaries (3)
HENRY W. FAYNE - Executive vice president - 1998 290,000 63,234 61,555 34,124
financial services and director of the Service
Corporation; vice president and director of
other subsidiaries (3)
</TABLE>
- ------------------------
(1) Amounts in the Bonus column reflect awards under the Senior Officer Annual
Incentive Compensation Plan (and predecessor Management Incentive
Compensation Plan). Payments were made in March of the succeeding fiscal
year for performance in the year indicated. Amounts for 1998 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 for three-year
performance periods.
See below under Long Term Incentive Plans - Awards in 1998 for additional
information.
(2) Amounts in the All Other Compensation column include (i) AEP's matching
contributions under the AEP Employees Savings Plan and the AEP Supplemental
Savings Plan, a non-qualified plan designed to supplement the AEP Savings
Plan, and (ii) subsidiary companies director fees. For 1998, the amounts
also include split-dollar insurance. Split-dollar insurance represents the
present value of the interest projected to accrue for the employee's
benefit on the current year's insurance premium paid by AEP. Cumulative net
life insurance premiums paid are recovered by AEP at the later of
retirement or 15 years. Detail of the 1998 amounts in the All Other
Compensation column is shown below.
<TABLE>
<CAPTION>
Item Dr. Draper Mr. Lhota Dr. Markowsky Mr. Vipperman Mr. Fayne
---- ---------- --------- ------------- ------------- ---------
<S> <C> <C> <C> <C> <C>
Savings Plan Matching Contributions $ 3,200 $ 4,800 $ 4,800 $ 4,800 $ 4,800
Supplemental Savings Plan Matching Contributions 20,200 6,600 5,700 4,500 3,900
Split-Dollar Insurance 71,621 35,173 31,439 43,135 17,399
Subsidiaries Directors Fees 9,920 9,920 9,920 6,000 8,025
-------- ------- ------- ------- -------
Total All Other Compensation $104,941 $56,493 $51,859 $58,435 $34,124
======== ======= ======= ======= =======
</TABLE>
(3) No 1996 or 1997 compensation information is reported for Messrs. Vipperman
and Fayne because they were not executive officers in these years.
Long-Term Incentive Plans -- Awards In 1998
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 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.
51
<PAGE> 59
<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> <C>
E. L. Draper, Jr................... 7,730 1998-2000 1,932 7,730 15,460
W. J. Lhota........................ 2,636 1998-2000 659 2,636 5,272
J. J. Markowsky.................... 2,428 1998-2000 607 2,428 4,856
J. H. Vipperman.................... 2,150 1998-2000 537 2,150 4,300
H. W. Fayne........................ 2,012 1998-2000 503 2,012 4,024
</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
--------------- --------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
$ 300,000 $ 69,525 $ 92,700 $115,875 $139,050 $162,225 $182,175
400,000 93,525 124,700 155,875 187,050 218,225 244,825
500,000 117,525 156,700 195,875 235,050 274,225 307,475
700,000 165,525 220,700 275,875 331,050 386,225 432,775
900,000 213,525 284,700 355,875 427,050 498,225 558,075
1,200,000 285,525 380,700 475,875 571,050 666,225 746,025
</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 55 and 62. 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
Senior Officer Annual Incentive Compensation Plan (and predecessor 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, 1998, the number of full years of
service applicable for retirement benefit calculation purposes for such officers
were as follows: Dr. Draper, six years; Mr. Lhota, 34 years; Dr. Markowsky, 27
years; Mr. Vipperman, 35 years; and Mr. Fayne, 23 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.
52
<PAGE> 60
Ten AEP System employees (including Messrs. Fayne, Lhota and Vipperman 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
1999 of the executive officers named in the Summary Compensation Table, none of
them would receive any supplemental benefits.
AEP 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 DEFERRED RETIREMENT
DEFERRED PAYMENT (4-YEAR PERIOD) PAYMENT
NAME (4-YEAR PERIOD) (15-YEAR PERIOD) (15-YEAR PERIOD)
-------- ------------------- -------------------- ------------------- --------------------
<S> <C> <C> <C> <C>
J. H. Vipperman............... $11,000 $90,750 $10,000 $67,500
H. W. Fayne................... $ 0 $ 0 $ 9,000 $95,400
</TABLE>
Severance Plan
In connection with the proposed merger with Central and South West
Corporation, AEP's Board of Directors adopted a severance plan on February 24,
1999, effective March 1, 1999, that includes Dr. Markowsky and Messrs. Lhota,
Vipperman and Fayne. The severance plan provides for payments and other benefits
if, within two years after the merger is completed, the officer's employment is
terminated by AEP without "cause" or by the officer because of a detrimental
change in responsibilities or a reduction in salary or benefits. Under the
severance plan, the officer will receive:
o A lump sum payment equal to three times the officer's annual base
salary plus target annual incentive under the Senior Officer Annual
Incentive Compensation Plan.
o Maintenance for a period of three additional years of all medical and
dental insurance benefits substantially similar to those benefits to
which the officer was entitled immediately prior to termination,
reduced to the extent comparable benefits are otherwise received.
o Outplacement services not to exceed a cost of $30,000 or use of an
office and secretarial services for up to one year.
AEP's obligation for the payments and benefits under the severance plan is
subject to the waiver by the officer of any other severance benefits that may be
provided by AEP. In addition, the officer agrees to refrain from the disclosure
of confidential information relating to AEP.
-----------------------------
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.
53
<PAGE> 61
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 for the 1999 annual meeting of
shareholders to be filed within 120 days after December 31, 1998.
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 1999 annual
meeting of stockholders, to be filed within 120 days after December 31, 1998.
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, 1999, 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.
STOCK
NAME SHARES(a) UNITS(b) TOTAL
- ---- --------- -------- -----
Karl G. Boyd ......................... 1,679 158 1,837
Coulter R. Boyle, III ................ 4,000 662 4,662
Gregory A. Clark ..................... 16 -- 16
E. Linn Draper, Jr ................... 7,934(c) 77,612 85,546
Henry W. Fayne ....................... 4,649 10,135 14,784
James A. Kobyra ...................... 3,454(c) 415 3,869
William J. Lhota ..................... 16,042(c)(d) 14,902 30,944
James J. Markowsky ................... 3,942(e) 13,062 17,004
Armando A. Pena ...................... 4,886 5,213 10,099
David B. Synowiec .................... 74 366 440
Joseph H. Vipperman .................. 10,734(c)(d) 4,718 15,452
William E. Walters ................... 6,118 316 6,434
Earl H. Wittkamper ................... 3,231(c) 307 3,538
All Directors and Executive Officers.. 151,990(d)(f) 127,866 279,856
(a) Includes share equivalents held in the AEP Employees Savings Plan in the
amounts listed below:
<TABLE>
<CAPTION>
AEP EMPLOYEES SAVINGS AEP EMPLOYEES SAVINGS
NAME PLAN (SHARE EQUIVALENTS) NAME PLAN (SHARE EQUIVALENTS)
---- ------------------------ ---- ------------------------
<S> <C> <C> <C>
Mr. Boyd............................. 1,675 Dr. Markowsky.............................. 3,888
Mr. Boyle............................ 4,000 Mr. Pena................................... 3,464
Mr. Clark............................ 16 Mr. Synowiec............................... 74
Dr. Draper........................... 3,033 Mr. Vipperman.............................. 10,002
Mr. Fayne............................ 4,144 Mr. Walters................................ 6,118
Mr. Kobyra........................... 2,604 Mr. Wittkamper............................. 1,809
Mr. Lhota............................ 13,862 All Directors and Executive Officers............ 54,689
</TABLE>
With respect to the share equivalents held in the AEP Employees
Savings Plan, such persons have sole voting power, but the
investment/disposition power is subject to the terms of the Plan.
(b) This column includes amounts deferred in stock units and held under AEP's
officer benefit plans.
(c) Includes the following numbers of shares held in joint tenancy with a
family member: Dr. Draper, 4,901; Mr. Kobyra, 850; Mr. Lhota, 2,180; Mr.
Vipperman, 67; and Mr. Wittkamper, 1,422.
(d) Does not include, for Messrs. Lhota and Vipperman, 85,231 shares in the
American Electric Power System Educational Trust Fund over which Messrs.
Lhota and Vipperman 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.
(e) Includes 20 shares held by family members of Dr. Markowsky over which
beneficial ownership is disclaimed.
(f) Represents less than 1% of the total number of shares outstanding
54
<PAGE> 62
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 1999 annual
meeting of shareholders, to be filed within 120 days after December 31, 1998.
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:
The following financial statements have been incorporated herein by
reference pursuant to Item 8.
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
AEGCo:
Independent Auditors' Report; Statements of Income for the years
ended December 31, 1998, 1997 and 1996; Statements of Retained
Earnings for the years ended December 31, 1998, 1997 and 1996;
Statements of Cash Flows for the years ended December 31, 1998, 1997
and 1996; Balance Sheets as of December 31, 1998 and 1997; Notes to
Financial Statements
AEP and its subsidiaries consolidated:
Consolidated Statements of Income for the years ended December 31,
1998, 1997 and 1996; Consolidated Statements of Retained Earnings for
the years ended December 31, 1998, 1997 and 1996; Consolidated
Balance Sheets as of December 31, 1998 and 1997; Consolidated
Statements of Cash Flows for the years ended December 31, 1998, 1997
and 1996; Notes to Consolidated Financial Statements; Schedule of
Consolidated Cumulative Preferred Stocks of Subsidiaries at December
31, 1998 and 1997; Schedule of Consolidated Long-term Debt of
Subsidiaries at December 31, 1998 and 1997; Independent Auditors'
Report.
APCo:
Consolidated Statements of Income for the years ended December 31,
1998, 1997 and 1996; Consolidated Balance Sheets as of December 31,
1998 and 1997; Consolidated Statements of Cash Flows for the years
ended December 31, 1998, 1997 and 1996; Consolidated Statements of
Retained Earnings for the years ended December 31, 1998, 1997 and
1996; Notes to Consolidated Financial Statements; Independent
Auditors' Report.
CSPCo:
Independent Auditors' Report; Consolidated Statements of Income for
the years ended December 31, 1998, 1997 and 1996; Consolidated
Balance Sheets as of December 31, 1998 and 1997; Consolidated
Statements of Cash Flows for the years ended December 31, 1998, 1997
and 1996; Consolidated Statements of Retained Earnings for the years
ended December 31, 1998, 1997 and 1996; Notes to Consolidated
Financial Statements.
</TABLE>
55
<PAGE> 63
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
I&M:
Independent Auditors' Report; Consolidated Statements of Income for
the years ended December 31, 1998, 1997 and 1996; Consolidated
Balance Sheets as of December 31, 1998 and 1997; Consolidated
Statements of Cash Flows for the years ended December 31, 1998, 1997
and 1996; Consolidated Statements of Retained Earnings for the years
ended December 31, 1998, 1997 and 1996; Notes to Consolidated
Financial Statements.
KEPCo:
Independent Auditors' Report; Statements of Income for the years
ended December 31, 1998, 1997 and 1996; Statements of Retained
Earnings for the years ended December 31, 1998, 1997 and 1996;
Balance Sheets as of December 31, 1998 and 1997; Statements of Cash
Flows for the years ended December 31, 1998, 1997 and 1996; Notes to
Financial Statements.
OPCo:
Independent Auditors' Report; Consolidated Statements of Income for
the years ended December 31, 1998, 1997 and 1996; Consolidated
Statements of Cash Flows for the years ended December 31, 1998, 1997
and 1996; Consolidated Balance Sheets as of December 31, 1998 and
1997; Consolidated Statements of Retained Earnings for the years
ended December 31, 1998, 1997 and 1996; 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
</TABLE>
(b) No Reports on Form 8-K were filed during the quarter ended December 31,
1998.
56
<PAGE> 64
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/ A. A. PENA
--------------------------------------
(A. A. PENA, VICE PRESIDENT, TREASURER
AND CHIEF FINANCIAL OFFICER)
Date: March 19, 1999
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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
(I) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. President,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/s/ A. A. PENA Vice President, Treasurer, March 19, 1999
- ------------------------------------ Chief Financial Officer
(A. A. PENA) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ L. V. ASSANTE Controller and March 19, 1999
- ------------------------------------ Chief Accounting Officer
(L. V. ASSANTE)
(IV) A MAJORITY OF THE DIRECTORS:
*HENRY W. FAYNE
*JOHN R. JONES, III
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*By: /s/ A. A. PENA March 19, 1999
-----------------------------------
(A. A. PENA, ATTORNEY-IN-FACT)
</TABLE>
57
<PAGE> 65
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/ H. W. FAYNE
--------------------------------
(H. W. FAYNE, VICE PRESIDENT
AND CHIEF FINANCIAL OFFICER)
Date: March 19, 1999
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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
(I) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board,
President,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/s/ H. W. FAYNE Vice President and March 19, 1999
- ------------------------------------ Chief Financial Officer
(H. W. FAYNE)
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ L. V. ASSANTE Controller and March 19, 1999
- ------------------------------------ Chief Accounting Officer
(L. V. ASSANTE)
(IV) A MAJORITY OF THE DIRECTORS:
*JOHN P. DESBARRES
*ROBERT M. DUNCAN
*ROBERT W. FRI
*LESTER A. HUDSON, JR.
*LEONARD J. KUJAWA
*ANGUS E. PEYTON
*DONALD G. SMITH
*LINDA GILLESPIE STUNTZ
*KATHRYN D. SULLIVAN
*MORRIS TANENBAUM
*By: /s/ H. W. FAYNE March 19, 1999
-----------------------------------
(H. W. FAYNE, ATTORNEY-IN-FACT)
</TABLE>
58
<PAGE> 66
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/ A. A. PENA
--------------------------------------
(A. A. PENA, VICE PRESIDENT, TREASURER
AND CHIEF FINANCIAL OFFICER)
Date: March 19, 1999
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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
(I) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/s/ A. A. PENA Vice President, Treasurer, Chief March 19, 1999
- -------------------------------------- Financial Officer
(A. A. PENA) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ L. V. ASSANTE Controller and March 19, 1999
- -------------------------------------- Chief Accounting Officer
(L. V. ASSANTE)
(IV) A MAJORITY OF THE DIRECTORS:
*HENRY W. FAYNE
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*J. H. VIPPERMAN
*By: /s/ A. A. PENA March 19, 1999
---------------------------------
(A. A. PENA, ATTORNEY-IN-FACT)
</TABLE>
59
<PAGE> 67
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/ A. A. PENA
--------------------------------------
(A. A. PENA, VICE PRESIDENT, TREASURER
AND CHIEF FINANCIAL OFFICER)
Date: March 19, 1999
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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
(I) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/s/ A. A. PENA Vice President, Treasurer, March 19, 1999
- ---------------------------------------- Chief Financial Officer
(A. A. PENA) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ L. V. ASSANTE Controller and March 19, 1999
- ---------------------------------------- Chief Accounting Officer
(L. V. ASSANTE)
(IV) A MAJORITY OF THE DIRECTORS:
*HENRY W. FAYNE
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*J. H. VIPPERMAN
*By: /s/ A. A. PENA March 19, 1999
----------------------------------
(A. A. PENA, ATTORNEY-IN-FACT)
</TABLE>
60
<PAGE> 68
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/ A. A. PENA
--------------------------------------
(A. A. PENA, VICE PRESIDENT, TREASURER
AND CHIEF FINANCIAL OFFICER)
Date: March 19, 1999
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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
(I) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/s/ A. A. PENA Vice President, Treasurer, March 19, 1999
- ---------------------------------------- Chief Financial Officer
(A. A. PENA) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ L. V. ASSANTE Controller and March 19, 1999
- ---------------------------------------- Chief Accounting Officer
(L. V. ASSANTE)
(IV) A MAJORITY OF THE DIRECTORS:
*K. G. BOYD
*C. R. BOYLE, III
*G. A. CLARK
*HENRY W. FAYNE
*JAMES A. KOBYRA
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*D. B. SYNOWIEC
*J. H. VIPPERMAN
*W. E. WALTERS
*E. H. WITTKAMPER
*By: /s/ A. A. Pena. March 19, 1999
------------------------------
(A. A. PENA, ATTORNEY-IN-FACT)
</TABLE>
61
<PAGE> 69
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/ A. A. PENA
--------------------------------------
(A. A. PENA, VICE PRESIDENT, TREASURER
AND CHIEF FINANCIAL OFFICER)
Date: March 19, 1999
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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
(V) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board,
Chief Executive Officer
and Director
(VI) PRINCIPAL FINANCIAL OFFICER:
/s/ A. A. PENNA Vice President, Treasurer, March 19, 1999
- --------------------------------------- Chief Financial Officer
(A. A. PENA) and Director
(VII) PRINCIPAL ACCOUNTING OFFICER:
/s/ L. V. ASSANTE Controller and March 19, 1999
- --------------------------------------- Chief Accounting Officer
(L. V. ASSANTE)
(VIII) A MAJORITY OF THE DIRECTORS:
*HENRY W. FAYNE
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*J. H. VIPPERMAN
March 19, 1999
*By: /s/ A. A. Pena
------------------------------
(A. A. PENA, ATTORNEY-IN-FACT)
</TABLE>
62
<PAGE> 70
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/ A. A. PENA
--------------------------------------
(A. A. PENA, VICE PRESIDENT, TREASURER
AND CHIEF FINANCIAL OFFICER)
Date: March 19, 1999
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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
(I) PRINCIPAL EXECUTIVE OFFICER:
*E. LINN DRAPER, JR. Chairman of the Board,
Chief Executive Officer
and Director
(II) PRINCIPAL FINANCIAL OFFICER:
/s/ A. A. PENA Vice President, Treasurer, March 19, 1999
- --------------------------------------- Chief Financial Officer
(A. A. PENA) and Director
(III) PRINCIPAL ACCOUNTING OFFICER:
/s/ L. V. ASSANTE Controller and March 19, 1999
- --------------------------------------- Chief Accounting Officer
(L. V. ASSANTE)
(IV) A MAJORITY OF THE DIRECTORS:
*HENRY W. FAYNE
*WM. J. LHOTA
*JAMES J. MARKOWSKY
*J. H. VIPPERMAN
*By: /s/ A. A. PENA. March 19, 1999
----------------------------------
(A. A. PENA, ATTORNEY-IN-FACT)
</TABLE>
63
<PAGE> 71
<TABLE>
<CAPTION>
INDEX TO FINANCIAL STATEMENT SCHEDULES
Page
----
<S> <C>
INDEPENDENT AUDITORS' REPORT .......................................................... S-2
The following financial statement schedules for the years ended December 31,
1998, 1997 and 1996 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
</TABLE>
S-1
<PAGE> 72
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, 1998 and 1997,
and for each of the three years in the period ended December 31, 1998, and have
issued our reports thereon dated February 23, 1999; such financial statements
and reports are included in your respective 1998 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 23, 1999
S-2
<PAGE> 73
<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 AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS 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, 1998....... $6,760 $23,646 $8,290(a) $27,621(b) $11,075
====== ======= ====== ======= =======
Year Ended December 31, 1997....... $3,692 $20,650 $8,953(a) $26,535(b) $ 6,760
====== ======= ====== ======= =======
Year Ended December 31, 1996....... $5,430 $16,382 $7,224(a) $25,344(b) $ 3,692
====== ======= ====== ======= =======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
<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 AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS 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, 1998....... $1,333 $5,093 $1,306(a) $5,498(b) $2,234
====== ====== ====== ====== ======
Year Ended December 31, 1997....... $ 687 $3,621 $ 666(a) $3,641(b) $1,333
===== ====== ======= ====== ======
Year Ended December 31, 1996....... $2,253 $1,748 $ 779(a) $4,093(b) $ 687
====== ====== ======= ====== ======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
<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 AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
===========================================================================================================================
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>D
EDUCTED FROM ASSETS:
Accumulated Provision for
Uncollectible Accounts:
Year Ended December 31, 1998....... $1,058 $7,551 $5,278(a) $11,289(b) $2,598
====== ====== ====== ======= ======
Year Ended December 31, 1997....... $1,032 $6,815 $6,380(a) $13,169(b) $1,058
====== ====== ====== ======= ======
Year Ended December 31, 1996....... $1,061 $7,720 $3,978(a) $11,727(b) $1,032
====== ====== ====== ======= ======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
===========================================================================================================================
</TABLE>
S-3
<PAGE> 74
<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 AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS 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, 1998......... $1,188 $4,630 $221(a) $4,012(b) $2,027
====== ====== ==== ====== ======
Year Ended December 31, 1997......... $ 156 $4,411 $798(a) $4,177(b) $1,188
====== ====== ==== ====== ======
Year Ended December 31, 1996......... $ 334 $2,208 $791(a) $3,177(b) $ 156
====== ====== ==== ====== ======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
==========================================================================================================================
<CAPTION>
==========================================================================================================================
KENTUCKY POWER COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- ---------------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ---------------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS 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, 1998......... $525 $1,280 $392(a) $1,349(b) $848
==== ====== ==== ====== ====
Year Ended December 31, 1997......... $272 $1,482 $347(a) $1,576(b) $525
==== ====== ==== ====== ====
Year Ended December 31, 1996......... $259 $1,507 $311(a) $1,805(b) $272
==== ====== ==== ====== ====
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
==========================================================================================================================
<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 AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS 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, 1998......... $2,501 $3,255 $941(a) $5,019(b) $1,678
====== ====== ==== ====== ======
Year Ended December 31, 1997......... $1,433 $4,008 $675(a) $3,615(b) $2,501
====== ====== ==== ====== ======
Year Ended December 31, 1996......... $1,424 $2,874 $532(a) $3,397(b) $1,433
====== ====== ==== ====== ======
- ---------------------
(a) Recoveries on accounts previously written off.
(b) Uncollectible accounts written off.
==========================================================================================================================
</TABLE>
S-4
<PAGE> 75
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. 229.10(d) and 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
(+), 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.
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
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 1998 Annual Report (for the fiscal year ended December
31, 1998) which are incorporated by reference in this filing.
*24 -- Power of Attorney
*27 -- Financial Data Schedules
AEP**
3(a) -- Copy of Restated Certificate of Incorporation of AEP, dated October 29, 1997 [Quarterly
Report on Form 10-Q of AEP for the quarter ended September 30, 1997, File No. 1-3525,
Exhibit 3(a)].
* 3(b) -- Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP, dated
January 13, 1999.
* 3(c) -- Composite copy of the Restated Certificate of Incorporation of AEP, as amended.
3(d) -- Copy of By-Laws of AEP, as amended through January 28, 1998 [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 3(b)].
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)].
</TABLE>
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<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
AEP**(continued)
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 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(d) -- 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(e) -- 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(f) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
1-3525, Exhibit 10(f)].
+10(g)(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)].
+10(g)(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)].
+10(h) -- 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)].
+10(i)(1) -- AEP Deferred Compensation and Stock Plan for Non-Employee Directors [Annual Report on Form
10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(f)(1)
+10(i)(2) -- AEP Stock Unit Accumulation Plan for Non-Employee Directors [Annual Report on Form 10-K of
AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(f)(2)].
+10(j)(1)(A) -- AEP Excess Benefit Plan, as amended through August 25, 1997 [Quarterly Report on Form 10-Q
of AEP for the quarter ended September 30, 1997, File No. 1-3525, Exhibit 10].
+10(j)(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)].
+10(j)(2) -- AEP System Supplemental Savings Plan, as amended through November 15, 1995 (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)].
</TABLE>
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<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
AEP** (continued)
+10(j)(3) -- Service Corporation Umbrella Trust 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)].
+10(k) -- 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)].
+10(l)(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)].
+10(l)(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)].
+10(m) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of
AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10].
+*10(n) -- Letter agreement between AEP and Donald M. Clements, Jr. dated August 19, 1994.
+*10(o) -- AEP Senior Executive Severance Plan for Merger with Central and South West Corporation,
effective March 1, 1999.
*13 -- Copy of those portions of the AEP 1998 Annual Report (for the fiscal year ended December 31,
1998) 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**
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 [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File
No. 1-3457, Exhibit 3(c)].
3(d) -- Composite copy of the Restated Articles of Incorporation of APCo (amended as of March 7, 1997)
[Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No.
1-3457, Exhibit 3(d)].
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
</TABLE>
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<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
APCO** (continued)
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); Annual Report on Form 10-K of APCo for the fiscal year
ended December 31, 1996, File No. 1-3457, Exhibit 4(b); Annual Report on Form 10-K of APCo
for the fiscal year ended December 31, 1998, Exhibit 4(b)].
4(b) -- Indenture (for unsecured debt securities), dated as of January 1, 1998, between APCo and The
Bank of New York, As Trustee [Registration Statement No. 333-45927, Exhibits 4(a) and 4(b);
Registration Statement No. 333-49071, Exhibit 4(b)].
*4(c) -- Company Order and Officers' Certificate, dated April 22, 1998, establishing certain terms of
the 7.30% Senior Notes, Series B, due 2038.
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)].
</TABLE>
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<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
APCO** (continued)
10(e) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
1-3525, Exhibit 10(f)].
+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)].
+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)].
+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)].
+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)].
+10(h)(1) -- Excess Benefits Plan [Quarterly Report on Form 10-Q of AEP for the quarter ended September
30, 1997, File No. 1-3525, Exhibit 10].
+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)].
+10(h)(3) -- Umbrella Trust 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)].
+10(i) -- 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)].
+10(j) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of
AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10].
+10(k) -- AEP Senior Executive Severance Plan for Merger with Central and South West Corporation,
effective March 1, 1999 [Annual Report on Form 10-K of AEP for the fiscal year ended December
31, 1998, File No. 1-3525, Exhibit 10(o)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the APCo 1998 Annual Report (for the fiscal year ended December 31,
1998) 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, 1998, File No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLp.
*24 -- Power of Attorney
*27 -- Financial Data Schedules.
CSPCO**
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)].
</TABLE>
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<TABLE>
<CAPTION>
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- -------------- -----------
<S> <C> <C>
CSPCO** (continued)
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)]
4(b) -- Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between
CSPCo and Bankers Trust Company, as Trustee [Registration Statement No. 333-54025, Exhibits
4(a), 4(b), 4(c) and 4(d)].
*4(c) -- Copy of Company Order and Officers' Certificate, dated June 18, 1998, establishing certain
terms of the Unsecured Medium Term Notes, Series B.
*4(d) -- Copy of Instructions, dated June 18, 1998, from CSPCo to Bankers Trust Company, establishing
certain terms of the 6.55% Unsecured Medium Term Notes, Series B, due 2008.
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)].
</TABLE>
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<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
CSPCO** (continued)
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) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
1-3525, Exhibit 10(f)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the CSPCo 1998 Annual Report (for the fiscal year ended December 31,
1998) which are incorporated by reference in this filing.
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney
*27 -- Financial Data Schedules.
I&M**
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 [Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1996, File No.
1-3570, Exhibit 3(b)].
3(c) -- Composite Copy of the Amended Articles of Acceptance of I&M (amended as of March 7, 1997)
[Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1996, File No. 1-3570,
Exhibit 3(c)].
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); Annual Report on Form 10-K of I&M for
fiscal year ended December 31, 1996, File No. 1-3570, Exhibit 4(b)].
* 4(b) -- Copy of indenture (for unsecured debt securities), dated as of October 1, 1998, between I&M
and The Bank of New York, as Trustee.
* 4(c) -- Copy of Company Order and Officers' Certificate, dated October 29, 1998, establishing certain
terms of the Unsecured Medium Term Notes, Series A.
</TABLE>
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<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
I&M** (continued)
* 4(d) -- Copy of Instructions, dated November 4, 1998, from I&M to The Bank of New York, establishing
certain terms of the 6.45% Unsecured Medium Term Notes, Series A, due 2008.
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(a)(4) -- 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)(5) -- 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, 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 1, 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
</TABLE>
E-8
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<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
I&M** (continued)
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(g) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
1-3525, Exhibit 10(f)].
*12 -- Statement re: Computation of Ratios
*13 -- Copy of those portions of the I&M 1998 Annual Report (for the fiscal year ended December 31,
1998) 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, 1998, File No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney
*27 -- Financial Data Schedules.
KEPCO**
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)].
4(b) -- Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between
KEPCo and Bankers Trust Company, as Trustee [Annual Report on Form 10-K of KEPCo for the
fiscal year ended December 31, 1997, Exhibits 4(b), 4(c) and 4(d)].
*4(c) -- Copy of Instructions, dated November 4, 1998, from KEPCo to Bankers Trust Company,
establishing certain terms of the 6.45% Unsecured Medium Term Notes, Series A, due 2008.
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)].
</TABLE>
E-9
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<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
KEPCO** (continued)
10(d) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
1-3525, Exhibit 10(f)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy those portions of the KEPCo 1998 Annual Report (for the fiscal year ended December 31,
1998) which are incorporated by reference in this filing.
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney
*27 -- Financial Data Schedules
OPCO**
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 [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1996, File
No. 1-6543, Exhibit 3(c)].
3(d) -- Composite copy of the Amended Articles of Incorporation of OPCo (amended as of March 7, 1997)
[Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1996, File No.
1-6543, Exhibit 3(d)].
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)(iv); 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)].
4(b) -- Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between OPCo
and Bankers Trust Company, as Trustee [Registration Statement No. 333-49595, Exhibits 4(a),
4(b) and 4(c)].
*4(c) -- Copy of Instructions, dated December 1, 1998, from OPCo to Bankers Trust Company, establishing
certain terms of the 6.24% Unsecured Medium Term Notes, Series A, due 2008.
*4(d) -- Copy of Company Order and Officers' Certificate, dated April 29, 1998, establishing certain
terms of the 7 3/8% Senior Notes, Series A, due 2038.
</TABLE>
E-10
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<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
OPCO** (continued)
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, 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); 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)].
10(f) -- 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(g) -- Agreement and Plan of Merger, dated as of December 21, 1997, by and among American Electric
Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
1-3525, Exhibit 10(f)].
+10(h)(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)].
+10(h)(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)].
</TABLE>
E-11
<PAGE> 86
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
<S> <C> <C>
OPCO** (continued)
+10(i)(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)].
+10(i)(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)].
+10(j)(1) -- Excess Benefits Plan [Quarterly Report on Form 10-Q of AEP for the quarter ended September
30, 1997, File No. 1-3525, Exhibit 10].
+10(j)(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)].
+10(j)(3) -- Umbrella Trust 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)].
+10(k) -- 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)].
+10(l) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of
AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10].
+10(m) -- AEP Senior Executive Severance Plan for Merger with Central and South West Corporation,
effective March 1, 1999 [Annual Report on Form 10-K of AEP for the fiscal year ended December
31, 1998, File No. 1-3525, Exhibit 10(o)].
*12 -- Statement re: Computation of Ratios.
*13 -- Copy of those portions of the OPCo 1998 Annual Report (for the fiscal year ended December 31,
1998) 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, 1998, File No. 1-3525, Exhibit 21].
*23 -- Consent of Deloitte & Touche LLP.
*24 -- Power of Attorney.
*27 -- Financial Data Schedules.
</TABLE>
-------------------------------------
** 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.
E-12
<PAGE>
Exhibit 3(b)
CERTIFICATE OF AMENDMENT
OF THE
CERTIFICATE OF INCORPORATION
OF
AMERICAN ELECTRIC POWER COMPANY, INC.
Under Section 805 of the Business Corporation Law
The undersigned, being respectively the Vice President and
Secretary of American Electric Power Company, Inc., hereby
certify that:
1. The name of the corporation is AMERICAN ELECTRIC POWER COMPANY, INC.
The name under which the corporation was formed is American Gas and Electric
Company.
2. The Department of State on February 18, 1925 filed the certificate of
consolidation forming the corporation.
3.(A) The certificate of incorporation of the corporation, as heretofore
amended, is hereby amended pursuant to section 801(b)(7) of the Business
Corporation Law, to effect an increase in the aggregate number of shares which
the corporation shall have authority to issue from 300,000,000 shares of Common
Stock, of the par value of $6.50 each, to 600,000,000 shares of Common Stock, of
the par value of $6.50 each.
(B) Paragraph 4.1 of the certificate of incorporation of the corporation,
as heretofore amended, is hereby amended to read as follows:
4.1 The aggregate number of shares which the corporation is
authorized to issue is 600,000,000 shares of Common Stock, of the par
value of $6.50 each.
4. The manner in which this amendment to the certificate of incorporation
of the corporation, as heretofore amended, was authorized was by the (i)
unanimous affirmative vote of the Board of Directors of the corporation at its
meeting duly called and held on the 28th day of January, 1998, a quorum being
present, and (ii) affirmative vote of the holders of a majority of all
outstanding shares entitled to vote thereon at the annual meeting of
shareholders of the corporation duly called and held on the 27th day of May,
1998, a quorum being present.
IN WITNESS WHEREOF, the undersigned have signed this certificate this 13th
day of January, 1999, and do affirm the contents to be true under the penalties
of perjury.
/S/ HENRY W. FAYNE
Henry W. Fayne, Vice President
/S/ SUSAN TOMASKY
Susan Tomasky, Secretary
<PAGE>
Exhibit 3(c)
RESTATED CERTIFICATE OF INCORPORATION
OF
AMERICAN ELECTRIC POWER COMPANY, INC.
Under Section 807 of the Business Corporation Law
As filed with the Department of State
of the State of New York
on November 5, 1997
RESTATED CERTIFICATE OF INCORPORATION
OF
AMERICAN ELECTRIC POWER COMPANY, INC.
Under Section 807 of the Business Corporation Law
The undersigned, being respectively the Vice President and Assistant
Secretary of American Electric Power Company, Inc., hereby certify that:
I. Name. The name of the corporation is AMERICAN ELECTRIC POWER COMPANY,
INC. The name under which the corporation was formed is American Gas and
Electric Company.
II. Date of Filing of Certificate of Incorporation. The certificate of
consolidation forming the corporation was filed by the Department of State on
February 18, 1925.
III. Original Certificate Superseded. The certificate of incorporation, as
amended heretofore, is hereby restated without further amendment or
change to read as herein set forth in full:
1. The name of the corporation shall be AMERICAN ELECTRIC POWER COMPANY,
INC.
2. The purposes for which the corporation is formed are:
(a) To acquire, hold and dispose of the stock, bonds, notes, debentures and
other securities and obligations (hereinafter called "securities") of any
person, firm, association, or corporation, private, public or municipal, or of
any body politic, including, without limitation, securities of electric and gas
utility companies; and while the owner of such securities, to possess and
exercise in respect thereof all the rights, powers and privileges of ownership
thereof, including voting power;
(b) To aid in any manner permitted by law any person, firm, association or
corporation in whose securities the corporation may be interested, directly or
indirectly, and to do any other act or thing permitted by law for the
preservation, protection, improvement or enhancement of the value of such
securities or the property represented thereby or securing the same or owned,
held or possessed by such person, firm, association or corporation;
(c) To acquire, construct, own, maintain, operate and dispose of real or
personal property used or useful in the business of an electric utility company
or gas utility company and such other real or personal property as may be
permitted by law; and
(d) To do everything necessary, proper, advisable or convenient for the
accomplishment of the foregoing purposes, and to do all other things incidental
to them or connected with them that are not forbidden by law or by this
certificate of incorporation.
3. The city and county in which the office of the corporation is to be
located are the City and County of New York.
4.1. The aggregate number of shares which the corporation is authorized to
issue is 600,000,000 shares of Common Stock of the par value of $6.50 each.
4.2. Each share of the Common Stock shall be equal in all respects to every
other share of the Common Stock. Every holder of record 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; provided, however, that at all
elections of directors by stockholders each holder of record of shares of the
Common Stock then entitled to vote, shall be entitled to as many votes as shall
equal the number of votes which (except for this provision as to cumulative
voting) he would be entitled to cast for the election of directors with respect
to his shares of Common Stock multiplied by the number of directors to be
elected, and such holder may cast all of such votes for a single director or may
distribute them among the number of directors to be voted for, or any two or
more or them, as he may see fit, which right, when exercised, shall be termed
cumulative voting.
4.3. The corporation may, at any time and from time to time, issue and
dispose of any of the authorized and unissued shares of the Common Stock for
such consideration as may be fixed by the Board of Directors, subject to any
provisions of law then applicable, and subject to the provisions of any
resolutions of the stockholders of the corporation relating to the issue and
disposition of such shares.
4.4. Upon any issuance for money or other consideration of any stock of the
corporation, or of any securities convertible into any stock of the corporation,
of any class whatsoever which may be authorized from time to time, no holder of
stock of any kind shall have any preemptive or other right to subscribe for,
purchase or receive any proportionate or other share of the stock or securities
so issued, but the Board of Directors may dispose of all or any portion of such
stock or securities as and when it may determine free of any such rights,
whether by offering the same to stockholders or by sale or other disposition as
the Board of Directors may deem advisable; provided, however, that if the Board
of Directors shall determine to issue and sell any shares of Common Stock
(including, for the purposes of this paragraph, any security convertible into
Common Stock, but excluding shares of Common Stock and securities convertible
into Common Stock theretofore reacquired by the corporation after having been
duly issued, and excluding shares of Common Stock and securities convertible
into Common Stock issued to satisfy conversion or option rights theretofore
granted by the corporation) solely for money and other than by:
(i) a public offering thereof, or
(ii) an offering thereof to or through underwriters or dealers who shall
agree promptly to make a public offering thereof, or
(iii) any other offering thereof which shall have been authorized or
approved by the affirmative vote, cast in person or by proxy, of the holders of
record of a majority of the outstanding shares of Common Stock entitled to vote
at the stockholders' meeting at which action shall have been taken with respect
to such other offering,
such shares of Common Stock shall first be offered pro rata, except that the
corporation shall not be obligated to offer or to issue any fractional interest
in a full share of Common Stock, to the holders of record of the then
outstanding shares of Common Stock (excluding outstanding shares of Common Stock
held for the benefit of holders of scrip certificates or other instruments
representing fractional interests in a full share of Common Stock) upon terms
which, in the judgment of the Board of Directors of the corporation, shall be
not less favorable (without deduction of such reasonable compensation for the
sale, underwriting or purchase of such shares by underwriters or dealers as may
lawfully be paid by the corporation) to the purchaser than the terms upon which
such shares are offered to others than such holders of Common Stock; and
provided that the time within which such preemptive rights shall be exercised
may be limited to such time as to the Board of Directors may seem proper, not
less, however, than fourteen (14) days after the mailing of notice that such
preemptive rights are available and may be exercised.
5. Directors shall hold office after the expiration of their terms until
their successors are elected and have qualified. Directors need not be
stockholders.
6. To the fullest extent permitted by the New York Business Corporation Law
as it exists on the date hereof or as it may hereafter be amended, no director
of the corporation shall be liable to the corporation or its stockholders for
damages for any breach of duty as a director. Any repeal or modification of the
foregoing sentence by the stockholders of the corporation shall not adversely
affect any right or protection of a director of the corporation existing at the
time of such repeal or modification.
7.1.(A) In addition to any affirmative vote required by law or this
certificate of incorporation (any other provision of this certificate of
incorporation notwithstanding), and except as otherwise expressly provided in
paragraph 7.2:
(1) any merger or consolidation of the corporation or any Subsidiary (as
hereinafter defined) with (i) any Interested Stockholder (as hereinafter
defined) or (ii) any other corporation (whether or not itself an Interested
Stockholder) which is, or after such merger or consolidation would be, an
Affiliate (as hereinafter defined) of an Interested Stockholder; or
(2) any sale, lease, license, exchange, mortgage, pledge, transfer or other
disposition (in one transaction or a series of transactions) to or with any
Interested Stockholder or any Affiliate of any Interested Stockholder of any
assets of the corporation or any Subsidiary having an aggregate Fair Market
Value (as hereinafter defined) of $100,000,000 or more; or
(3) the issuance or transfer by the corporation or any Subsidiary (in one
transaction or a series of transactions) of any securities of the corporation or
any Subsidiary to any Interested Stockholder or any Affiliate of any Interested
Stockholder having an aggregate Fair Market Value of $100,000,000 or more, other
than the issuance of securities upon the conversion of convertible securities of
the corporation or any Subsidiary which were not acquired by such Interested
Stockholder (or such Affiliate) from the corporation or a Subsidiary; or
(4) the adoption of any plan or proposal for the liquidation or dissolution
of the corporation proposed by or on behalf of any Interested Stockholder or any
Affiliate of any Interested Stockholder; or
(5) any reclassification of securities (including any reverse stock split),
or recapitalization or reorganization of the corporation, or any merger or
consolidation of the corporation with any of its Subsidiaries, or any self
tender offer for or repurchase of securities of the corporation by the
corporation or any Subsidiary or any other transaction (whether of not with or
into or otherwise involving any Interested Stockholder) which has the effect,
directly or indirectly, of increasing the proportionate share of the outstanding
shares of any class or series of equity or convertible securities of the
corporation or any Subsidiary which is directly or indirectly owned by any
Interested Stockholder or any Affiliate of any Interested Stockholder;
shall require the affirmative vote of the holders of at least (i) seventy-five
per centum of the combined voting power of the then issued and outstanding
capital stock of all classes and series of the corporation having voting powers
(the "Voting Stock"), voting together as a single class, and (ii) a majority of
the combined voting power of the then issued and outstanding Voting Stock
beneficially owned by persons other than such Interested Stockholder, voting
together as a single class, given at any annual meeting of stockholders or at
any special meeting called for that purpose. Such affirmative vote shall be
required notwithstanding the fact that no vote may be required, or that a lesser
percentage may be specified, by law, by any other provision of this certificate
of incorporation or in any agreement with any national securities exchange or
otherwise.
(B) The term "Business Combination" as used herein shall mean any
transaction which is referred to in any one or more of clauses (1) through (5)
of sub-paragraph (A) of this paragraph 7.1.
7.2. The provisions of paragraph 7.1 shall not be applicable to any
particular Business Combination, and such Business Combination shall require
only such affirmative vote, if any, as is required by law, any other provision
of this certificate of incorporation, and any agreement with any national
securities exchange, if all of the conditions specified in either of the
following sub-paragraphs (A) or (B) are met:
(A) The Business Combination shall have been approved by a
majority of the Disinterested Directors (as hereinafter defined).
(B) All of the following conditions shall have been met:
(1) The aggregate amount of the cash and the Fair Market
Value as of the date of the consummation of the Business Combination (the
"Consummation Date") of consideration other than cash to be received per share
by holders of Common Stock in such Business Combination shall be at least equal
to the highest of the following (it being intended that the requirements of this
clause (1) shall be required to be met with respect to every share of
outstanding Common Stock, whether or not the Interested Stockholder has
previously acquired any shares of Common Stock):
(i) (if applicable) the highest per share price (including any brokerage
commissions, transfer taxes and soliciting dealers' fees) paid by the Interested
Stockholder for any shares of Common Stock acquired by it (x) within the
five-year period immediately prior to the first public announcement of the terms
of the proposed Business Combination (the "Announcement Date") or (y) in the
transaction in which it became an Interested Stockholder, whichever is higher;
(ii) the Fair Market Value per share of Common Stock on the Announcement
Date or on the date on which the Interested Stockholder became an Interested
Stockholder (such latter date is referred to herein as the "Determination
Date"), whichever is higher; and
(iii) an amount which bears the same or greater percentage relationship to
the Fair Market Value per share of Common Stock on the Announcement Date as the
highest per share price determined in clause (B)(1)(i) above bears to the Fair
Market Value per share of Common Stock on the date of the commencement of the
acquisition of the Common Stock by such Interested Stockholder
(2) The aggregate amount of cash and the Fair Market Value as
of the Consummation Date Of consideration other than cash to be
received per share by holders of shares of any other class or series of
outstanding Voting Stock shall be at least equal to the highest of the following
(it being intended that the requirements of this clause (2) shall be required to
be met with respect to every class or series of outstanding Voting Stock,
whether or not the Interested Stockholder has previously acquired any shares of
a particular class or series of Voting Stock):
(i) (if applicable) the highest per share price
(including any brokerage commissions, transfer taxes and soliciting
dealers' fees) paid by the Interested Stockholder for any shares of such class
or series of Voting Stock acquired by it (x) within the five-year period
immediately prior to the Announcement Date or (y) in the transaction in which it
became an Interested Stockholder, whichever is higher;
(ii) the Fair Market Value per share of such class or
series of Voting Stock on the Announcement Date or on the Determination Date,
whichever is higher;
(iii) (if applicable) the highest preferential amount
per share to which the holders of shares of such class or series of Voting
Stock are entitled in the event of any liquidation, dissolution or winding up of
the corporation, whether voluntary or involuntary; and
(iv) an amount which bears the same or greater
percentage relationship to the Fair Market Value per share of such class or
series of Voting Stock on the Announcement Date as the highest per share price
determined in clause (B)(2)(i) above bears to the Fair Market Value per share of
such Voting Stock on the date of the commencement of the acquisition of such
Voting Stock by such Interested Stockholder.
(3) The consideration to be received by holders of a
particular class or series of outstanding Voting Stock (including Common Stock)
shall be in cash or in the same form as the Interested Stockholder has
previously paid for shares of such class or series of Voting Stock. If the
Interested Stockholder has paid for shares of any class or series of Voting
Stock with varying forms of consideration, the form of consideration to be
received by each holder of such class or series of Voting Stock shall be, at the
option of such holder, either cash or the form used by the Interested
Stockholder to acquire the largest number of shares of such class or series of
Voting Stock previously acquired by it prior to the Announcement Date. The price
determined in accordance with clauses (1) and (2) of this sub-paragraph (B)
shall be subject to appropriate adjustment in the event of any stock dividend,
stock split, combination of shares or similar event.
(4) After the Determination Date and prior to the Consummation
Date:
(i) except as approved by a majority of the Disinterested
Directors, there shall have been no failure to declare and
pay at the regular dates therefor the full amount of any dividends (whether or
not cumulative) payable on any class or series of stock of the corporation
having a preference over the Common Stock as to dividends or upon liquidation;
and
(ii) there shall have been (x) no reduction in the quarterly
rate of dividends paid on the Common Stock (except as necessary
to reflect any subdivision of the Common Stock), except as approved by a
majority of the Disinterested Directors, and (y) an increase in such quarterly
rate of dividends paid on such Common Stock as necessary to reflect any
reclassification (including any reverse stock split), recapitalization,
reorganization, self tender offer for or repurchase of securities of the
corporation by the corporation or any Subsidiary or any similar transaction
which has the effect of reducing the number of outstanding shares of the Common
Stock, unless the failure so to increase such quarterly rate is approved by a
majority of the Disinterested Directors; and
(iii) such Interested Stockholder shall not have become the
beneficial owner of any additional shares of Voting Stock except as part of
the transaction which results in such Interested Stockholder becoming an
Interested Stockholder or upon conversion of convertible securities acquired by
it prior to becoming an Interested Stockholder or as a result of a pro rata
stock dividend or stock split; and
(iv) such Interested Stockholder shall not have received the
benefit, directly or indirectly (except proportionately as a
stockholder), of any loans, advances, guarantees, pledges or other financial
assistance or tax credits or other tax advantages provided by the corporation or
any Subsidiary, whether in anticipation of or in connection with such Business
Combination or otherwise; and
(v) such Interested Stockholder shall not have caused any
material change in the corporation's business or capital structure,
including, without limitation, the issuance of shares of capital stock of the
corporation to any third party.
(5) A proxy or information statement describing the proposed
Business Combination and complying with the requirements of the Securities
Exchange Act of 1934, as amended (the "Act"), and the rules and regulations
thereunder (or any subsequent provisions replacing the Act, rules and
regulations), shall be mailed by and at the expense of the Interested
Stockholder to public stockholders of the corporation at least 30 days prior to
the Consummation Date (whether or not such proxy or information statement is
required to be mailed pursuant to the Act). The proxy or information statement
shall contain at the front thereof in a prominent place (i) any recommendation
as to the advisability (or inadvisability) of the Business Combination which a
majority of the Disinterested Directors may choose to state, and (ii) if a
majority of the Disinterested Directors so requests, the opinion of a reputable
national investment banking firm as to the fairness (or not) of such Business
Combination from the point of view of the remaining public stockholders of the
corporation (such investment banking firm to be engaged solely on behalf of the
remaining public stockholders, to be paid a reasonable fee for their services by
the corporation upon receipt of such opinion, to be unaffiliated with such
Interested Stockholder, and, to be selected by a majority of the Disinterested
Directors).
(6) The holders of all outstanding shares of Voting Stock not
beneficially owned by the Interested Stockholder prior to the consummation of
any Business Combination shall be entitled to receive in such Business
Combination cash or other consideration for their shares of such Voting Stock in
compliance with clauses (1), (2) and (3) of sub-paragraph (B) of this paragraph
7.2 (provided, however, that the failure of any such holders who are exercising
their statutory rights to dissent from such Business Combination and receive
payment of the fair value of their shares to exchange their shares in such
Business Combination shall not be deemed to have prevented the condition set
forth in this clause (6) from being satisfied).
7.3. The following terms shall be deemed to have the meanings
specified below:
(A) The term "person" shall mean any individual, firm,
corporation, group (as such term is used in Regulation 13D-G of the rules and
regulations under the Act, as in effect on January 1, 1988) or other entity.
(B) The term "Interested Stockholder" shall mean any person
(other than the corporation, any Subsidiary or any pension, profit sharing,
employee stock ownership, employee savings or other employee benefit plan, or
any dividend reinvestment plan, of the corporation or any Subsidiary or any
trustee of or fiduciary with respect to any such plan acting in such capacity)
who or which:
(1) is the beneficial owner, directly or indirectly, of
more than five per centum of the combined voting power of the then outstanding
Voting Stock; or
(2) is an Affiliate of the corporation and at any time
within the five-year period immediately prior to the date in question was the
beneficial owner, directly or indirectly, of more than five per centum of the
combined voting power of the then outstanding Voting Stock; or
(3) is an assignee of or has otherwise succeeded to any
shares of Voting Stock which were at any time within the five-year period
immediately prior to the date in question beneficially owned by an Interested
Stockholder, if such assignment or succession shall have occurred in the course
of a transaction or series of transactions not involving a public offering
within the meaning of the Securities Act of 1933, as amended (or any subsequent
provisions replacing such).
(C) A person shall be deemed a "beneficial owner" of any Voting
Stock:
(1) which such person or any of its
Affiliates or Associates (as hereinafter defined) beneficially owns, directly or
indirectly; or
(2) which such person or any of its
Affiliates or Associates has (i) the right to acquire (whether such right is
exercisable immediately or only after the passage of time), pursuant to any
agreement, arrangement or understanding or upon the exercise of conversion
rights, exchange rights, warrants or options, or otherwise, or (ii) the right to
vote pursuant to any agreement, arrangement or understanding; or
(3) which is beneficially owned, directly
or indirectly, by any other person with which such person or any of its
Affiliates or Associates has any agreement, arrangement or understanding for the
purpose of acquiring, holding, voting or disposing of any shares of Voting
Stock.
(D) For the purpose of determining whether a person is an
Interested Stockholder pursuant to sub-paragraph (B) of this paragraph 7.3, the
number of shares of Voting Stock deemed to be outstanding shall include shares
deemed owned through application of sub-paragraph (C) of this paragraph 7.3, but
shall not include any other shares of Voting Stock which may be issuable
pursuant to any agreement, arrangement or understanding, or upon exercise of
conversion rights, exchange rights, warrants or options, or otherwise.
(E) The term "Affiliate" of, or a person "affiliated" with, a
specified person shall mean a person that directly, or indirectly
through one or more intermediaries, controls, or is controlled by, or is under
common control with, the person specified.
(F) The term "Associate" as used to indicate a relationship
with any person shall mean (1) any corporation or organization (other than the
corporation or a Subsidiary) of which such person is an officer or partner or
is, directly or indirectly, the beneficial owner of ten per centum or more of
any class or series of equity securities, (2) any trust or other estate in which
such person has a substantial beneficial interest or as to which such person
serves as trustee or in a similar fiduciary capacity, and (3) any relative or
spouse of such person, or any relative of such spouse, who has the same home as
such person.
(G) The term "Subsidiary" shall mean any corporation of which
a majority of any class or series of equity security is owned, directly or
indirectly, by the corporation or by a Subsidiary or by the corporation and one
or more Subsidiaries; provided, however, that for the purposes of the definition
of Interested Stockholder set forth in sub-paragraph (B) of this paragraph 7.3,
the term "Subsidiary" shall mean only a corporation of which a majority of each
class or series of equity security is owned, directly or indirectly, by the
corporation.
(H) The term "Fair Market Value" shall mean: (1) in the case
of stock, the highest closing sale price during the 30-day period immediately
preceding the date in question of a share of such stock on the Composite Tape
for New York Stock Exchange-Listed Stocks, or, if such stock is not quoted on
the Composite Tape, on the New York Stock Exchange, or if such stock is not
listed on such Exchange, on the principal United States securities exchange
registered under the Act on which such stock is listed or, if such stock is not
listed on any such exchange, the highest closing bid quotation with respect to a
share of such stock during the 30-day period preceding the date in question on
the National Association of Securities Dealers, Inc. Automated Quotations System
or any similar system then in use, or if no such quotations are available, the
fair market value on the date in question of a share of such stock as determined
by a majority of the Disinterested Directors in good faith, in each case with
respect to any class or series of such stock, appropriately adjusted for any
dividend or distribution in shares of such stock or any subdivision or
reclassification of outstanding shares of such stock into a greater number of
shares of such stock or any combination or reclassification of outstanding
shares of such stock into a smaller number of shares of such stock; and (2) in
the case of property other than cash or stock, the fair market value of such
property on the date in question as determined by a majority of the
Disinterested Directors in good faith.
(I) In the event of any Business Combination in whic the
corporation is the survivor, the phrase "consideration other than cash to
be received" as used in clauses (1) and (2) of sub-paragraph (B) of paragraph
7.2 shall include the shares of Common Stock and/or the shares of any other
class or series of outstanding Voting Stock retained by the holders of such
shares.
(J) The term "Disinterested Director" shall mean any member
of the Board of Directors of the corporation who is unaffiliated with, and not a
nominee of, the Interested Stockholder and who was a member of the Board of
Directors prior to the Determination Date, and any successor of a Disinterested
Director who is unaffiliated with, and not a nominee of, the Interested
Stockholder and is recommended to succeed a Disinterested Director by a majority
of the total number of Disinterested Directors then on the Board of Directors.
(K) References to "highest per share price" shall in each
case with respect to any class or series of stock reflect an appropriate
adjustment for any dividend or distribution in shares of such stock or any
subdivision or reclassification of outstanding shares of such stock into a
greater number of shares of such stock or any combination or reclassification of
outstanding shares of such stock into a smaller number of shares of such stock.
7.4. A majority of the Board of Directors of the corporation shall
have the power and duty to determine for the purpose of these paragraphs 7.1
through 7.6, on the basis of information known to them after reasonable inquiry,
whether a person is an Interested Stockholder. Once the Board of Directors has
made a determination, pursuant to the preceding sentence, that a person is an
Interested Stockholder, a majority of the total number of directors of the
corporation who would qualify as Disinterested Directors shall have the power
and duty to interpret all of the terms and provisions of these paragraphs 7.1
through 7.6, and to determine on the basis of information known to them after
reasonable inquiry all facts necessary to ascertain compliance therewith,
including, without limitation, (A) the number of shares of Voting Stock
beneficially owned by any person, (B) whether a person is an Affiliate or
Associate of another, (C) whether the assets which are the subject of any
Business Combination have, or the consideration to be received for the issuance
or transfer of securities by the corporation or any Subsidiary in any Business
Combination has, an aggregate Fair Market Value of $100,000,000 or more and (D)
whether all of the applicable conditions set forth in sub-paragraph (B) of
paragraph 7.2 have been met with respect to any Business Combination. Any
determination pursuant to this paragraph 7.4 made in good faith shall be binding
and conclusive on all parties.
7.5. Nothing contained in these paragraphs 7.1 through 7.6 shall be
construed to relieve any Interested Stockholder from any fiduciary obligation
imposed by law.
7.6. Notwithstanding any other provisions of this certificate of
incorporation or the by-laws of the corporation (and notwithstanding the
fact that a lesser percentage may be specified by law, this certificate of
incorporation or the by-laws of the corporation), the affirmative vote of
the holders of at least (A) seventy-five per centum of the combined voting
power of the then issued and outstanding Voting Stock, voting together as
a single class, and (B) a majority of the combined voting power of the
then issued and outstanding Voting Stock beneficially owned by persons
other than an Interested Stockholder, voting together as a single class,
given at any annual meeting of stockholders or at any special meeting
called for that purpose, shall be required to amend, alter, change or
repeal, or adopt any provisions inconsistent with, these paragraphs 7.1
through 7.6; provided, however, that the foregoing provisions of this
paragraph 7.6 shall not apply to, and such vote shall not be required for,
any such amendment, alteration, change, repeal or adoption approved by a
majority of the disinterested Directors, and any such amendment,
alteration, change, repeal or adoption so approved shall require only such
vote, if any, as is required by law, any other provision of this
certificate of incorporation or the by-laws of the corporation.
8. The Secretary of State of the State of New York is hereby
designated as the agent of the corporation upon whom any process in any action
or proceeding against it may be served. The address to which the Secretary of
State shall mail a copy of any process against the corporation served upon him
is: c/o CT Corporation System, 1633 Broadway, New York, NY 10019.
9. The name of the registered agent upon whom and the address of th
registered agent at which process against the corporation may be served is:
c/o CT Corporation System, 1633 Broadway, New York, NY 10019.
IV. Manner of Authorization. The foregoing restatement of the
certificate of incorporation was authorized by the unanimous affirmative vote of
the Board of Directors of the corporation at its meeting duly called and held
on the 29th day of October, 1997, a quorum being present.
IN WITNESS WHEREOF, the undersigned have signed this certificate this 29th
day of October, 1997, and do affirm the contents to be true under the penalties
of perjury.
/S/ G. P. MALONEY
G. P. Maloney, Vice President
/S/ JOHN F. DI LORENZO, JR.
John F. Di Lorenzo, Jr., Assistant Secretary
<PAGE>
EXHIBIT 10(n)
Mr. Donald M. Clements, Jr.
6355 Wayside Drive
Beaumont, Texas 77707
August 19, 1994
Dear Don:
This is to confirm your acceptance of our offer of employment as Senior Vice
President, Corporate Development of the American Electric Power Service
Corporation, effective September 1, 1994 or as soon thereafter as you are able
to begin work. You will report to me in this position.
Among other duties that may be assigned, you will be responsible for exploring
and securing new business opportunities for the AEP System. This may include
possible alliances or combinations within the utility industry, non-traditional
arrangements with major customers, and the deployment of our extensive
engineering expertise in new ventures.
Your starting salary will be $170,000 a year and reviewed on an annual basis.
You will be entitled to 20 days of vacation annually beginning in 1995 and
assigned a company car for business and personal use. Subject to their specific
terms, including Board approval as necessary, you will be eligible for our
Management Incentive Compensation Plan (MICP) upon hire, and our Performance
Share Incentive Plan (PSIP) beginning January 1, 1995.
The MICP presently has an annual target award of 25% of base salary for your
position, 100% of which will be based on Corporate Performance under the Plan.
Actual awards may range from 0 to 150% of target and are paid as soon after
year-end results are confirmed. If you join the Company prior to October 1,
1994, you will receive a pro-rata award for 1994.
The PSIP for your position presently provides an annual award of 25% of your
base salary converted to AEP share units at market value. Those units are
subsequently multiplied from 0 to 200% to establish actual awards based on
comparative three year Total Shareholder Return. Dividends are credited during
the performance period and converted to equivalent performance share units.
PSIP payments are made annually at the end of each three year performance cycle
based on then share market value. The Board determines whether payment will be
in cash, AEP stock, or a combination of both. If in stock, the Board may
require its retention for an indefinite period. At the end of your first and
second calendar years of employment you will be eligible for transition
performance awards of one-third and two-thirds respectively, of the three-year
performance award that is made for that year.
As exceptions to our relocation expense reimbursement program, details of which
will be separately provided to you, we will provide you a furnished apartment
until May 1, 1995, pending relocation of your family when school is out next
spring. We will gross-up for the effect of income tax on this housing. We will
further provide you a $5,000 payment to cover miscellaneous relocation
expenses, also grossed-up for tax.
We will recognize all of your employment with Gulf States Utilities as if
credited service under the American Electric Power pension plan. Your pension
when you retire at any time after vesting will be based on your actual service
at retirement plus such credited service, as if you had been continuously
employed for the combined period. It will be paid in two parts that actually
earned through AEP service and the credited service supplement, offset by the
dollar amount of any retirement benefits you are entitled to receive from Gulf
States.
You will be eligible under their terms and conditions for all other benefit
programs and perquisites appropriate to your position and status as an employee
and officer of the AEP Service Corporation.
Our Human Resources Department will send you documents describing our benefit
plans and other appropriate informational material by separate cover. This will
include information regarding our relocation policy and relocation assistance.
They will also request certain information to expedite the employment process
and to comply with applicable law.
As this offer is contingent on your successful completion of a pre-employment
physical, they will advise you of the procedures to accomplish that as soon as
possible.
Don, we are very pleased that you will be joining the AEP System and I am
personally delighted at the opportunity to be working with you again.
Sincerely,
/s/E. Linn Draper, Jr.
E. Linn Draper, Jr.
<PAGE>
EXHIBIT 10(o)
AMERICAN ELECTRIC POWER SYSTEM
SENIOR EXECUTIVE SEVERANCE PLAN
FOR MERGER WITH
CENTRAL AND SOUTH WEST CORPORATION
Introduction
American Electric Power Company, Inc. ("AEP"), a New York corporation, and
Central and South West Corporation ("CSW"), a Delaware corporation, have entered
into an Agreement and Plan of Merger dated as of December 21, 1997 (the "Merger
Agreement"), whereby AEP and CSW will be parties to a merger (the "Combination")
with AEP as the parent of CSW. AEP recognizes that the uncertainty during the
pendency of the Combination, and the inevitable adjustments that will occur
during the transition period following the Combination, may result in the loss
or distraction of employees of its subsidiaries to the detriment of AEP and its
shareholders.
AEP considers the avoidance of such loss and distraction to be essential
to protecting and enhancing the best interests of AEP and its shareholders. AEP
also believes that during the pendency of the Combination and the transition
period thereafter, AEP should be able to receive and rely on dedicated service
from employees of its subsidiaries without concern that those employees might be
distracted or concerned by personal uncertainties and risks.
In addition, AEP believes that it is consistent with the employment
practices and policies of its subsidiaries and in the best interests of AEP and
its shareholders to treat fairly those employees whose employment terminates as
a result of the Combination.
Accordingly, AEP has determined that appropriate steps should be taken by
its subsidiaries to assure AEP of the continued employment and attention and
dedication to duty of the employees of its subsidiaries and to seek to ensure
the availability of their continued service, notwithstanding the Combination.
Therefore, in order to fulfill the above purposes, the following plan has
been developed and is hereby adopted by American Electric Power Service
Corporation, a subsidiary of AEP.
ARTICLE I
ESTABLISHMENT OF PLAN
As of March 1, 1999, American Electric Power Service Corporation hereby
establishes a separation compensation plan known as the American Electric Power
System Senior Executive Severance Plan For Merger With Central And South West
Corporation, as set forth in this document.
ARTICLE II
DEFINITIONS
As used herein the following words and phrases shall have the following
respective meanings unless the context clearly indicates otherwise.
(a) "Annual Compensation" means the sum of a Participant's
Annual Salary and the Participant's Target Annual Incentive.
(b) "Annual Salary" means the Participant's regular annual base salary
immediately prior to the Participant's termination of employment, including
compensation converted to other benefits under a flexible pay arrangement
maintained by the Corporation or deferred pursuant to a written plan or
agreement with the Corporation, but excluding overtime pay, allowances, premium
pay, compensation paid or payable under any of the Corporation's long-term or
short-term incentive plans or any similar payments.
(c) "Board" means the Board of Directors of American Electric Power
Company, Inc., a New York corporation.
(d) "Code" means the Internal Revenue Code of 1986, as amended from time
to time.
(e) "Corporation" means American Electric Power Service Corporation, a New
York corporation, and any of its subsidiary companies, divisions, organizations
or affiliates.
(f) "Date of Termination" means the date on which a Participant ceases to
be employed by the Corporation.
(g) "Effective Time" means the Effective Time, as defined in the Merger
Agreement.
(h) "Participant" means an individual who is designated as such pursuant
to Section 3.1.
(i) "Plan" means the American Electric Power System Senior Executive
Severance Plan For Merger With Central And South West Corporation.
(j) "Separation Benefits" means the benefits described in Section 4.3 that
are provided to qualifying Participants under the Plan.
(k) "Separation Period" means the period beginning on a Participant's Date
of Termination and ending on the earlier of (i) the third anniversary thereof,
or (ii) the first day of the month coincident with or next following the
Participant's 65th birthday.
(l) "Target Annual Incentive" means the award that the Participant would
have received under the Senior Officer Annual Incentive Compensation Plan or the
AEP Energy Services, Inc. Incentive Compensation Plan for the year in which the
Participant's Date of Termination occurs, if 100% of the annual target award had
been earned.
ARTICLE III
ELIGIBILITY
3.1 Participation. Each of the individuals named on Schedule 1 hereto
shall be a Participant in the Plan. With the approval of the Board, Schedule 1
may be amended by the Corporation from time to time to add individuals as
Participants; provided, however, the Corporation shall not have the right to
amend Schedule 1 to remove any individual, except that a Participant shall be
removed from Schedule 1 if the Participant's salary, duties or responsibilities
are materially altered for reasons other than the Combination, or the
Participant's employment is terminated for cause.
3.2 Duration of Participation. A Participant shall only cease to be a
Participant in the Plan as a result of an amendment or termination of the Plan
complying with Article VI of the Plan, or when the Participant ceases to be
employed by the Corporation, unless, at the time the Participant ceases to be
employed, such Participant is entitled to payment of a Separation Benefit as
provided in the Plan or there has been an event or occurrence described in
Section 4.2(a) which would enable the Participant to terminate employment and
receive a Separation Benefit. A Participant entitled to payment of a Separation
Benefit or any other amount under the Plan shall remain a Participant in the
Plan until the full amount of the Separation Benefit and any other amounts
payable under the Plan have been paid to the Participant.
ARTICLE IV
SEPARATION BENEFITS
4.1 Right to Separation Benefit. A Participant shall be entitled to
receive Separation Benefits in accordance with Section 4.3 if the Participant
ceases to be employed by the Corporation for any reason specified in Section
4.2(a).
4.2 Termination of Employment.
(a) Terminations Which Give Rise to Separation Benefits Under This Plan.
Except as set forth in subsection (b) below, a Participant shall be entitled to
Separation Benefits if at any time before the second anniversary of the
Effective Time (or, if the Combination has not occurred, before the expiration
of the Plan as set forth in Section 6.1 hereof):
(i) the Participant is involuntarily terminated by the
Corporation; or
(ii) the Participant's Annual Salary is reduced below the higher of
(x) the amount in effect on March 1, 1999 and (y) the highest amount in
effect at any time thereafter, excluding situations where the salary
reduction is due to the reassignment of a Participant returning to active
employment after a period of disability, and the Participant ceases to be
employed by the Corporation or by the Participant's own action within 90
days after the occurrence of such reduction; or
(iii) the Chief Executive Officer of the Corporation, in his or her
sole discretion, determines that the Participant's duties and
responsibilities or the program of incentive compensation and retirement
and welfare benefits offered to the Participant are materially and
adversely diminished in comparison to the duties and responsibilities or
the program of benefits enjoyed by the Participant on March 1, 1999, and
the Participant ceases to be employed by the Participant's own action
within 90 days after the occurrence after such reduction.
(b) Terminations Which Do Not Give Rise to Separation Benefits Under This
Plan. If a Participant's employment is terminated for cause, disability,
retirement, or voluntarily by the Participant in the absence of an event
described in subsection (a)(ii) or (iii) of this Section 4.2, the Participant
shall not be entitled to Separation Benefits under the Plan.
(i) A termination for disability shall have occurred where a
participant is terminated because illness or injury has prevented the
Participant from performing the Participant's duties (as they existed
immediately prior to the illness or injury) on a full time basis for 180
consecutive business days; provided, however, a termination for Disability
shall not have occurred if such termination is coincident with or
subsequent to a termination which otherwise gives rise to Separation
Benefits under this Plan as set forth in this Section 4.2.
(ii) A termination by retirement shall have occurred where a
Participant's termination is due to the Participant's voluntary late,
normal or early retirement under a pension plan sponsored by the
Corporation, as defined in such plan; provided, however, a termination by
Retirement shall not have occurred if such termination is coincident with
or subsequent to a termination which otherwise gives rise to Separation
Benefits under this Plan as set forth in this Section 4.2.
(iii) A termination for cause shall have occurred where a
Participant is terminated because of:
(A) the willful and continued failure of the Participant to perform
substantially the Participant's duties with the Corporation (other
than any such failure resulting from incapacity due to physical or
mental illness), after a written demand for substantial performance
is delivered to the Participant by the Board or an elected officer of
the Corporation which specifically identifies the manner in which the
Board or the elected officer believes that the Participant has not
substantially performed the Participant's duties, or
(B) the willful engaging by the Participant in illegal conduct or
gross misconduct which is materially and demonstrably injurious to
AEP and the Corporation, as determined by the Chief Executive Officer
of the Corporation.
For purposes of this provision, no act or failure to act, on the part of the
Participant, shall be considered "willful" unless it is done, or omitted to be
done, by the Participant in bad faith or without reasonable belief that the
Participant's action or omission was in the best interests of AEP or the
Corporation. Any act, or failure to act, based upon authority given pursuant to
a resolution duly adopted by the Board or upon the advice of counsel for AEP or
the Corporation, shall be conclusively presumed to be done, or omitted to be
done, by the Participant in good faith and in the best interests of AEP or the
Corporation.
4.3 Separation Benefits.
(a) If a Participant's employment is terminated in circumstances entitling
the Participant to a Separation Benefit as provided in Section 4.2(a), and
subject to the provisions of Section 4.5, the Corporation shall pay such
Participant, within ten days of the Date of Termination, a cash lump sum as set
forth in subsection (b) below and continuing benefits as set forth in subsection
(c) below. For purposes of determining the benefits set forth in subsections (b)
and (c), if the termination of the Participant's employment is based upon a
reduction of the Participant's Annual Salary or benefits as described in
subsection (a)(ii) or (a)(iii) of Section 4.2, such reduction shall be ignored.
(b) The cash lump sum referred to in Section 4.3(a) shall equal the
aggregate of the following amounts:
(i) an amount equal to the sum of (1) the portion of the
Participant's Annual Salary through the Date of Termination to the extent
not theretofore paid, (2) the product of (x) the Target Annual Incentive
and (y) a fraction, the numerator of which is the number of days in such
calendar year through the Date of Termination, and the denominator of
which is 365, and (3) any accrued vacation pay, in each case to the extent
not theretofore paid and in full satisfaction of the rights of the
Participant thereto; and
(ii) an amount equal to three times the Participant's Annual
Compensation.
(c) The continuing benefits referred to above shall be as follows:
(i) During the Separation Period, the Participant and the
Participant's family shall be provided with medical and dental insurance
benefits as if the Participant's employment had not been terminated;
provided, however, that if the Participant becomes reemployed with another
employer and is eligible to receive medical or other welfare benefits
under another employer-provided plan, the medical and other welfare
benefits described herein shall be secondary to those provided under such
other plan during such applicable period of eligibility. For purposes of
determining eligibility (but not the time of commencement of benefits) of
the Participant for retiree medical and dental insurance benefits under
the Corporation's plans, practices, programs and policies, the Participant
shall be considered to have remained employed during the Separation Period
and to have retired on the last day of such Separation Period; and
(ii) The Corporation shall, at its sole expense as incurred, provide
the Participant with outplacement services the scope and provider of which
shall be selected by the Participant in the Participant's sole discretion
(but at a cost to the Employer of not more than $30,000) or, at the
Participant's option, the use of comparable and accessible office space,
office supplies and equipment and secretarial services for a period not to
exceed one year.
To the extent any benefits described in this Section 4.3(c) cannot be provided
pursuant to the appropriate plan or program maintained by the Corporation, the
Corporation shall provide such benefits outside such plan or program at no
additional cost (including without limitation tax cost) to the Participant.
4.4 Other Benefits Payable.
(a) The cash lump sum and continuing benefits described in Section 4.3
above shall be payable in addition to, and not in lieu of, all other accrued or
vested or earned but deferred compensation (including voluntary deferrals of
regular salary and deferrals of long-term or short-term incentive compensation),
rights, options or other benefits which may be owed to a Participant upon or
following termination, including but not limited to sick pay, amounts or
benefits payable under any bonus or other compensation plans, stock option plan,
stock ownership plan, stock purchase plan, life insurance plan, health plan,
disability plan or similar or successor plan but excluding any severance pay or
pay in lieu of notice required to be paid to such Participant under applicable
law.
(b) Notwithstanding the foregoing;
(i) The Severance payments and benefits provided under Section 4.3
hereof shall be subject to, and conditioned upon, the waiver of any other
cash severance payment provided by the Corporation. No amount shall be
payable under this Plan to, or on behalf of the Participant, if the
Participant elects benefits under any other cash severance plan or
program, or any other special pay arrangement with respect to the
termination of the Participant's employment.
(ii) The Participant agrees that at all times following termination,
the Participant will not, without the prior written consent of AEP or the
Corporation, disclose to any person, firm or corporation any confidential
information of AEP or the Corporation which is now known to the
Participant or which hereafter may become known to the Participant as a
result of the Participant's employment or association with AEP or the
Corporation and which could be helpful to a competitor, unless such
disclosure is required under the terms of a valid and effective subpoena
or order issued by a court or governmental body; provided, however, that
the foregoing shall not apply to confidential information which becomes
publicly disseminated by means other than a breach of this provision. It
is recognized that damages in the event of breach of this Section 4.4
(b)(ii) by the Participant would be difficult, if not impossible, to
ascertain, and it is therefore agreed that AEP or the Corporation, in
addition to and without limiting any other remedy or right AEP or the
Corporation may have, shall have the right to an injunction or other
equitable relief in any court of competent jurisdiction, enjoining any
such breach, and the Participant hereby waives any and all defenses the
Participant may have on the ground of lack of jurisdiction or competence
of the court to grant such an injunction or other equitable relief. The
existence of this right shall not preclude AEP or the Corporation from
pursuing any other rights or remedies at law or in equity which AEP or the
Corporation may have.
4.5 Payment Obligations Absolute. The obligations of the Corporation to
pay the Separation Benefits described in Section 4.3 and the other benefits
described in Section 4.4 shall be absolute and unconditional and shall not be
affected by any circumstances, including, without limitation, any set-off,
counterclaim, defense or other right which the Corporation may have against any
Participant. In no event shall a Participant be obligated to seek other
employment or take any other action by way of mitigation of the amounts payable
to a Participant under any of the provisions of this Plan, nor shall the amount
of any payment hereunder be reduced by any compensation earned by a Participant
as a result of employment by another employer, except as specifically provided
in Section 4.3(c)(i).
ARTICLE V
SUCCESSOR TO CORPORATION
This Plan shall bind any successor of AEP or the Corporation, their assets
or their businesses (whether direct or indirect, by purchase, merger,
consolidation or otherwise) in the same manner and to the same extent that AEP
or the Corporation would be obligated under this Plan if no succession had taken
place.
In the case of any transaction in which a successor would not by the
foregoing provision or by operation of law be bound by this Plan, AEP or the
Corporation shall require such successor expressly and unconditionally to assume
and agree to perform AEP's or the Corporation's obligations under this Plan, in
the same manner and to the same extent that AEP or the Corporation would be
required to perform if no such succession had taken place. The term
"Corporation," as used in this Plan, shall mean the Corporation as hereinbefore
defined and any successor or assignee to the business of assets which by reason
hereof becomes bound by this Plan.
ARTICLE VI
DURATION, AMENDMENT AND TERMINATION
6.1 Duration. This Plan shall terminate on the date the closing conditions
set forth in Article VII of the Merger Agreement are not met or the date the
Merger Agreement is terminated pursuant to Article IX of the Merger Agreement,
unless it is extended for an additional period or periods by resolution adopted
by the Board. If the Combination occurs, this Plan shall terminate two years
after the closing date of the Combination.
6.2 Amendment. Except as provided in Section 6.1, the Plan shall not be
subject to amendment, change, substitution, deletion, revocation or termination
in any respect which adversely affects the rights of Participants.
6.3 Form of Amendment. The form of any amendment of the Plan shall be a
written instrument signed by a duly authorized officer of the Corporation,
certifying that the amendment has been approved by the Board.
ARTICLE VII
MISCELLANEOUS
7.1 Indemnification. If a Participant institutes any reasonable legal
action in seeking to obtain or enforce or is required to defend in any
reasonable legal action the validity or enforceability of, any right or benefit
provided by this Plan, the Corporation will pay for all actual and reasonable
legal fees and expenses incurred (as incurred) by such Participant, regardless
of the outcome of such action.
7.2 Employment Status. This Plan does not constitute a contract of
employment or impose on the Participant or the Corporation any obligation to
retain the Participant as an employee, to change the status of the Participant's
employment, or to change the Corporation's policies regarding the termination of
employment.
7.3 Claim Procedure. If a Participant makes a written request alleging a
right to receive benefits under this Plan or alleging a right to receive an
adjustment in benefits being paid under the Plan, the Corporation shall treat it
as a claim for benefit. All claims for benefit under the Plan shall be sent to
the Human Resources Department of the Corporation and must be received within 30
days after the Date of Termination. If the Corporation determines that any
individual who has claimed a right to receive benefits, or different benefits,
under the Plan is not entitled to receive all or any part of the benefits
claimed, it will inform the claimant in writing of its determination and the
reasons therefor in terms calculated to be understood by the claimant. The
notice will be sent within 90 days of the claim unless the Corporation
determines additional time, not exceeding 90 days, is needed. The notice shall
make specific reference to the pertinent Plan provisions on which the denial is
based, and describe any additional material or information, if any, necessary
for the claimant to perfect the claim and the reason any such addition material
or information is necessary. Such notice shall, in addition, inform the claimant
what procedure the claimant should follow to take advantage of the review
procedures set forth below in the event the claimant desires to contest the
denial of the claim. The claimant may within 90 days thereafter submit in
writing to the Corporation a notice that the claimant contests the denial of the
claim by the Corporation and desires a further review. The Corporation shall
within 60 days thereafter review the claim and authorize the claimant to appear
personally and review pertinent documents and submit issues and comments
relating to the claim to the persons responsible for making the determination on
behalf of the Corporation. The Corporation will render its final decision with
specific reasons therefore in writing and will transmit it to the claimant
within 60 days of the written request for review, unless the Corporation
determines additional time, not exceeding 60 days, is needed, and so notifies
the claimant. If the Corporation fails to respond to a claim filed in accordance
with the foregoing within 60 days or any such extended period, the Corporation
shall be deemed to have denied the claim.
7.4 Validity and Severability. The invalidity or unenforceability of any
provision of the Plan shall not affect the validity or enforceability of any
other provision of the Plan, which shall remain in full force and effect, and
any prohibition or unenforceability in any jurisdiction shall not invalidate or
render unenforceable such provision in any other jurisdiction.
7.5 Governing Law. The validity, interpretation, construction and
performance of the Plan shall in all respects be governed by the law of Ohio,
without reference to principles of conflicts of laws, except to the extent
pre-empted by federal law.
SCHEDULE 1
PARTICIPANTS IN THE AMERICAN ELECTRIC POWER SYSTEM
SENIOR EXECUTIVE SEVERANCE PLAN
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
<CAPTION>
Year Ended December 31, 1998 1997 1996 1995 1994
<S> <C> <C> <C> <C> <C>
INCOME STATEMENTS DATA (in millions):
Operating Revenues $6,346 $5,880 $5,849 $5,670 $5,505
Operating Income 957 984 1,008 965 932
Income Before Extraordinary Item 536 620 587 530 500
Extraordinary Loss -
UK Windfall Tax - 109 - - -
Net Income 536 511 587 530 500
December 31, 1998 1997 1996 1995 1994
BALANCE SHEETS DATA (in millions):
Electric Utility Plant $20,146 $19,597 $18,970 $18,496 $18,175
Accumulated Depreciation
and Amortization 8,416 7,964 7,550 7,111 6,827
Net Electric
Utility Plant $11,730 $11,633 $11,420 $11,385 $11,348
Total Assets $19,483 $16,615 $15,883 $15,900 $15,736
Common Shareholders' Equity 4,842 4,677 4,545 4,340 4,229
Cumulative Preferred Stocks
of Subsidiaries:
Not Subject to Mandatory Redemption 46 47 90 148 233
Subject to Mandatory Redemption* 128 128 510 523 590
Long-term Debt* 7,006 5,424 4,884 5,057 4,980
Obligations Under Capital Leases* 533 538 414 405 400
*Including portion due within one year
Year Ended December 31, 1998 1997 1996 1995 1994
COMMON STOCK DATA:
Earnings per Common Share:
Before Extraordinary Item $2.81 $ 3.28 $3.14 $2.85 $2.71
Extraordinary Loss - UK Windfall Tax - (0.58) - - -
Net Income $2.81 $ 2.70 $3.14 $2.85 $2.71
Average Number of Shares
Outstanding (in thousands) 190,774 189,039 187,321 185,847 184,666
Market Price Range: High $53-5/16 $ 52 $44-3/4 $40-5/8 $37-3/8
Low 42-1/16 39-1/8 38-5/8 31-1/4 27-1/4
Year-end Market Price 47-1/16 51-5/8 41-1/8 40-1/2 32-7/8
Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio 85.4% 88.7%(a) 76.5% 84.1% 88.6%
Book Value per Share $25.24 $24.62 $24.15 $23.25 $22.83
(a) Dividend Payout Ratio before Extraordinary Loss - UK Windfall Tax is 73.1%.
</TABLE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
This discussion includes forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934.
These forward-looking statements reflect assumptions, and involve
a number of risks and uncertainties. Among the factors that could
cause actual results to differ materially from forward looking
statements are: electric load and customer growth; abnormal weather
conditions; available sources and costs of fuels; availability of
generating capacity; the impact of the proposed merger with Central
and South West Corporation (CSW) including any regulatory
conditions imposed on the merger or the inability to consummate the
merger with CSW; the speed and degree to which competition is
introduced to our power generation business, the structure and
timing of a competitive market and its impact on energy prices or
fixed rates; the ability to recover stranded costs in connection
with possible deregulation of generation; new legislation and
government regulations; the ability of the Company to successfully
control its costs; the success of new business ventures;
international developments affecting our foreign investments; the
economic climate and growth in our service territory; unforeseen
events affecting the Company's nuclear plant which is on an
extended safety related shutdown; problems or failures related to
Year 2000 readiness of computer software and hardware; inflationary
trends; electricity and gas market prices; interest rates and other
risks and unforeseen events. This discussion contains a "Year 2000
Readiness Disclosure" within the meaning of the Year 2000
Information and Readiness Disclosure Act.
Growth Of The Business
In 1998 management continued to implement its growth-oriented
strategy with a goal of being America's Energy Partner and a global
energy and related services company. We have adopted a strategy to
expand our geographic reach and to build and acquire capabilities
across a broader spectrum of the energy products and services value
chain. AEP is working to position itself to be successful in an
increasingly competitive market that will allow customers to choose
their energy supplier. AEP made several acquisitions in 1998 that
expanded its energy operations overseas and in the United States.
The expansion of the foreign energy business in 1998 included the
purchase of CitiPower, an Australian electric distribution utility,
the acquisition of an equity interest in Pacific Hydro, an
Australian hydroelectric generating company, and continued on-
schedule construction of two generating units in China.
The $1.1 billion acquisition of CitiPower, completed on
December 31, 1998, was accounted for using the purchase method of
accounting. CitiPower serves approximately 240,000 customers in
the city of Melbourne. CitiPower will contribute to earnings
beginning in the first quarter of 1999.
In March 1998 the Company invested $10 million to acquire a 20%
equity interest in Pacific Hydro. Pacific Hydro operates four
hydroelectric power stations in Australia with an installed
capacity of 40 megawatts (MW) and has interests in two
hydroelectric projects under construction in the Philippines.
The generating units under construction in China are owned 70%
by the Company with the remaining 30% owned by two Chinese
partners. Construction of the two unit 250 MW, coal-fired station
is proceeding on schedule. The first unit began commercial
operation in February of 1999 and the second unit is expected to go
into commercial service in July of 1999. These units are expected
to contribute to earnings in 1999.
In addition, the Company has a 50% investment in Yorkshire
Electricity Group plc (Yorkshire), a United Kingdom (UK)
distribution electric company. The investment was made in April
1997 and contributed $38.5 million to nonregulated, nonoperating
income in 1998. In September 1998 certain residential and
commercial customers in the UK could choose their electricity
supplier marking the start of a transition to competition.
Yorkshire serves approximately 2.2 million customers.
One disappointment we suffered in 1998 was the withdrawal of
a joint venture partner. In 1997 the Company announced a joint
venture with Conoco, an energy subsidiary of DuPont. The venture
was to provide energy management and financing for steam and
electric generation facilities for commercial and industrial
customers. Conoco withdrew from the joint venture after its parent
announced plans to sell Conoco.
The past year also saw the expansion of AEP's domestic energy
operations. On December 1, 1998, the Company purchased the
midstream gas operations of Equitable Resources, Inc. for
approximately $340 million including working capital funds. The
midstream operations include a fully integrated natural gas
gathering, processing, storage and transportation operation in
Louisiana and a gas trading and marketing operation in Houston,
Texas. Assets include an intrastate pipeline system, four natural
gas processing plants plus a fifth plant under construction, one
natural gas storage facility and an additional storage facility
under construction. The gas trading operation included in this
purchase was merged with AEP's existing gas trading organization
which began operating in December 1997. This acquisition is
expected to enhance AEP's gas trading operations by improving
management's knowledge of the Henry Hub gas market.
Traditionally a major marketer of electricity, AEP has recently
become a major participant in the electricity trading market. Our
electricity trading operation, which commenced in mid 1997,
significantly expanded its trading volume in 1998. Electricity
trading involves the trading of contracts for the future delivery
or receipt of electricity in both regulated and non-regulated
operations. It also involves the purchase and sale of options,
swaps and other electricity derivative financial instruments. Open
access transmission, the introduction of competition to the
wholesale electricity market and the development of a trading
market and settlement process have fostered the growth of
electricity trading in the United States. The electricity trading
market is a highly volatile market which requires enhanced credit
and market risk management skills. Electricity trading requires
little capital investment and profit margins are usually smaller
than margins on traditional electricity sales. The Company's goal
is to utilize its knowledge of energy markets to trade electricity
and gas to contribute to net income, thereby enhancing both
customer and shareholder value.
In December 1997 the Company and CSW agreed to merge. The
merger is intended to expand AEP's geographic reach. The benefits
of the merger include costs savings; improved prices and services;
increased financial strength; greater diversity in fuel, generation
and service territory; and increased scale (the size of the Company
which contributes to business success in a competitive market). At
the 1998 annual meeting AEP shareholders approved the issuance of
common shares to effect the merger and approved an increase in the
number of authorized shares of AEP Common Stock from 300,000,000 to
600,000,000 shares. CSW stockholders approved the merger at their
May 1998 annual meeting. Approval of the merger has been requested
from the Federal Energy Regulatory Commission (FERC), the
Securities and Exchange Commission, the Nuclear Regulatory
Commission (NRC) and all of CSW's state regulatory commissions:
Arkansas, Louisiana, Oklahoma and Texas. In the near future, AEP
and CSW plan to make the final two filings associated with approval
of the merger with the Federal Communications Commission and the
Department of Justice.
Regulatory approvals for the merger have been received from the
Arkansas Public Service Commission (APSC) and the NRC. In December
1998 the APSC approved a stipulated agreement related to a proposed
merger regulatory plan submitted by the Company, CSW and CSW's
Arkansas operating subsidiary, Southwestern Electric Power Company.
The regulatory plan, agreed to with the APSC staff, provides for a
sharing of net merger savings through a $6 million rate reduction
over 5 years following the completion of the merger.
The application to the NRC by CSW's operating subsidiary,
Central Power and Light Company (CPL), requesting permission to
transfer indirect control of the license from CSW to AEP for CPL's
interest in the South Texas Project nuclear generating station was
approved by the NRC in November 1998.
In October 1998 the Oklahoma Corporation Commission (OCC)
approved plans by AEP and CSW to submit an amended filing seeking
approval of the proposed merger. The amended application is being
made as a result of an Oklahoma administrative law judge's
recommendation that the merger filing be dismissed without
prejudice for lack of sufficient information regarding the
potential impact of the merger on the retail electric market in
Oklahoma. Submission of the amended application will reset
Oklahoma's 90-day statutory time period for OCC action on the
merger phase of the application. The filing of the amended
application should not affect the timing of the merger closing.
A settlement agreement between AEP, CSW and certain key parties
to the Texas merger proceeding has been reached. The staff of the
Public Utility Commission of Texas was not a signatory to the
settlement agreement, which resolves all issues for the
signatories. The settlement provides for, among other things, rate
reductions totaling approximately $180 million over a six year
period following completion of the merger to share net merger
savings of $84 million and settle existing rate issues of $96
million. Hearings are scheduled for April 1999.
In July 1998 the FERC issued an order which confirmed that a
250 megawatt firm contract path with the Ameren System is
available. The contract path was obtained by AEP and CSW to meet
the requirement of the Public Utility Holding Company Act of 1935
that the two systems operate on an integrated and coordinated
basis.
In November 1998 the FERC issued an order establishing hearing
procedures for the merger and scheduled the hearings to begin on
June 1, 1999. The FERC order indicated that the review of the
proposed merger will address the issues of competition, market
power and customer protection and instructed the companies to
refile an updated market power study.
The proposed merger of CSW into AEP would result in common
ownership of two UK regional electricity companies (RECs),
Yorkshire and Seeboard, plc. AEP has a 50% ownership interest in
Yorkshire and CSW has a 100% interest in Seeboard. Although the
merger of CSW into AEP is not subject to approval by UK regulatory
authorities, the common ownership of two UK RECs could be referred
by the UK Secretary of State for Trade and Industry to the UK
Monopolies and Mergers Commission for investigation.
AEP has received a request from the staff of the Kentucky
Public Service Commission (KPSC) to file an application seeking
KPSC approval for the indirect change in control of Kentucky Power
Company that will occur as a result of the proposed merger.
Although AEP does not believe that the KPSC has the jurisdictional
authority to approve the merger, management will prepare a merger
application filing to be made with the KPSC, which is expected to
be filed by April 15, 1999. Under the governing statute the KPSC
must act on the application within 60 days. Therefore this is not
expected to impact the timing of the merger.
The merger is conditioned upon, among other things, the
approval of the above state and federal regulatory agencies. The
transaction must satisfy many conditions, a number of which may not
be waived by the parties, including the condition that the merger
must be accounted for as a pooling of interests. The merger
agreement will terminate on December 31, 1999 unless extended by
either party as provided in the merger agreement. Although
consummation of the merger is expected to occur in the fourth
quarter of 1999, the Company is unable to predict the outcome or
the timing of the required regulatory proceedings.
Business Outlook
The most significant factors affecting the Company's future
earnings are the ability to recover its costs as the domestic
electric generating business becomes more competitive and the
performance of the recently acquired energy investments and
business ventures described above. The Company continues to
evaluate domestic and international markets for investments to grow
the business in the best interests of our shareholders, customers
and employees. The performance of any future acquisitions, mergers
and investments will also impact future earnings.
The introduction of competition and customer choice for retail
customers in the Company's domestic service territory has been slow
and continues at a deliberate pace as legislators and regulatory
officials recognize the complexity of the issues. Federal
legislation has been proposed to mandate competition and customer
choice at the retail level. In February 1999 the Virginia general
assembly passed legislation, subject to the governor's signature,
that would provide Virginia retail customers the ability to choose
their electric supplier beginning in 2002. The legislation
provides for the recovery of "just and reasonable net stranded
costs". Prior to January 1, 2001 the Virginia State Corporation
Commission must establish rates that will be "capped" through as
long as July 1, 2007. Statement of Financial Accounting Standards
(SFAS) 71 "Accounting for the Effects of Certain Types of
Regulation" will no longer apply to the Company's Virginia retail
jurisdiction once the "capped" rates are established. When this
occurs the application of SFAS 71 will be discontinued for the
Virginia retail jurisdiction portion of the generating business and
net regulatory assets applicable to the Virginia generating
business would have to be written off to the extent that they are
not probable of recovery. Although management does not believe
that the impact of the new legislation on regulatory assets would
have a material adverse impact on results of operations, cash flows
or financial condition, the amount of an impairment loss, if any,
cannot be estimated with any certainty until the "capped" rates are
determined (See requirements of EITF 97-4 discussed below).
All of the other states within our service territory have
initiatives to implement or review customer choice, although the
timing is uncertain. The Company supports customer choice and
deregulation of generation and is proactively involved in
discussions at both the state and federal levels regarding the best
competitive market structure and method to transition to a
competitive marketplace.
As the pricing of generation in the electric energy market
evolves from regulated cost-of-service ratemaking to market-based
rates, many complex issues must be resolved, including the recovery
of stranded costs. Stranded costs are those costs above market and
potentially would not be recoverable in a competitive market. At
the wholesale level recovery of stranded costs under certain
conditions was addressed by the FERC when it established rules for
open transmission access and competition in the wholesale markets.
However, the issue of stranded cost is generally unresolved at the
retail level where it is much larger than it is at the wholesale
level. The amount of stranded costs the Company could experience
depends on the timing and extent to which competition is introduced
to its generation business and the future market prices of
electricity. The recovery of stranded cost is dependent on the
terms of future legislation and related regulatory proceedings.
Under the provisions of SFAS 71, regulatory assets (deferred
expenses) and regulatory liabilities (deferred revenues) are
included in the consolidated balance sheets of regulated utilities
in accordance with regulatory actions in order to match expenses
and revenues with cost-based rates. In order to maintain net
regulatory assets on the balance sheet, SFAS 71 requires that rates
charged to customers be cost-based and provide for the recovery of
the deferred expenses over future accounting periods. In the event
a portion of AEP's business no longer meets the requirements of
SFAS 71, SFAS 101 "Accounting for the Discontinuance of
Application of Statement 71" requires that net regulatory assets be
written off for that portion of the business. The provisions of
SFAS 71 and SFAS 101 never anticipated that deregulation would
include an extended transition period or that it could provide for
recovery of stranded costs during and after the transition period.
In 1997 the Financial Accounting Standards Board's Emerging Issues
Task Force (EITF) addressed such a situation with the consensus
reached on issue 97-4 that requires the application of SFAS 71 to
a segment of a regulated electric utility cease when that segment
is subject to a legislatively approved plan for competition or an
enabling rate order is issued containing sufficient detail for the
utility to reasonably determine what the plan would entail. The
EITF indicated that the cessation of application of SFAS 71 would
require that regulatory assets and impaired plant be written off
unless they are recoverable in future rates.
Although certain FERC orders provide for competition in the
firm wholesale market, that market is a relatively small part of
our business and most of our firm wholesale sales are still under
cost-of-service contracts. As of December 31, 1998 AEP's
generation business is cost-based regulated. The enactment of
enabling legislation in Virginia to deregulate the generation
business will cause a portion of the Company's generation business
to become deregulated. This could ultimately result in adverse
impacts on results of operations and cash flows depending on the
market price of electricity and the ability of the Company to
recover its stranded costs. We believe that enabling state
legislation should provide for the recovery of any generation-related
net regulatory assets and other reasonable stranded costs
from impaired generating assets. However, if in the future AEP's
generation business were to no longer be cost-based regulated and
if it were not possible to demonstrate probability of recovery of
resultant stranded costs including regulatory assets, results of
operations, cash flows and financial condition would be adversely
affected.
Cost Containment and Process Improvements
Efforts continue to reduce the costs of AEP's products and
services in order to maintain competitiveness. The accounting
department completed its consolidation of operations and the
marketing department completed its reorganization in 1998 producing
significant cost reductions. In 1998 plans were announced to close
one of the Company's coal mining operations in October 1999 and the
Company reviewed its staffing levels for power generation and
energy delivery and developed plans to reduce staff in 1999. The
cost of staff reductions planned for 1999 was provided for in the
fourth quarter of 1998. Although cost savings are expected to
result from the power generation and energy delivery
reorganizations and the planned mine closing, the Company continues
to incur expenses related to investments in new business growth and
development; marketing and customer services; and the reengineering
and improvement of business processes.
During 1998, AEP completed installation of a new unified
customer service system which is designed to support customer
requests for service, billings, accounts receivable, credit and
collection functions. On January 1, 1999, the Company's new
financial data base and PeopleSoft client server accounting and
purchasing software became operational. The move to client server
business software and related online data bases will empower AEP
employees to maximize the benefits of their personal computers and
will position AEP to access the power of the Internet and other new
technologies.
Fuel Costs
The management and control of coal costs is critical to AEP's
competitive position. Approximately 90% of AEP's generation is
coal fired and approximately 13% of the 54 million tons of coal
burned in 1998 were supplied by affiliated mines with the remainder
acquired under long-term contracts and purchases in the spot
market. As long-term contracts expire we are negotiating with
unaffiliated suppliers to lower coal costs. We intend to continue
to prudently supplement our long-term coal supplies with spot
market purchases when spot market prices are favorable.
We have agreed in our Ohio jurisdiction to certain limitations
on the current recovery of affiliated coal costs. At December 31,
1998, the Company had deferred $106 million for future recovery
under the agreements which established the limitation. See
discussion in Note 2 of the Notes to Consolidated Financial
Statements. Our analysis shows that we should be able to recover
the Ohio jurisdictional portion of the costs of our affiliated
mining operations including future mine closure costs before the
expiration of the agreement in 2009. The Company has announced
plans to close the Muskingum mine in 1999. A provision for
Muskingum mine closing cost of $45 million was recorded in 1998.
Management intends to seek recovery of its non-Ohio jurisdictional
portion of its investment in and the liabilities and closing costs
of affiliated mines estimated at $100 million after tax.
Should it become apparent that these affiliated mining costs
will not be recovered from Ohio and/or non-Ohio jurisdictional
customers, the other mines may have to be closed and future
earnings, cash flows and possibly financial condition would be
adversely affected. In addition compliance with Phase II
requirements of the Clean Air Act Amendments of 1990 (CAAA), which
become effective in January 2000, could also cause the remaining
mining operations to close. Unless the cost of any mine closure
and the coal cost deferrals in the Ohio jurisdiction are recovered
either in regulated rates or as a stranded cost under a plan to
transition the generation business to competition, future earnings,
cash flows and possibly financial condition would be adversely
affected.
Costs for Spent Nuclear Fuel and Decommissioning
AEP, as the owner of the Cook Nuclear Plant, like other nuclear
power plants, has a significant future financial commitment to
safely dispose of spent nuclear fuel (SNF) and decommission and
decontaminate the plant. The Nuclear Waste Policy Act of 1982
established federal responsibility for the permanent off-site
disposal of SNF and high-level radioactive waste. By law we
participate in the Department of Energy's (DOE) SNF disposal
program which is described in Note 4 of the Notes to Consolidated
Financial Statements. Since 1983 we have collected $272 million
from customers for the disposal of nuclear fuel consumed at the
Cook Plant. $115 million of these funds have been deposited in
external trust funds to provide for the future disposal of spent
nuclear fuel and $157 million has been remitted to the DOE. 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. However, in December 1996, the DOE notified AEP
that it would be unable to begin accepting SNF by the January 1998
deadline required by law.
As a result of DOE's failure to make sufficient progress toward
a permanent repository or otherwise assume responsibility for SNF,
AEP along with a number of unaffiliated utilities and states filed
suit in the U.S. Court of Appeals for the District of Columbia
Circuit requesting, among other things, that the court order DOE to
meet its obligations under the law. The court ordered the parties
to proceed with contractual remedies but declined to order DOE to
begin accepting SNF for disposal. DOE estimates its planned site
for the nuclear waste will not be ready until 2010. In June 1998,
AEP filed a complaint in the U.S. Court of Federal Claims seeking
damages in excess of $150 million due to the DOE's partial material
breach of its unconditional contractual deadline to begin disposing
of SNF generated by the Cook Nuclear Plant. Similar lawsuits have
been filed by other utilities. As long as the delay in the
availability of a government approved storage repository for SNF
continues, the cost of both temporary and permanent storage will
increase.
The cost to decommission the Cook Plant is affected by both NRC
regulations and the delayed SNF disposal program. Studies
completed in 1997 estimate the cost to decommission the Cook Plant
ranges from $700 million to $1,152 million in 1997 dollars. This
estimate could escalate due to continued uncertainty in the SNF
disposal program and the length of time that SNF may need to be
stored at the plant site. External trust funds have been
established with amounts collected from customers to decommission
the plant. At December 31, 1998, the total decommissioning trust
fund balance was $443 million which includes earnings on the trust
investments. We will work with regulators and customers to recover
the remaining estimated cost of decommissioning the Cook Plant.
However, AEP's future results of operations, cash flows and
possibly its financial condition would be adversely affected if the
cost of SNF disposal and decommissioning continues to increase and
cannot be recovered.
COOK NUCLEAR PLANT SHUTDOWN
We shut down both units of the Cook Nuclear Plant in September
1997 due to questions, which arose during a NRC architect engineer
design inspection, regarding the operability of certain safety
systems. The NRC issued a Confirmatory Action Letter in September
1997 requiring AEP to address the issues identified in the letter.
We are working with the NRC to resolve the remaining open issue in
the letter.
In April 1998 the NRC notified I&M that it had convened a
Restart Panel for Cook Plant. A list of required restart
activities was provided by the NRC in July 1998 and in October the
NRC expanded the list. In order to identify and resolve the issues
necessary to restart the Cook units, AEP is and will be meeting
with the Panel on a regular basis, until the units are returned to
service.
In January 1999 we announced that we will conduct additional
engineering reviews at the Cook Plant that will delay restart of
the units. Previously, the units were scheduled to return to
service at the end of the first and second quarters of 1999. The
decision to delay restart resulted from internal assessments that
indicated a need to conduct expanded system readiness reviews. A
new restart schedule will be developed based on the results of the
expanded reviews and should be available in June 1999. When
maintenance and other activities required for restart are complete,
AEP will seek concurrence from the NRC to return the Cook Plant to
service. Until these additional reviews are completed, management
is unable to determine when the units will be returned to service.
Unless the costs of the extended outage and restart efforts are
recovered from customers, there would be a material adverse effect
on results of operations, cash flows and possibly financial
condition.
One of the steps AEP has taken toward expediting the restart
of the Cook units is to augment its existing nuclear generation
management and staff with personnel experienced in restarting
unaffiliated companies' nuclear plants during NRC supervised
extended outages.
The incremental costs incurred in 1997 and 1998 for restart of
the Cook units were $6 million and $78 million, respectively, and
recorded as operation and maintenance expense. Currently
incremental restart expenses are approximately $12 million a month.
In July 1998 AEP received an "adverse trend letter" from the
NRC indicating that NRC senior managers determined that there had
been a slow decline in performance at the Cook Plant during the 18
month period preceding the letter. The letter indicated that the
NRC will closely monitor efforts to address issues at Cook Plant
through additional inspection activities. In October 1998 the NRC
issued AEP a Notice of Violation and proposed a $500,000 civil
penalty for alleged violations at the Cook Plant discovered during
five inspections conducted between August 1997 and April 1998. AEP
paid the penalty.
The cost of electricity supplied to certain retail customers
rose due to the outage of the two units since higher cost coal-fired
generation and coal based purchased power were substituted
for low cost nuclear generation. AEP's Indiana and Michigan retail
jurisdictional fuel cost recovery mechanisms permit the recovery,
subject to regulatory commission review and approval, of changes in
fuel costs including the fuel component of purchased power in the
Indiana jurisdiction and changes in replacement power in the
Michigan jurisdiction. Under these fuel cost recovery mechanisms,
retail rates contain a fuel cost adjustment factor that reflects
estimated fuel costs for the period during which the factor will be
in effect subject to reconciliation to actual fuel costs in a
future proceeding. When actual fuel costs exceed the estimated
costs reflected in the billing factor a regulatory asset is
recorded and revenues are accrued. Therefore, a regulatory asset
has been recorded and revenues accrued in anticipation of the
future reconciliation and billing under the fuel cost recovery
mechanisms of the higher fuel costs to replace Cook energy during
the extended outage. At December 31, 1998, the regulatory asset
was $65 million.
The Indiana Utility Regulatory Commission approved, subject to
future reconciliation or refund, agreements authorizing AEP, during
the billing months of July 1998 through March 1999, to include in
rates a fuel cost adjustment factor less than that requested by
AEP. The agreements provide the parties to the proceedings with
the opportunity to conduct discovery regarding certain issues that
were raised in the proceedings, including the appropriateness of
the recovery of replacement energy cost due to the extended Cook
Plant outage, in anticipation of resolving the issues in a future
fuel cost adjustment proceeding. Management believes that it
should be allowed to recover the deferred Cook replacement energy
costs; however, if recovery of the replacement costs is denied,
future results of operations and cash flows would be adversely
affected by the writeoff of the regulatory asset.
Environmental Concerns and Issues
We take great pride in our efforts to economically produce and
deliver electricity while minimizing the impact on the environment.
Over the years AEP has spent more than a billion dollars to equip
its facilities with the latest cost effective clean air and water
technologies and to research new technologies. We are also proud
of our award winning efforts to reclaim our mining properties. We
intend to continue in a leadership role fostering 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 SNF. Coal combustion by-products, which constitute the
overwhelming percentage of these materials, are typically disposed
of or treated in captive disposal facilities or are beneficially
utilized. In addition, our generating plants and transmission and
distribution facilities have used asbestos, polychlorinated
biphenyls (PCBs) and other hazardous and nonhazardous materials.
We are currently incurring costs to safely dispose of such
substances. Additional costs could be incurred to comply with new
laws and regulations if enacted.
The Comprehensive Environmental Response, Compensation and
Liability Act (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 1998, we are involved in
litigation with respect to three sites overseen by the Federal EPA
and have been named by the Federal EPA as a potentially responsible
party (PRP) for three other sites. There is one additional site
for which AEP has received an information request which could lead
to PRP designation. Our liability has been resolved for a number
of sites with no significant effect on results of operations. In
those instances where we have been named a PRP or defendant, our
disposal or recycling activity was in accordance with the then-applicable laws
and regulations. Unfortunately, Superfund does not
recognize compliance as a defense, but imposes strict liability on
parties who fall within its broad statutory categories.
While the potential liability for each Superfund site must be
evaluated separately, several general statements can be made
regarding our potential future liability. AEP's disposal of
materials at a particular site is often unsubstantiated and the
quantity of materials deposited at a site was small and often
nonhazardous. Typically many parties are named as PRPs for each
site and, although liability is joint and several, generally
several of the parties are financially sound enterprises.
Therefore, our present estimates do not anticipate material cleanup
costs for identified sites for which we have been declared PRPs.
However, if for reasons not currently identified significant
cleanup costs are attributed in the future to AEP, results of
operations, cash flows and possibly financial condition would be
adversely affected unless the costs can be recovered from
customers.
In December 1998 the Company purchased gas assets from
Equitable Resources, Inc. (Equitable). The purchase contract
contains details of partial indemnification by Equitable for
certain environmental and soil and ground water contamination
cleanup liabilities which existed at the time of AEP's purchase.
An outside consultant has estimated total environmental liabilities
for the acquired entities to range from $10 million to $16 million.
By contract the Company must seek indemnification by December 1,
2000. The indemnification clause requires that AEP incur $3
million of cleanup liabilities before seeking reimbursement. Based
upon the consultant's estimate, environmental liabilities resulting
from the gas asset acquisition should not have a material impact on
results of operations, cash flows or financial condition.
In December 1998, the Company purchased CitiPower, an
Australian distribution utility, from Entergy, an unaffiliated
company. CitiPower operates under Australian environmental laws.
Prior to the purchase, AEP hired an outside consultant, experienced
in Australian environmental laws, to identify CitiPower's exposure.
The consultant's assessment identified sites with contaminated
land, PCBs and storm water runoff. Cost of environmental
remediation are estimated at $3.5 million by the consultant. Based
upon this estimate, environmental costs from the acquisition of
CitiPower are not expected to have a material impact on results of
operations, cash flows or financial condition.
Federal EPA is required by the CAAA to issue rules to implement
the law. In 1996 Federal EPA issued final rules governing nitrogen
oxides (NOx) emissions that must be met after January 1, 2000
(Phase II of CAAA). The final rules will require substantial
reductions in NOx emissions from certain types of boilers including
those in AEP's power plants. To comply with Phase II of CAAA, the
Company plans to install NOx emission control equipment on certain
units and switch fuel at other units. Total capital costs to meet
the requirements of Phase II of CAAA are estimated to be
approximately $90 million of which $69 million has been incurred
through December 31, 1998.
On September 24, 1998, the administrator of Federal EPA signed
final rules which require reductions in NOx emissions in 22 eastern
states, including the states in which the Company's generating
plants are located. The implementation of the final rules would be
achieved through the revision of state implementation plans (SIPs)
by September 1999. SIPs are a procedural method used by each state
to comply with Federal EPA rules. The final rules anticipate the
imposition of a NOx reduction on utility sources of approximately
85% below 1990 emission levels by the year 2003. On October 30,
1998, a number of utilities, including the operating companies of
the AEP System, filed petitions in the U.S. Court of Appeals for
the District of Columbia Circuit seeking a review of the final
rules.
Should the states fail to adopt the required revisions to their
SIPs within one year of the date the final rules were signed
(September 24, 1999), Federal EPA has proposed to implement a
federal plan to accomplish the NOx reductions. Federal EPA also
proposed the approval of portions of petitions filed by eight
northeastern states that would result in imposition of NOx emission
reductions on utility and industrial sources in upwind midwestern
states. These reductions are substantially the same as those
required by the final NOx rules and could be adopted by Federal EPA
in the event the states fail to implement SIPs in accordance with
the final rules.
Preliminary estimates indicate that compliance costs could
result in required capital expenditures of approximately $1.2
billion for the AEP System. Compliance costs cannot be estimated
with certainty and the actual costs incurred to comply could be
significantly different from this preliminary estimate depending
upon the compliance alternatives selected to achieve reductions in
NOx emissions. Unless such costs are recovered from customers,
they would have a material adverse effect on results of operations,
cash flows and possibly financial condition.
At the Third Conference of the Parties to the United Nations
Framework Convention on Climate Change held in Kyoto, Japan in
December 1997 more than 160 countries, including the United States,
negotiated a treaty requiring legally-binding reductions in
emissions of greenhouse gases, chiefly carbon dioxide, which many
scientists believe are contributing to global climate change. The
treaty, which requires the advice and consent of the United States
Senate for ratification, would require the United States to reduce
greenhouse gas emissions seven percent below 1990 levels in the
years 2008-2012. Although the United States has agreed to the
treaty and signed it on November 12, 1998, President Clinton has
indicated that he will not submit the treaty to the Senate for
consideration until it contains requirements for "meaningful
participation by key developing countries" and the rules,
procedures, methodology and guidelines of the treaty's market-based
policy instruments, joint implementation programs and compliance
enforcement provisions have been negotiated. At the Fourth
Conference of the Parties, held in Buenos Aires, Argentina, in
November 1998, the parties agreed to a work plan to complete
negotiations on outstanding issues with a view toward approving
them at the Sixth Conference of the Parties to be held in December
2000. We will continue to work with the Administration and
Congress to monitor the development of public policy on this issue.
If the Kyoto treaty is approved by Congress, the costs to
comply with the emission reductions required by the treaty are
expected to be substantial and would have a material adverse impact
on results of operations, cash flows and possibly financial
condition if not recovered from customers.
Results of Operations
Net Income
Net income increased 5% to $536 million or $2.81 per share from
$511 million or $2.70 per share in 1997 primarily due to the effect
of a 1997 extraordinary loss of $109 million. The extraordinary
loss, recorded in 1997, was a result of the UK's one-time windfall
tax which was based on a revision or recomputation of the original
privatization value of certain privatized utilities, including
Yorkshire. In 1997 net income decreased 13% to $511 million
primarily due to the extraordinary loss of $109 million from the
UK's one-time windfall tax.
Income Before Extraordinary Item
In 1998 income before the extraordinary loss, recorded in 1997,
decreased 14% to $536 million or $2.81 per share from $620 million
or $3.28 per share in 1997. Several major items reduced 1998
earnings including the cost of restart activities during an
extended outage at the Cook Nuclear Plant, a write-down of
Yorkshire's investment in Ionica, a UK telecommunications company,
severance accruals for reductions in power generation and energy
delivery staff and mild winter and fall weather.
AEP's 1997 income before the extraordinary loss increased 6%
to $620 million or $3.28 per share from $587 million or $3.14 per
share in 1996. The increase was primarily attributable to
increased transmission service revenues, reduced preferred stock
dividends due to a redemption program and an increase in
nonoperating income from equity earnings, exclusive of the
extraordinary loss, since the April 1997 investment in Yorkshire.
<PAGE>
Revenues Increase
Operating revenues increased 8% in 1998 and were relatively
unchanged in 1997. Increased revenues from retail, wholesale and
transmission service customers were the primary reasons for the
increase in 1998. The slight increase in 1997 is primarily due to
increased transmission service revenues. The changes in the
components of revenues are as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1998 1997
Amount % Amount %
Retail:
Residential $ 37.6 $(34.7)
Commercial 57.0 1.8
Industrial 90.1 18.2
Other 3.8 0.4
188.5 3.8 (14.3) (0.3)
Wholesale 206.8 25.9 6.1 0.8
Transmission 68.0 61.7 33.3 43.2
Miscellaneous 2.8 4.8 5.5 10.9
Total $466.1 7.9 $ 30.6 0.5
Retail revenues increased 4% in 1998 reflecting a 2% sales
increase and higher fuel recoveries. The increase in retail fuel
recoveries reflects higher cost coal fired generation and purchased
power replacing power usually generated at the Cook Nuclear Plant.
The Cook Plant has been unavailable since September 1997. Although
residential sales were flat reflecting mild winter and fall weather
in 1998, revenues from residential customers increased 2%. The
accrual of revenues for the recovery of the Cook related increased
fuel costs accounted for the increase in residential revenues. The
rise in commercial revenues resulted from a 4% increase in sales
reflecting increased usage and growth in the number of customers.
Industrial revenues increased 6% reflecting a sales increase of 2%
following the resumption of operations by a major industrial
customer after an extended labor strike. Also contributing to the
increase in industrial revenues were favorable contract price
adjustments to certain major industrial customers and the pass-through of
higher power costs during periods of peak demand.
In 1997 retail revenues decreased slightly although retail
sales rose one half of a percent. Residential revenues and sales
each declined 2% reflecting mild weather. Sales to commercial
customers increased slightly causing a small increase in commercial
revenues. Industrial sales increased 2% accounting for the
increase in industrial revenues. The increase in lower priced
sales to industrial customers resulted from increased usage.
The 26% increase in wholesale revenues in 1998 is attributable
to trading of electricity with other utilities and power marketers
in the Company's traditional marketing area and increased power
marketing sales. Revenues from the trading of electricity are
recorded net of purchases. Regulated trading activities are
conducted as part of AEP's electric power wholesale marketing and
trading operations and involve the purchase and sale of substantial
amounts of electricity. Power marketing sales are for the resale
of power purchased from unaffiliated companies to other
unaffiliated companies. Although wholesale revenues rose, total
wholesale sales declined due to a reduction in coal conversion
service sales. These sales are for the generation of electricity
from the purchaser's coal and as a result do not include fuel
costs. Consequently, the drop in coal conversion service sales did
not have a significant effect on wholesale revenues.
In 1997 wholesale revenues increased slightly primarily due to
the commencement of trading activities in July 1997 and a
significant increase in coal conversion service sales. Since the
price of coal conversion service sales is for the generation of
electricity from coal provided by the electricity purchaser and
excludes fuel cost, a large change in coal conversion service sales
has a small impact on revenues.
The 62% increase in transmission service revenues in 1998 is
attributable to a substantial rise in the quantity of energy
transmitted for other entities over AEP's transmission lines. The
increase in 1997 of 43% in transmission service revenues was also
due to an increase in the volume of other companies' electricity
transmitted through AEP's transmission system. The issuance in
1996 of open transmission access rules by the FERC facilitated the
growth in transmission services.
The level of wholesale transactions, including transmission
services, tends to fluctuate due to the highly competitive nature
of the short-term energy market and other factors, such as
affiliated and unaffiliated generating plant availability, the
weather and the economy. The FERC rules which introduced a greater
degree of competition into the wholesale energy market have had a
major effect on wholesale sales and increased transmission service
revenues as more electricity is traded in the short-term (spot)
market. The Company's sales and in turn its results of operations
were impacted by the quantities of energy and services sold to
wholesale customers as well as the sale prices and cost of goods
sold. Future results of operations will be affected by the
quantity and price of both retail and wholesale transactions which
often depend on factors the Company does not control including the
level of competition, the weather and affiliated and unaffiliated
power plant availability. However, we work to keep abreast of
these factors and to take advantage of them whenever possible.
<PAGE>
Operating Expenses Increase
Operating expenses increased 10% in 1998 and 1% in 1997.
Changes in the components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1998 1997
Amount % Amount %
Fuel $ 90.1 5.5 $ 26.4 1.6
Purchased Power 301.7 223.9 48.6 56.5
Other Operation 75.7 6.2 17.3 1.4
Maintenance 59.7 12.3 (19.6) (3.9)
Depreciation and Amortization (11.1) (1.9) (9.7) (1.6)
Taxes Other Than Federal
Income Taxes 2.8 0.6 (8.0) (1.6)
Federal Income Taxes (25.1) (7.3) (0.9) (0.3)
Total $493.8 10.1 $ 54.1 1.1
Fuel expense increased in 1998 and 1997 primarily due to an
increase in the average cost of fuel consumed reflecting the
reduced availability of lower cost nuclear generation due to the
unplanned shutdown of both of AEP's nuclear units which began in
September 1997 and continued throughout 1998.
The significant increases in purchased power expense in both
1998 and 1997 were primarily due to purchases of electricity for
resale to other utilities and power marketers and for replacement
of energy usually generated at the Cook Plant. The increase in
purchases made for resale to other entities reflects an expanding
and evolving wholesale marketplace.
Other operation expenses increased in 1998 due to the extended
Cook Plant outage, power marketing and trading compensation and
severance accruals for reductions in power generation and energy
delivery staff.
Maintenance expense increased in 1998 largely due to
expenditures to prepare the Cook Plant units for restart and to
restore service interrupted by two severe snowstorms.
The decrease in federal income tax expense attributable to
operations in 1998 was primarily due to a decrease in pre-tax
operating income.
Nonoperating Income
The significant decline in nonoperating income in 1998 was due
to losses from non-regulated energy trading activity and the write-down of
Yorkshire's investment in Ionica ($30 million). The
trading of gas and electricity outside of AEP's traditional
marketing area is marked-to-market and recorded in nonoperating
income.
The increase in nonoperating income in 1997 was mainly due to
income from the Company's share of earnings from its April 1997
investment in Yorkshire. The $34 million of equity in Yorkshire
earnings included $10 million of tax benefits related to a
reduction of the UK corporate income tax rate from 33% to 31%
effective April 1, 1997. The utilization of foreign tax credits
also contributed to the increase in nonoperating income.
Interest Charges and Preferred Stock Dividend Requirements
In 1997 interest charges on both long-term and short-term debt
increased reflecting additional borrowing primarily to fund the
Company's investment in non-regulated operations including the
investment in Yorkshire. Preferred stock dividend requirements of
the subsidiaries decreased in 1997 due to the reacquisition of over
4 million shares of cumulative preferred stock.
Financial Condition
AEP's financial condition continues to be strong. The 1998
payout ratio was 85.4%. It has been a management objective to
reduce the payout ratio through efforts to increase earnings in
order to enhance AEP's ability to invest in new energy based
businesses that can leverage our core competencies and improve
shareholder value. AEP's three-year total shareholder return
ranked 14th among the companies in the S&P Electric Utility Index.
While this placed us just below the midpoint, it has been and
continues to be management's goal to be in the top quartile of the
S&P Electric Utility Index for three-year total shareholder return.
Capital Investments
The total consideration paid by AEP to acquire CitiPower was
approximately $1.1 billion which was financed by the issuance of
debt in Australia and an equity investment by AEP Resources, Inc.
(AEPR). The purchase, for approximately $340 million, of domestic
gas assets in Louisiana was funded with part of the proceeds from
an issuance of $400 million of 6-1/2% senior notes by AEPR. For
more information see Note 6 of the Notes to Consolidated Financial
Statements. Also AEP's 70% interest in the construction of two 125
MW units in China required approximately $61 million of investment
during 1998.
Consolidated construction expenditures for all subsidiaries are
expected to be $2.4 billion over the next three years. All
expenditures for domestic electric utility construction, estimated
to be $2.2 billion for the next three years, are expected to be
financed with internally generated funds.
Capital Resources - Structure and Liquidity
AEP's ratio of common equity to total capitalization including
amounts due within one year was 40.3% for 1998, compared with 45.5%
for 1997 and 45.3% for 1996. The decline in 1998 reflects
borrowing to support the acquisitions which were completed in
December.
The Company and its subsidiaries issued $1.9 billion principal
amount of long-term obligations in 1998 at interest rates ranging
from 5% to 10.53%. The Company also increased its borrowing under
a long-term revolving credit agreement which expires in June 2000
by $270 million. The principal amount of long-term debt
retirements, including maturities, totaled $563 million with
interest rates ranging from 2.85% to 9.60%. The operating
subsidiaries senior secured debt/first mortgage bond ratings are
listed in the following table:
Company Moody's S&P Fitch D & P
APCo A3 A A A
CSPCo A3 A- A- A
I&M Baa1 A- BBB+ BBB+
KPCo Baa1 A BBB+ BBB+
OPCo A3 A- A- A
The operating subsidiaries generally issue short-term debt to
provide for interim financing of capital expenditures that exceed
internally generated funds. They periodically reduce their
outstanding short-term debt through issuances of long-term debt and
additional capital contributions by the parent company. The
companies formed to pursue non-regulated businesses use short-term
debt (through a revolving credit facility) which is replaced with
long-term debt when financial market conditions are favorable and
capital contributions by the parent company. They also assume
outstanding debt as part of the acquisition of existing business
entities. Short-term debt increased $62 million from the prior
year-end balance and increased by $235 million in 1997. At
December 31, 1998, AEP Co., Inc. (the parent company) and its
subsidiaries had unused short-term lines of credit of $763 million,
and several of AEP's subsidiaries engaged in non-regulated energy
investments and businesses had available $60 million under a $600
million revolving credit agreement which expires in June 2000. The
sources of funds available to AEP are dividends from its
subsidiaries, short-term and long-term borrowings and proceeds from
the issuance of common stock. AEP issued 1,826,000 shares of
common stock in 1998, 1,755,000 shares in 1997 and 1,600,000 shares
in 1996 through a Dividend Reinvestment and Direct Stock Purchase
Plan and the Employee Savings Plan raising $86 million, $77 million
and $65 million, respectively. Additional sales of common stock
and/or equity linked securities may be necessary in the future to
support the Company's growth.
Unless the domestic electric operating utility subsidiaries
meet certain earnings or coverage tests, they cannot issue
additional mortgage bonds. In order to issue mortgage bonds
(without refunding existing debt), each subsidiary must have pre-tax earnings
equal to at least two times the annual interest
charges on mortgage bonds after giving effect to the issuance of
the new debt.
The following debt coverages of AEP's principal domestic
electric operating utility subsidiaries remained strong in 1998:
Coverages at
December 31, 1998
Mortgage
APCo 3.88
CSPCo 6.36
I&M 6.39
KPCo 4.40
OPCo 13.43
As the above table indicates, the major domestic electric
operating utility subsidiaries presently exceed the minimum
coverage requirements.
Market Risks
The Company as a major power producer and a trader of wholesale
electricity and natural gas has certain market risks inherent in
its business activities. The trading of electricity and natural
gas and related financial derivative instruments exposes the
Company to market risk. Market risk represents the risk of loss
that may impact the Company due to adverse changes in commodity
market prices and rates. In 1998 the Company substantially
increased the volume of its wholesale electricity and natural gas
marketing and trading activities. Various policies and procedures
have been established to manage market risk exposures including the
use of a risk measurement model utilizing Value at Risk (VaR).
Throughout the year ending December 31, 1998, the highest, lowest
and average quarterly VaR in the wholesale trading portfolio was
less than $11 million at a 95% confidence level with a holding
period of three business days. The Company used the variance-covariance method
for calculating VaR based on three months of
daily prices. Based on this VaR analysis, at December 31, 1998 a
near term change in commodity prices is not expected to have a
material effect on the Company's results of operations, cash flows
or financial condition. At December 31, 1997, the exposure for
financial derivatives in electricity and natural gas marketing
activities were not material to the Company's consolidated results
of operations, financial position or cash flows.
Investments in foreign ventures expose the Company to risk of
foreign currency fluctuations. The Company's exposure to changes
in foreign currency exchange rates related to these foreign
ventures and investments is not expected to be significant for the
foreseeable future since these foreign investments are considered
long-term and not expected to be liquidated in the near-term. The
Company does not presently utilize derivatives to manage its
exposures to foreign currency exchange rate movements.
The Company is exposed to changes in interest rates primarily
due to short- and long-term borrowings to fund its business
operations. The debt portfolio has both fixed and variable
interest rates, terms from one day to forty years and an average
duration of five years at December 31, 1998.
The Company measures interest rate market risk exposure
utilizing a VaR model. The model is based on the Monte Carlo
method of simulated price movements with a 95% confidence level and
a one year holding period. The volatilities and correlations were
based on three years of monthly prices. The risk of potential loss
in fair value attributable to the Company's exposure to interest
rates, primarily related to long-term debt with fixed interest
rates, was $589 million at December 31, 1998 and $501 million at
December 31, 1997. The Company would not expect to liquidate its
entire debt portfolio in a one year holding period. Therefore, a
near term change in interest rates should not materially affect
results of operations or the consolidated financial position of the
Company. The Company is currently utilizing interest rate swaps to
manage its exposure to interest rate fluctuations in Australia.
The Company has investments in debt and equity securities which
are held in nuclear trust funds. Approximately 85% of the trust
fund value is invested in tax exempt and taxable bonds, short-term
debt instruments or cash. The trust investments and their fair
value are discussed in Note 11 of the Notes to Consolidated
Financial Statements. Instruments in the trust funds have not been
included in the market risk calculation for interest rates as these
instruments are marked-to-market and changes in market value are
reflected in a corresponding decommissioning liability. Any
differences between the trust fund assets and the ultimate
liability should be recoverable from ratepayers.
Inflation affects AEP's cost of replacing utility plant and the
cost of operating and maintaining its plant. The rate-making
process limits our recovery to the historical cost of assets
resulting in economic losses when the effects of inflation are not
recovered from customers on a timely basis. However, economic
gains that result from the repayment of long-term debt with
inflated dollars partly offset such losses.
Other Matters
Year 2000 Readiness Disclosure
On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date. In
addition, certain systems may fail to detect that the year 2000 is
a leap year. Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Year 2000
ready programs.
<PAGE>
Readiness Program - Internally, the Company is modifying or
replacing its computer hardware and software programs to minimize
Year 2000-related failures and repair such failures if they occur.
This includes both information technology systems (IT), which are
mainframe and client server applications, and embedded logic
systems (non-IT), such as process controls for energy production
and delivery. Externally, the problem is being addressed with
entities that interact with the Company, including suppliers,
customers, creditors, financial service organizations and other
parties essential to the Company's operations. In the course of
the external evaluation, the Company has sought written assurances
from third parties regarding their state of Year 2000 readiness.
Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system.
AEP, along with other electric utilities in North America,
regularly submits information to the North American Electric
Reliability Council (NERC) as part of NERC's Year 2000 readiness
program. NERC then publicly reports summary information to the
U.S. Department of Energy (DOE) regarding the Year 2000 readiness
of electric utilities. In 1999 AEP plans to participate in two
NERC-sponsored coordinated electric industry Year 2000 readiness
drills.
The second NERC report, dated January 11, 1999 and entitled:
Preparing the Electric Power Systems of North American for
Transition to the Year 2000 - A Status Report and Work Plan, Fourth
Quarter 1998, states that: "With more than 44% of mission critical
components tested through November 30, 1998, findings continue to
indicate that transition through critical Year 2000 (Y2K) rollover
dates is expected to have minimal impact on electric system
operations in North America." The Company continues to set a
target date of June 30, 1999 for having all mission critical and
high priority systems and components Y2K ready.
Through the Electric Power Research Institute, an electric
industry-wide effort has been established to deal with Year 2000
problems affecting embedded systems. Under this effort,
participating utilities, including AEP, are working together to
assess specific vendors' system problems and test plans.
The state regulatory commissions in the Company's service
territory are also reviewing the Year 2000 readiness of the
Company.
Company's State of Readiness - Work has been prioritized in
accordance with business risk. The highest priority has been
assigned to activities that potentially affect safety, the physical
generation and delivery of energy and communications; followed by
back office activities such as customer service/billing, regulatory
reporting, internal reporting and administrative activities (e.g.
payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in
normal business operations.
The following chart shows our progress toward becoming ready
for the Year 2000 as of December 31, 1998:
IT SYSTEMS NON-IT SYSTEMS
COMPLETION COMPLETION
DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE
Launch: Initiation of 2/24/1998 100% 5/31/1998 100%
the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.
Inventory and Assessment:
Identifying all Company 7/31/1998 100% 2/15/1999 99%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.
Remediation/Testing: The
process of modifying, 6/30/1999 Mainframe 6/30/1999 37%
replacing or retiring 70%
those mission critical and
high priority digital-based
systems with problems Client
processing dates past the Server:
Year 2000. Testing these 18%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.
The above chart does not reflect progress of recently acquired
midstream gas operations and CitiPower. The mission critical
systems for the midstream gas operations are expected to be ready
by June 30, 1999 and the mission critical systems for CitiPower are
expected to be ready by October 1, 1999.
Costs to Address the Company's Year 2000 Issues - Through
December 31, 1998, the Company has spent $21 million on the Year
2000 project and estimates spending an additional $35 million to
$47 million to achieve Year 2000 readiness. Most Year 2000 costs
are for software, IT consultants and salaries and are expensed;
however, in certain cases the Company has acquired hardware that
was capitalized. The Company intends to fund these expenditures
through internal sources. Although significant, the cost of
becoming Year 2000 compliant is not expected to have a material
impact on the Company's results of operations, cash flows or
financial condition.
Risks of the Company's Year 2000 Issues - The applications
posing the greatest business risk to the Company's operations
should they experience Y2K problems are:
* Automated power generation, transmission and distribution systems
* Telecommunications systems
* Energy trading systems
* Time-in-use, demand and remote metering systems for
commercial and industrial customers
* Work management and billing systems.
The potential problems related to erroneous processing by, or
failure of, these systems are:
* Power service interruptions to customers
* Interrupted revenue data gathering and collection
* Poor customer relations resulting from delayed billing and
settlement.
CitiPower operates under a legal and regulatory regime which
may expose it to customer claims, that may differ from claims under
the US legal and regulatory regime, for service interruptions
and/or power quality problems resulting from Y2K problems.
In addition, although as discussed the Company is monitoring
its relationships with third parties, such as suppliers, customers
and other electric utilities, these third parties nonetheless
represent a risk that cannot be assessed with precision or
controlled with certainty.
Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others not affiliated with AEP, fail for critical
applications, Year 2000-related issues may materially adversely
affect AEP.
Company's Contingency Plans - To address possible failures of
electric generation and delivery of electrical energy due to Year
2000 related failures, we have established a draft Year 2000
contingency plan and submitted it to the East Central Area
Reliability Council (ECAR) in December 1998 as part of NERC's
review of regional and individual electric utility contingency
plans in 1999. NERC's target date is June 1999 for the completion
of this contingency plan. In addition, the Company intends to
establish contingency plans for its business units to address
alternatives if Year 2000 related failures occur. AEP's
contingency plans will be developed by the end of 1999. AEP's
plans build upon the disaster recovery, system restoration, and
contingency planning that we have had in place.
<PAGE>
New Accounting Standards
In 1997 the FASB issued SFAS 130 "Reporting Comprehensive
Income" and SFAS No. 131 "Disclosures About Segments of an
Enterprise and Related Information." SFAS 130 establishes the
standards for reporting and displaying components of "comprehensive
income," which is the total of net income and all transactions not
included in net income affecting equity except those with
shareholders. The Company adopted SFAS 130 in the first quarter of
1998. For 1998 there were no material differences between net
income and comprehensive income.
SFAS 131 initiates reporting standards for annual and interim
financial statements about operating segments of a business for
which separate financial information is available and regularly
evaluated by the chief operating decision maker in allocating
resources and reviewing performance. Information about products
and services and geographic areas is to be reported at an
enterprise-level instead of by segment. SFAS 131 was required to
be adopted by the Company for the year ended December 31, 1998 with
restatement of prior period comparative information. Adoption of
SFAS 131 did not have any effect on results of operations, cash
flows or financial condition.
In the first quarter of 1998 the Company adopted the American
Institute of Certified Public Accountants' (AICPA) Statement of
Position (SOP) 98-1, "Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use". The SOP requires the
capitalization and amortization of certain costs of acquiring or
developing internal use computer software. Previously the Company
expensed all software acquisition and development costs. The SOP
had to be adopted at the beginning of a fiscal year with no
restatement or retroactive adjustment of prior periods. The
adoption of the SOP effective January 1, 1998 did not have a
material effect on results of operations, cash flows or financial
condition.
In February 1998, the FASB issued SFAS 132 "Employers'
Disclosure about Pensions and Other Postretirement Benefits" which
revised employers' disclosures about pensions and other
postretirement benefit plans and suggested that the disclosure be
combined. It did not change the measurement or recognition
requirements for postretirement benefit accounting. The adoption
of SFAS 132 did not have a material effect on results of
operations, cash flows or financial condition. Prior periods were
restated to comply with SFAS 132 presentation requirements.
EITF 98-10 "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities" was issued in November 1998 to
address the application of mark-to-market accounting for energy
trading contracts. Under the provisions of this standard, which
must be adopted by the Company in January 1999, energy trading
contracts can no longer be accounted for on a settlement basis.
Instead they are to be marked-to-market. Adoption of EITF 98-10 is
not expected to have a significant impact on results of operations,
cash flows or financial condition.
The FASB issued SFAS 133 "Accounting for Derivative Instruments
and Hedging Activities" in June 1998. SFAS 133 establishes
accounting and reporting standards for derivative instruments. It
requires that all derivatives be recognized as either an asset or
a liability and measured at fair value in the financial statements.
If certain conditions are met a derivative may be designated as a
hedge of possible changes in fair value of an asset, liability or
firm commitment; variable cash flows of forecasted transactions; or
foreign currency exposure. The accounting/reporting for changes in
a derivative's fair value (gains and losses) depend on the intended
use and resulting designation of the derivative. Management is
currently studying the provisions of SFAS 133 to determine the
impact of its adoption on January 1, 2000 on results of operations,
cash flows and financial condition.
In April 1998 the AICPA issued SOP 98-5 "Reporting on the Costs
of Start-up Activities". The SOP clarifies the accounting and
reporting for one time start-up activities and organization costs,
requiring that they be expensed as incurred. The adoption of this
standard in January 1999 is not expected to have a material effect
on results of operations, cash flows or financial condition.
Litigation
Corporate Owned Life Insurance
The Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns requested a ruling
from their National Office that certain interest deductions claimed
by the Company relating to AEP's corporate owned life insurance
(COLI) program should not be allowed. As a result of a suit filed
by AEP in United States District Court (discussed below) this
request for ruling was withdrawn by the IRS agents. Adjustments
have been or will be proposed by the IRS disallowing COLI interest
deductions for taxable years 1991-96. A disallowance of the COLI
interest deductions through December 31, 1998 would reduce earnings
by approximately $316 million (including interest). The Company has
made no provision for any possible adverse earnings impact from
this matter.
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years 1991-97
to avoid the potential assessment by the IRS of any additional
above market rate interest on the contested amount. The payments
to the IRS are included on the balance sheet in other property and
investments pending the resolution of this matter. The Company
will seek refund, either administratively or through litigation, of
all amounts paid plus interest. In order to resolve this issue
without further delay, on March 24, 1998, the Company filed suit
against the United States in the United States District Court for
the Southern District of Ohio. Management believes that it has a
meritorious position and will vigorously pursue this lawsuit. In
the event the resolution of this matter is unfavorable, it will
have a material adverse impact on results of operations, cash flows
and possibly financial condition.
AEP is involved in a number of other 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, cash flows and/or financial condition.
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands - except per share amounts)
<CAPTION>
Year Ended December 31,
1998 1997 1996
<S> <C> <C> <C>
OPERATING REVENUES $6,345,902 $5,879,820 $5,849,234
OPERATING EXPENSES:
Fuel 1,717,177 1,627,066 1,600,659
Purchased Power 436,388 134,718 86,095
Other Operation 1,303,084 1,227,368 1,210,027
Maintenance 542,935 483,268 502,841
Depreciation and Amortization 579,997 591,071 600,851
Taxes Other Than Federal Income Taxes 493,386 490,595 498,567
Federal Income Taxes 316,201 341,280 342,222
TOTAL OPERATING EXPENSES 5,389,168 4,895,366 4,841,262
OPERATING INCOME 956,734 984,454 1,007,972
NONOPERATING INCOME (net) 9,463 59,572 2,212
INCOME BEFORE INTEREST CHARGES AND
PREFERRED DIVIDENDS 966,197 1,044,026 1,010,184
INTEREST CHARGES 419,088 405,815 381,328
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES 10,926 17,831 41,426
INCOME BEFORE EXTRAORDINARY ITEM 536,183 620,380 587,430
EXTRAORDINARY LOSS - UK WINDFALL TAX - (109,419) -
NET INCOME $ 536,183 $ 510,961 $ 587,430
AVERAGE NUMBER OF SHARES OUTSTANDING 190,774 189,039 187,321
EARNINGS PER SHARE:
Before Extraordinary Item $2.81 $3.28 $3.14
Extraordinary Loss - (0.58) -
Net Income $2.81 $2.70 $3.14
CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(in thousands)
Year Ended December 31,
1998 1997 1996
RETAINED EARNINGS JANUARY 1 $1,605,017 $1,547,746 $1,409,645
NET INCOME 536,183 510,961 587,430
DEDUCTIONS:
Cash Dividends Declared 457,638 453,453 449,353
Other 1 237 (24)
RETAINED EARNINGS DECEMBER 31 $1,683,561 $1,605,017 $1,547,746
See Notes to Consolidated Financial Statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(in thousands - except share data)
<CAPTION>
December 31,
1998 1997
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production $ 9,591,211 $ 9,493,158
Transmission 3,570,717 3,501,580
Distribution 4,779,772 4,654,234
General (including mining assets and nuclear fuel) 1,641,676 1,604,671
Construction Work in Progress 562,891 342,842
Total Electric Utility Plant 20,146,267 19,596,485
Accumulated Depreciation and Amortization 8,416,397 7,963,636
NET ELECTRIC UTILITY PLANT 11,729,870 11,632,849
OTHER PLANT 841,451 62,213
OTHER PROPERTY AND INVESTMENTS 2,515,103 1,294,291
CURRENT ASSETS:
Cash and Cash Equivalents 172,985 91,481
Accounts Receivable:
Customers 557,382 559,203
Miscellaneous 360,783 115,075
Allowance for Uncollectible Accounts (11,075) (6,760)
Fuel - at average cost 215,699 224,967
Materials and Supplies - at average cost 279,823 263,613
Accrued Utility Revenues 186,006 189,191
Energy Marketing and Trading Contracts 372,380 2,306
Prepayments and Other 83,686 81,366
TOTAL CURRENT ASSETS 2,217,669 1,520,442
REGULATORY ASSETS 1,846,718 1,817,540
DEFERRED CHARGES 332,391 288,011
TOTAL $19,483,202 $16,615,346
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
<CAPTION>
December 31,
1998 1997
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock-Par Value $6.50:
1998 1997
Shares Authorized. .600,000,000 300,000,000
Shares Issued. . . .200,816,469 198,989,981
(8,999,992 shares were held in treasury) $ 1,305,307 $ 1,293,435
Paid-in Capital 1,852,912 1,778,782
Retained Earnings 1,683,561 1,605,017
Total Common Shareholders' Equity 4,841,780 4,677,234
Cumulative Preferred Stocks of Subsidiaries:*
Not Subject to Mandatory Redemption 46,002 46,724
Subject to Mandatory Redemption 127,605 127,605
Long-term Debt* 6,799,641 5,129,463
TOTAL CAPITALIZATION 11,815,028 9,981,026
OTHER NONCURRENT LIABILITIES 1,428,968 1,246,537
CURRENT LIABILITIES:
Long-term Debt Due Within One Year* 206,476 294,454
Short-term Debt 616,604 555,075
Accounts Payable 618,019 353,256
Taxes Accrued 381,905 380,771
Interest Accrued 75,184 76,361
Obligations Under Capital Leases 81,661 101,089
Energy Marketing and Trading Contracts 360,248 1,983
Other 461,540 322,687
TOTAL CURRENT LIABILITIES 2,801,637 2,085,676
DEFERRED INCOME TAXES 2,601,402 2,560,921
DEFERRED INVESTMENT TAX CREDITS 350,946 376,250
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 222,042 231,320
DEFERRED CREDITS 263,179 133,616
COMMITMENTS AND CONTINGENCIES (Note 4)
TOTAL $19,483,202 $16,615,346
*See Accompanying Schedules.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<CAPTION>
Year Ended December 31,
1998 1997 1996
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net Income $ 536,183 $ 510,961 $ 587,430
Adjustments for Noncash Items:
Depreciation and Amortization 619,557 608,217 590,657
Deferred Federal Income Taxes 41,449 (6,549) (21,478)
Deferred Investment Tax Credits (25,304) (25,241) (25,808)
Amortization of Operating Expenses
and Carrying Charges (net) 14,786 12,001 55,458
Equity in Earnings of Yorkshire
Electricity Group plc (38,459) (33,780) -
Extraordinary Item - UK Windfall Tax - 109,419 -
Deferred Costs Under Fuel Clause Mechanisms (73,219) (52,469) 51
Changes in Certain Current Assets
and Liabilities:
Accounts Receivable (net) (141,637) (136,186) (39,049)
Fuel, Materials and Supplies 2,108 (1,427) 35,831
Accrued Utility Revenues 3,185 (14,225) 32,953
Accounts Payable 200,195 147,029 (13,915)
Taxes Accrued (826) (33,402) (6,019)
Payment of Disputed Tax and Interest
Related to COLI (302,739) (3,080) -
Other (net) 194,247 116,654 40,951
Net Cash Flows From Operating Activities 1,029,526 1,197,922 1,237,062
INVESTING ACTIVITIES:
Construction Expenditures (792,118) (760,394) (577,691)
Investment in Yorkshire Electricity Group plc - (363,436) -
Investment in CitiPower (1,054,081) - -
Investment in Gas Assets (340,131) - -
Other (26,370) 2,142 12,283
Net Cash Flows Used For
Investing Activities (2,212,700) (1,121,688) (565,408)
FINANCING ACTIVITIES:
Issuance of Common Stock 85,515 76,745 65,461
Issuance of Long-term Debt 2,491,113 880,522 407,291
Retirement of Cumulative Preferred Stock (547) (433,329) (70,761)
Retirement of Long-term Debt (915,294) (348,157) (601,278)
Change in Short-term Debt (net) 61,529 235,380 (45,430)
Dividends Paid on Common Stock (457,638) (453,453) (449,353)
Net Cash Flows From (Used For)
Financing Activities 1,264,678 (42,292) (694,070)
Net Increase (Decrease) in Cash and
Cash Equivalents 81,504 33,942 (22,416)
Cash and Cash Equivalents January 1 91,481 57,539 79,955
Cash and Cash Equivalents December 31 $ 172,985 $ 91,481 $ 57,539
See Notes to Consolidated Financial Statements.
/TABLE
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies:
Organization - American Electric Power (AEP or the Company) is one
of the United States' (US) largest investor-owned public utility
holding companies engaged in the generation, purchase, transmission
and distribution of electric power to 3 million retail customers in
its seven state service territory which covers portions of Ohio,
Michigan, Indiana, Kentucky, West Virginia, Virginia and Tennessee.
Electric power is also supplied at wholesale to neighboring utility
systems and power marketers. AEP also has other energy holdings in
the US, the United Kingdom (UK), China and Australia.
The organization of AEP consists of American Electric Power
Company, Inc. (AEP Co., Inc.), the parent holding company; seven
domestic regulated electric utility operating companies (domestic
utility subsidiaries); a domestic generating subsidiary, AEP
Generating Company (AEGCo); three active coal-mining companies; a
service company, American Electric Power Service Corporation
(AEPSC); AEP Resources, Inc. (AEPR) which invests in, owns and
operates non-regulated energy-related domestic and international
projects; AEP Energy Services, Inc. (AEPES) which markets and
trades energy commodities; and other subsidiaries that provide non-regulated
energy and communication services.
The following domestic utility subsidiaries pool their generating
and transmission facilities and operate them as an integrated
system: Appalachian Power Company (APCo), Columbus Southern Power
Company (CSPCo), Indiana Michigan Power Company (I&M), Kentucky
Power Company (KPCo) and Ohio Power Company (OPCo). The remaining
two domestic utility subsidiaries, Kingsport Power Company (KGPCo)
and Wheeling Power Company (WPCo) are distribution companies that
purchase power from APCo and OPCo, respectively. AEPSC provides
management and professional services to the AEP System
subsidiaries. The active coal-mining companies are wholly-owned by
OPCo and sell most of their production to OPCo. AEGCo has a 50%
interest in the Rockport Plant which is comprised of two of the AEP
System's six 1,300 megawatt (mw) generating units. AEPR owns 50%
of Yorkshire Electricity Group plc (Yorkshire), a supply and
distribution electric company in the UK (see Note 7); 70% of a
joint venture which is constructing a two-unit power plant nearing
completion in China; 20% of Pacific Hydro, an Australian
hydroelectric generating company; all of the assets of a midstream
natural gas operation in Louisiana and 100% of CitiPower, a
Melbourne, Australia distribution utility. The acquisitions of the
midstream natural gas assets and CitiPower were completed in
December 1998 (see Note 6). AEPES currently markets and trades
natural gas. The non-regulated subsidiaries are engaged in
providing power engineering, consulting and management services
around the world and fiber, wireless and information communication
services in the US.
Although the domestic utility subsidiaries are managed centrally by
AEPSC and operate as American Electric Power they and AEPSC have
not changed their names and remain separate legal entities.
Rate Regulation - The AEP System is subject to regulation by the
Securities and Exchange Commission (SEC) under the Public Utility
Holding Company Act of 1935 (1935 Act). The rates charged by the
domestic utility subsidiaries are approved by the Federal Energy
Regulatory Commission (FERC) or the state utility commissions as
applicable. The FERC regulates wholesale rates and the state
commissions regulate retail rates.
Principles of Consolidation - The consolidated financial statements
include AEP Co., Inc. and its wholly-owned and majority-owned
subsidiaries consolidated with their wholly-owned subsidiaries.
Significant intercompany items are eliminated in consolidation.
Yorkshire and Pacific Hydro are accounted for using the equity
method.
Basis of Accounting - As the owner of cost-based rate-regulated
electric public utility companies, AEP Co., Inc.'s consolidated
financial statements reflect the actions of regulators that result
in the recognition of revenues and expenses in different time
periods than enterprises that are not rate regulated. In
accordance with Statement of Financial Accounting Standards (SFAS)
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 and to match expenses with regulated revenues.
Use of Estimates - The preparation of these financial statements in
conformity with generally accepted accounting principles requires
in certain instances the use of estimates. Actual results could
differ from those estimates.
Regulated Utility Plant - Electric utility plant, which represents
the costs of service rate-regulated fixed assets of the domestic
electric utility subsidiaries, is stated at original cost and is
generally subject to first mortgage liens. Additions, major
replacements and betterments are added to the plant accounts.
Retirements from the plant accounts and associated removal costs,
net of salvage, are deducted from accumulated depreciation. The
costs of labor, materials and overheads incurred to operate and
maintain regulated domestic utility plant are included in operating
expenses. The distribution utility plant assets of CitiPower are
included in other plant.
Allowance for Funds Used During Construction (AFUDC) - AFUDC is a
noncash nonoperating income item that is recovered over the service
life of utility plant through depreciation and represents the
estimated cost of borrowed and equity funds used to finance
construction projects. The amounts of AFUDC for 1998, 1997 and
1996 were not significant.
<PAGE>
Depreciation, Depletion and Amortization - Depreciation is provided
on a straight-line basis over the estimated useful lives of
property other than coal-mining property and is calculated largely
through the use of composite rates by functional class. The annual
composite depreciation rates for regulated utility plant for 1998,
1997 and 1996 were as follows:
Functional Class Annual Composite
of Property Depreciation Rates
Production:
Steam-Nuclear 3.4%
Steam-Fossil-Fired 3.2% to 4.4%
Hydroelectric-Conventional
and Pumped Storage 2.7% to 3.4%
Transmission 1.7% to 2.7%
Distribution 3.3% to 4.2%
General 2.5% to 3.8%
The domestic utility subsidiaries presently recover amounts to be
used for demolition and removal of non-nuclear plant through
depreciation charges included in rates. Depreciation, depletion
and amortization of coal-mining assets is provided over each
asset's estimated useful life or the estimated life of the mine,
whichever is shorter, ranging up to 30 years, and is calculated
using the straight-line method for mining structures and equipment.
The units-of-production method is used to amortize coal rights and
mine development costs based on estimated recoverable tonnages at
a current average rate of $1.85 per ton in 1998, $1.91 per ton in
1997 and $1.49 per ton in 1996. These costs are included in the
cost of coal charged to fuel expense.
Cash and Cash Equivalents - Cash and cash equivalents include
temporary cash investments with original maturities of three months
or less.
Foreign Currency Translation - The financial statements of
subsidiaries outside the US are measured using the local currency
as the functional currency. Assets and liabilities are translated
to US dollars at year-end rates of exchange and revenues and
expenses are translated at monthly average exchange rates
throughout the year. Currency translation gain and loss
adjustments are accumulated in shareholders' equity. The
accumulated total of such adjustments at December 31, 1998 and 1997
is not material. Currency transaction gains and losses are
recorded in income.
Derivative Financial Instruments - During 1998, the Company
substantially increased the volume of its wholesale electricity and
natural gas marketing and trading transactions (trading
activities). Trading activities involve the sale of energy under
physical forward contracts at fixed and variable prices and the
trading of energy contracts including exchange traded futures and
options, over-the-counter options and swaps. The majority of these
transactions represent physical forward contracts in the Company's
traditional marketing area and are typically settled by entering
into offsetting contracts. The net revenues from these
transactions in the Company's traditional economic marketing area
are included in regulated revenues for ratemaking, regulatory
accounting and reporting purposes.
The Company has also purchased and sold electricity and gas
options, futures and swaps, and entered into forward purchase and
sale contracts for electricity outside its traditional marketing
area. These transactions represent non-regulated trading
activities that are included in nonoperating income. The
unrealized mark-to-market gains and losses from such non-regulated
trading activity are reported as assets and liabilities,
respectively.
The Company enters into contracts to manage the exposure to
unfavorable changes in the cost of debt to be issued. These
anticipatory debt instruments are entered into in order to manage
the change in interest rates between the time a debt offering is
initiated and the issuance of the debt (usually a period of 60
days). Gains or losses are deferred and amortized over the life of
the debt issuance. There were no such forward contracts
outstanding at December 31, 1998 or 1997.
See Note 11 - Financial Instruments, Credit and Risk Management for
further discussion.
Operating Revenues and Fuel Costs - Revenues include the accrual of
electricity consumed but unbilled at month-end as well as billed
revenues. Fuel costs are matched with revenues in accordance with
rate commission orders. Generally in the retail jurisdictions,
changes in fuel costs are deferred or revenues accrued until
approved by the regulatory commission for billing or refund to
customers in later months. Wholesale jurisdictional fuel cost
changes are expensed and billed as incurred.
Levelization of Nuclear Refueling Outage Costs - In accordance with
SFAS 71 incremental operation and maintenance costs associated with
refueling outages at I&M's Cook Plant are deferred and amortized
over the period 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 the book
cost and tax basis of assets and liabilities which will result in
a future tax consequence. Where the flow-through method of
accounting for temporary differences is reflected in rates,
deferred income taxes are recorded with related regulatory assets
and liabilities in accordance with SFAS 71.
<PAGE>
Investment Tax Credits - Investment tax credits have been accounted
for under the flow-through method except where regulatory
commissions have reflected investment tax credits in the rate-making process
on a deferral basis. Deferred investment tax
credits are being amortized over the life of the related plant
investment.
Debt and Preferred Stock - Gains and losses on reacquisition of
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.
Discount or premium and expenses of debt issuances are amortized
over the term of the related debt, with the amortization included
in interest charges.
Redemption premiums paid to reacquire preferred stock are included
in paid-in capital and amortized to retained earnings commensurate
with their recovery in rates. The excess of par value over costs
of preferred stock reacquired is credited to paid-in capital and
amortized to retained earnings.
Other Plant - Other plant is comprised primarily of the plant and
its related construction work in progress for midstream gas
operations, an Australian distribution company and a Chinese
generation project.
Other Property and Investments - Other property and investments are
comprised primarily of nuclear decommissioning and spent nuclear
fuel disposal trust funds; licenses for operating franchises and
goodwill for the Australian distribution company; amounts for
corporate owned life insurance and a related disputed tax payment;
and the investment in Yorkshire and Pacific Hydro which are
accounted for under the equity method of accounting. 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. Unrealized gains and losses from securities in these
trust funds are not reported in equity but result in adjustments to
the liability account for the nuclear decommissioning trust funds
and to regulatory assets or liabilities for the spent nuclear fuel
disposal trust funds. Excluding decommissioning and spent nuclear
fuel disposal trust funds and the investment in Yorkshire and
Pacific Hydro, other property and investments are stated at cost.
EPS - Earnings per share is determined based upon the weighted
average number of shares outstanding. There are no dilutive
potential common shares. Therefore, the computation of earnings
per share is the same for basic earnings per share and diluted
earnings per share.
Comprehensive Income - There were no material differences between
net income and comprehensive income.
Reclassification - In the fourth quarter of 1998 the Company
changed the presentation of its trading activities from a gross
basis (purchases and sales reported separately) to a net basis (net
amount from transactions reported as revenues). This
reclassification had no impact on net income. Certain prior year
amounts have been reclassified to conform to current year
presentation. Such reclassification had no impact on previously
reported net income.
2. Rate Matters:
OPCo's Recovery of Fuel Costs - Under the terms of a 1992
stipulation agreement the cost of coal burned at the Gavin Plant is
subject to a 15-year predetermined price of $1.575 per million
Btu's with quarterly escalation adjustments through November 2009.
A 1995 Settlement Agreement set the fuel component of the electric
fuel component (EFC) factor at 1.465 cents per Kwh for the period
June 1, 1995 through November 30, 1998. With the end of the period
covered by the 1995 Settlement Agreement, the escalated Gavin
predetermined price cap under the stipulation agreement will
determine Ohio jurisdictional fuel recoveries. To the extent the
actual cost of coal burned at the Gavin Plant is below the
predetermined prices, the stipulation agreement provides OPCo with
the opportunity to recover over its term the Ohio jurisdictional
share of OPCo's investment in and the liabilities and future shut-down costs
of its affiliated mines as well as any fuel costs
incurred above the predetermined rate. The Company announced plans
to close the Muskingum mine which supplies all of its output to
OPCo. The mine will be closed in October 1999 and efforts will
begin to reclaim the properties, sell or scrap all mining
equipment, terminate both capital and operating leases and perform
other miscellaneous activities necessary to shut down the mine.
Reclamation activities should be completed approximately two years
after shutdown, postremediation monitoring is anticipated to
continue for five years after completion of reclamation. The
Company established a liability for mine closing costs of $44.6
million comprised of a curtailment loss of $24.7 million,
provisions for workers compensation claims incurred through October
1998 of $4.7 million, severance costs of $4.1 million (related to
approximately 200 employees), postremediation monitoring costs of
$4.9 million, write-off of remaining materials and supplies of $4.6
million and other mine site closure costs of $1.6 million.
Pursuant to terms of the agreements, $18.5 million of these accrued
mine closure costs have been deferred for the Muskingum mine, the
remainder are included in fuel expense on the Consolidated
Statements of Income. For the three years ended December 31, 1998,
1997 and 1996 revenues and net income from the Muskingum mining
operation were $110.2 million and $1,000; $66.3 million and zero;
and $65.5 million and $1.8 million; respectively. After full
recovery of the deferrals or after November 2009, whichever comes
first, 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 market price at the time. Pursuant to these
agreements OPCo has deferred for future recovery $106 million at
December 31, 1998.
Based on the estimated future cost of coal burned at Gavin Plant,
management believes that the Ohio jurisdictional portion of the
investment in and liabilities and closing costs of the affiliated
mining operations including deferred amounts will be recovered
under the terms of the predetermined price agreement. Management
intends to seek from non-Ohio jurisdictional ratepayers recovery of
the non-Ohio jurisdictional portion of the investment in and the
liabilities and closing costs of the affiliated Meigs, Muskingum
and Windsor mines. The non-Ohio jurisdictional portion of shutdown
costs for these mines which includes the investment in the mines,
leased asset buy-outs, reclamation costs and employee benefits is
estimated to be approximately $100 million after tax at December
31, 1998.
Management anticipates closing the Windsor mine in December 2000 in
order to comply with the Phase II requirements of the Clean Air Act
Amendments of 1990 (CAAA) or it could close earlier depending on
the economics of continued operation under the terms of the above
stipulation agreement. Unless the cost of affiliated coal
production and/or shutdown costs of the Meigs, Muskingum and
Windsor mines can be recovered, results of operations, cash flows
and possibly financial condition would be adversely affected.
3. Effects of Regulation and Phase-In Plans:
In accordance with SFAS 71 the consolidated financial statements
include assets (deferred expenses) and liabilities (deferred
income) recorded in accordance with regulatory actions to match
expenses and revenues from cost-based rates. Regulatory assets are
expected to be recovered in future periods through the rate-making
process and regulatory liabilities are expected to reduce future
cost recoveries. Management has reviewed the evidence currently
available and concluded that it continues to meet the requirements
to apply SFAS 71. In the event a portion of the Company's business
no longer met these requirements, net regulatory assets would have
to be written off for that portion of the business and assets
attributable to that portion of the business would have to be
tested for possible impairment and if required an impairment loss
recorded unless the net regulatory assets and impairment losses are
recoverable as a stranded cost.
<PAGE>
Recognized regulatory assets and liabilities are comprised of the
following at:
December 31,
1998 1997
(in thousands)
Regulatory Assets:
Amounts Due From Customers For
Future Income Taxes $1,324,217 $1,372,926
Deferred Fuel Costs 193,430 75,552
Unamortized Loss on Reacquired Debt 90,997 96,793
Other 238,074 272,269
Total Regulatory Assets $1,846,718 $1,817,540
Regulatory Liabilities:
Deferred Investment Tax Credits $350,946 $376,250
Other Regulatory Liabilities* 147,569 78,802
Total Regulatory Liabilities $498,515 $455,052
* Included in Deferred Credits on Consolidated Balance Sheets
At January 1, 1997 rate phase-in plan deferrals existed for the
Zimmer Plant and Rockport Plant Unit 1. The Zimmer Plant is a
1,300 mw coal-fired plant which commenced commercial operation in
1991. CSPCo owns 25.4% of the plant with the remainder owned by
two unaffiliated companies. As a result of an Ohio Supreme Court
decision, in January 1994 the PUCO approved a temporary 3.39%
surcharge effective February 1, 1994. In June 1997 the Company
completed recovery of its Zimmer Plant phase-in plan deferrals and
discontinued the 3.39% temporary rate surcharge. In 1997 and 1996
$15.4 million and $31.5 million, respectively, of net phase-in
deferrals were collected through the surcharge.
The Rockport Plant consists of two 1,300 mw coal-fired units. I&M
and AEGCo each own 50% of one unit (Rockport 1) and lease a 50%
interest in the other unit (Rockport 2) from unaffiliated lessors
under an operating lease. The gain on the sale and leaseback of
Rockport 2 was deferred and is being amortized, with related taxes,
over the initial lease term which expires in 2022. Rate phase-in
plans in the Indiana and the FERC jurisdictions provided for the
recovery and straight-line amortization of deferred Rockport Plant
Unit 1 costs over a ten year period that ended in 1997. In 1997
and 1996 amortization and recovery of the deferred Rockport Plant
Unit 1 phase-in plan costs were $11.9 million and $15.6 million,
respectively. During the recovery period net income was unaffected
by the recovery of the phase-in deferrals.
4. Commitments and Contingencies:
Construction and Other Commitments - The AEP System has substantial
construction commitments to support its utility operations
including the replacement of the Cook Plant Unit 1 steam
generators. Such commitments do not presently include any
expenditures for new generating capacity. Aggregate construction
expenditures for 1999-2001 are estimated to be $2.4 billion
including construction cost estimates for the newly acquired
CitiPower and midstream gas assets.
Long-term domestic fuel supply contracts contain clauses for
periodic price adjustments, and most domestic 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
the year 2014, and contain various clauses that would release the
Company from its obligation under certain force majeure conditions.
The AEP System has contracted to sell approximately 1,100 mw of
capacity domestically on a long-term basis to unaffiliated
utilities. Certain contracts totaling 750 mw of capacity are unit
power agreements requiring the delivery of energy only if the unit
capacity is available. The power sales contracts expire from 1999
to 2010.
Nuclear Plant - I&M owns and operates the two-unit 2,110 mw Cook
Plant under licenses granted by the Nuclear Regulatory Commission
(NRC). 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 US, the resultant liability could be
substantial. By agreement I&M is partially liable together with
all other electric utility companies that own nuclear generating
units for a nuclear power plant incident. In the event nuclear
losses or liabilities are underinsured or exceed accumulated funds
and recovery in rates is not possible, results of operations, cash
flows and financial condition could be negatively affected.
Nuclear Plant Shutdown - I&M shut down both units of the Cook
Nuclear Plant in September 1997 due to questions, which arose
during a NRC architect engineer design inspection, regarding the
operability of certain safety systems. The NRC issued a
Confirmatory Action Letter in September 1997 requiring I&M to
address the issues identified in the letter. I&M is working with
the NRC to resolve the remaining open issue in the letter.
In April 1998 the NRC notified I&M that it had convened a Restart
Panel for Cook Plant. A list of required restart activities was
provided by the NRC in July 1998 and in October the NRC expanded
the list. In order to identify and resolve the issues necessary to
restart the Cook units, I&M is and will be meeting with the Panel
on a regular basis, until the units are returned to service.
In January 1999 I&M announced that it will conduct additional
engineering reviews at the Cook Plant that will delay restart of
the units. Previously, the units were scheduled to return to
service at the end of the first and second quarters of 1999. The
decision to delay restart resulted from internal assessments that
indicated a need to conduct expanded system readiness reviews. A
new restart schedule will be developed based on the results of the
expanded reviews and should be available in June 1999. When
maintenance and other activities required for restart are complete,
I&M will seek concurrence from the NRC to return the Cook Plant to
service. Until these additional reviews are completed, management
is unable to determine when the units will be returned to service.
Unless the costs of the extended outage and restart efforts are
recovered from customers, there would be a material adverse effect
on results of operations, cash flows and possibly financial
condition.
The incremental cost incurred in 1997 and 1998 for restart of the
Cook units were $6 million and $78 million, respectively, and
recorded as operation and maintenance expense. Currently
incremental restart expenses are approximately $12 million a month.
In July 1998 I&M received an "adverse trend letter" from the NRC
indicating that NRC senior managers determined that there had been
a slow decline in performance at the Cook Plant during the 18 month
period preceding the letter. The letter indicated that the NRC
will closely monitor efforts to address issues at Cook Plant
through additional inspection activities. In October 1998 the NRC
issued I&M a Notice of Violation and proposed a $500,000 civil
penalty for alleged violations at the Cook Plant discovered during
five inspections conducted between August 1997 and April 1998. I&M
paid the penalty.
The cost of electricity supplied to certain retail customers rose
due to the outage of the two units since higher cost coal-fired
generation and coal based purchased power were substituted for low
cost nuclear generation. I&M's Indiana and Michigan retail
jurisdictional fuel cost recovery mechanisms permit the recovery,
subject to regulatory commission review and approval, of changes in
fuel costs including the fuel component of purchased power in the
Indiana jurisdiction and changes in replacement power in the
Michigan jurisdiction. The Indiana Utility Regulatory Commission
approved, subject to future reconciliation or refund, agreements
authorizing I&M, during the billing months of July 1998 through
March 1999, to include in rates a fuel cost adjustment factor less
than that requested by I&M. The agreements provide the parties to
the proceedings with the opportunity to conduct discovery regarding
certain issues that were raised in the proceedings, including the
appropriateness of the recovery of replacement energy cost due to
the extended Cook Plant outage, in anticipation of resolving the
issues in a future fuel cost adjustment proceeding. A regulatory
asset in the amount of $65 million has been recorded at December
31, 1998.
Historically, the Company has been permitted to recover through the
fuel recovery mechanism the cost of replacement energy during
outages. Management believes that it should be allowed to recover
the deferred Cook replacement energy costs; however, if recovery of
the replacement costs is denied, future results of operations and
cash flows would be adversely affected by the writeoff of the
regulatory asset.
Nuclear Incident Liability - Public liability is limited by law to
$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 US the remainder of the liability would be
provided by a deferred premium assessment of $88 million on each
licensed reactor payable in annual installments of $10 million. As
a result, I&M could be assessed $176 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
billion of property damage, decommissioning and decontamination
coverage for the Cook Plant. Additional insurance provides
coverage for extra costs resulting from a prolonged accidental Cook
Plant outage. Some of the policies have deferred premium
provisions which could be triggered by losses in excess of the
insurer's resources. The losses could result from claims at the
Cook Plant or certain other unaffiliated nuclear units. I&M could
be assessed up to $23.2 million annually under these policies.
Spent Nuclear Fuel (SNF) Disposal - Federal law provides for
government responsibility for permanent SNF disposal and assesses
nuclear plant owners fees for SNF disposal. A fee of one mill per
kilowatthour for fuel consumed after April 6, 1983 is being
collected from customers and remitted to the US Treasury. Fees and
related interest of $190 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, 1998, funds collected from customers towards payment of the
pre-April 1983 fee and related earnings thereon approximate the
liability.
Decommissioning and Low Level Waste Accumulation Disposal -
Decommissioning costs are accrued over the service life of the Cook
Plant. The licenses to operate the two nuclear units expire in
2014 and 2017. After expiration of the licenses the plant is
expected to be decommissioned through dismantlement. The Company's
latest estimate for decommissioning and low level radioactive waste
accumulation disposal costs ranges from $700 million to $1,152
million in 1997 nondiscounted dollars. The wide range is caused by
variables in assumptions including the estimated length of time SNF
may need to be stored at the plant site subsequent to ceasing
operations. This, in turn, depends on future developments in the
federal government's SNF disposal program. Continued delays in the
federal fuel disposal program can result in increased
decommissioning costs. I&M is recovering estimated decommissioning
costs in its three rate-making jurisdictions based on at least the
lower end of the range in the most recent decommissioning study at
the time of the last rate proceeding. I&M records decommissioning
costs in other operation expense and records an increase in its
noncurrent liabilities equal to the decommissioning cost recovered
in rates; such amounts were $29 million in 1998, $28 million in
1997 and $27 million in 1996. Decommissioning costs recovered from
customers are deposited in external trusts. Trust fund earnings
increase the fund assets and the recorded liability and decrease
the amount needed to be recovered from ratepayers. During 1998 I&M
withdrew $3 million and expects to withdrawal $8 million in 1999
for decommissioning of original steam generators removed from Unit
2. At December 31, 1998 and 1997, I&M has recognized a
decommissioning liability of $446 million and $381 million,
respectively, which is included in other noncurrent liabilities.
Clean Air Act/Air Quality - The US Environmental Protection Agency
(Federal EPA) is required by the CAAA to issue rules to implement
the law. In 1996 Federal EPA issued final rules governing nitrogen
oxides (NOx) emissions that must be met after January 1, 2000
(Phase II of CAAA). The final rules will require substantial
reductions in NOx emissions from certain types of boilers including
those in AEP's power plants. To comply with Phase II of CAAA, the
Company plans to install NOx emission control equipment on certain
units and switch fuel at other units. Total capital costs to meet
the requirements of Phase II of CAAA are estimated to be
approximately $90 million of which $69 million has been incurred
through December 31, 1998.
On September 24, 1998, Federal EPA finalized rules which require
reductions in NOx emissions in 22 eastern states, including the
states in which the Company's generating plants are located. The
implementation of the final rules would be achieved through the
revision of state implementation plans (SIPs) by September 1999.
SIPs are a procedural method used by each state to comply with
Federal EPA rules. The final rules anticipate the imposition of a
NOx reduction on utility sources of approximately 85% below 1990
emission levels by the year 2003. On October 30, 1998, a number of
utilities, including the operating companies of the AEP System,
filed petitions in the US Court of Appeals for the District of
Columbia Circuit seeking a review of the final rules.
Should the states fail to adopt the required revisions to their
SIPs within one year of the date of the final rules (September 24,
1999), Federal EPA has proposed to implement a federal plan to
accomplish the NOx reductions. Federal EPA also proposed the
approval of portions of petitions filed by eight northeastern
states that would result in imposition of NOx emission reductions
on utility and industrial sources in upwind midwestern states.
These reductions are substantially the same as those required by
the final NOx rules and could be adopted by Federal EPA in the
event the states fail to implement SIPs in accordance with the
final rules.
Preliminary estimates indicate that compliance costs could result
in required capital expenditures of approximately $1.2 billion for
the AEP System. Compliance costs cannot be estimated with
certainty and the actual costs incurred to comply could be
significantly different from this preliminary estimate depending
upon the compliance alternatives selected to achieve reductions in
NOx emissions. Unless such costs are recovered from customers,
they would have a material adverse effect on results of operations,
cash flows and possibly financial condition.
Litigation - The Internal Revenue Service (IRS) agents auditing the
AEP System's consolidated federal income tax returns requested a
ruling from their National Office that certain interest deductions
claimed by the Company relating to AEP's corporate owned life
insurance (COLI) program should not be allowed. As a result of a
suit filed in US District Court (discussed below) this request for
ruling was withdrawn by the IRS agents. Adjustments have been or
will be proposed by the IRS disallowing COLI interest deductions
for taxable years 1991-96. A disallowance of the COLI interest
deductions through December 31, 1998 would reduce earnings by
approximately $316 million (including interest). The Company has
made no provision for any possible adverse earnings impact from
this matter.
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years 1991-97
to avoid the potential assessment by the IRS of any additional
above market rate interest on the contested amount. The payments
to the IRS are included on the balance sheet in other property and
investments pending the resolution of this matter. The Company
will seek refund, either administratively or through litigation, of
all amounts paid plus interest. In order to resolve this issue
without further delay, on March 24, 1998, the Company filed suit
against the US in the US District Court for the Southern District
of Ohio. Management believes that it has a meritorious position
and will vigorously pursue this lawsuit. In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations, cash flows and possibly
financial condition.
The Company is involved in a number of other 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, cash flows or financial condition.
5. Proposed Merger
In December 1997 the Company and Central and South West Corporation
(CSW) agreed to merge. At the 1998 annual meeting AEP shareholders
approved the issuance of common shares to effect the merger and
approved an increase in the number of authorized shares of AEP
Common Stock from 300,000,000 to 600,000,000 shares. CSW
stockholders approved the merger at their May 1998 annual meeting.
Approval of the merger has been requested from the FERC, the SEC,
the NRC and all of CSW's state regulatory commissions: Arkansas,
Louisiana, Oklahoma and Texas. In the near future, AEP and CSW
plan to make the final two filings associated with approval of the
merger with the Federal Communications Commission and the
Department of Justice.
Regulatory approvals for the merger have been received from the
Arkansas Public Service Commission (APSC) and the NRC. In December
1998 the APSC approved a stipulated agreement related to a proposed
merger regulatory plan submitted by the Company, CSW and CSW's
Arkansas operating subsidiary, Southwestern Electric Power Company.
The regulatory plan, agreed to with the APSC staff, provides for a
sharing of net merger savings through a $6 million rate reduction
over 5 years following the completion of the merger.
The application to the NRC by CSW's operating subsidiary, Central
Power and Light Company (CPL), requesting permission to transfer
indirect control of the license from CSW to AEP for CPL's interest
in the South Texas Project nuclear generating station was approved
by the NRC in November 1998.
In October 1998 the Oklahoma Corporation Commission (OCC) approved
plans by AEP and CSW to submit an amended filing seeking approval
of the proposed merger. The amended application is being made as
a result of an Oklahoma administrative law judge's recommendation
that the merger filing be dismissed without prejudice for lack of
sufficient information regarding the potential impact of the merger
on the retail electric market in Oklahoma. An amended application
was filed in Oklahoma in February 1999. Submission of the amended
application will reset Oklahoma's 90-day statutory time period for
OCC action on the merger phase of the application.
A settlement agreement between AEP, CSW and certain key parties to
the Texas merger proceeding has been reached. The staff of the
Public Utility Commission of Texas was not a signatory to the
settlement agreement, which resolves all issues for the
signatories. The settlement provides for, among other things, rate
reductions totaling approximately $180 million over a six year
period following completion of the merger to share net merger
savings of $84 million and settle existing rate issues of $96
million. Hearings are scheduled for April 1999.
In July 1998 the FERC issued an order which confirmed that a 250
megawatt firm contract path with the Ameren System is available.
The contract path was obtained by AEP and CSW to meet the
requirement of the 1935 Act that the two systems operate on an
integrated and coordinated basis.
In November 1998 the FERC issued an order establishing hearing
procedures for the merger and scheduled the hearings to begin on
June 1, 1999. The FERC order indicated that the review of the
proposed merger will address the issues of competition, market
power and customer protection and instructed the companies to
refile an updated market power study which was done in January
1999.
The proposed merger of CSW into AEP would result in common
ownership of two UK regional electricity companies (RECs),
Yorkshire and Seeboard, plc. AEP has a 50% interest in Yorkshire
and CSW has a 100% interest in Seeboard. Although the merger of
CSW into AEP is not subject to approval by UK regulatory
authorities, the common ownership of two UK RECs could be referred
by the UK Secretary of State for Trade and Industry to the UK
Monopolies and Mergers Commission for investigation.
AEP has received a request from the staff of the Kentucky Public
Service Commission (KPSC) to file an application seeking KPSC
approval for the indirect change in control of Kentucky Power
Company that will occur as a result of the proposed merger.
Although AEP does not believe that the KPSC has the jurisdictional
authority to approve the merger, management will prepare a merger
application filing to be made with the KPSC, which is expected to
be filed by April 15, 1999. Under the governing statute the KPSC
must act on the application within 60 days. Therefore this is not
expected to impact the timing of the merger.
The merger is conditioned upon, among other things, the approval of
the above state and federal regulatory agencies. The transaction
must satisfy many conditions a number of which may not be waived by
the parties, including the condition that the merger must be
accounted for as a pooling of interests. The merger agreement will
terminate on December 31, 1999 unless extended by either party as
provided in the merger agreement. Although consummation of the
merger is expected to occur in the fourth quarter of 1999, the
Company is unable to predict the outcome or the timing of the
required regulatory proceedings.
As of December 31, 1998 the Company had deferred $20 million of
incremental costs incurred in connection with the proposed merger.
The amounts deferred are included in deferred charges on the
Consolidated Balance Sheets.
6. Acquisitions
The Company completed two non-regulated energy related acquisitions
in 1998 through a subsidiary, AEPR. Both acquisitions have been
included in the December 31, 1998 consolidated financial statements
using the purchase method of accounting. The first acquisition was
of CitiPower, an Australian distribution utility, that serves
approximately 240,000 customers in Melbourne with 3,100 miles of
distribution lines in a service area of approximately 100 square
miles. All of the stock of CitiPower was acquired on December 31,
1998 for approximately $1.1 billion. The acquisition of CitiPower
had no effect on the results of operations for 1998. The financial
statements reflect a preliminary purchase price allocation.
Estimated goodwill of $557 million has been recorded in other
property and investments which will be amortized over a period of
not more than 40 years.
The second acquisition was of midstream gas operations that include
a fully integrated natural gas gathering, processing, storage and
transportation operation in Louisiana and a gas trading and
marketing operation in Houston. The gas operations were acquired
for approximately $340 million, including working capital funds, on
December 1, 1998 with one month of earnings reflected in AEP's
consolidated results of operations for the year ended December 31,
1998. The financial statements reflect a preliminary purchase
price allocation. Estimated goodwill of approximately $158 million
for the midstream gas storage operations and $17 million for the
gas trading and marketing operation has been recorded in other
property and investments and is being amortized on a straight-line
basis over not more than 40 years and 10 years, respectively.
7. Yorkshire Acquisition and UK Windfall Tax
In April 1997 the Company and New Century Energies, Inc. through an
equally owned joint venture, Yorkshire Power Group Limited (YPG),
acquired all of the outstanding shares of Yorkshire. Total
consideration paid by the joint venture was approximately $2.4
billion which was financed by a combination of equity and non-recourse debt.
The Company uses the equity method of accounting
for its investment in YPG. The Company's investment in the joint
venture was $325.8 million and $287.4 million at December 31, 1998
and 1997, respectively, and is included in other property and
investments.
In July 1997 the British government enacted a new law that imposed
a one-time windfall tax on a revised privatization value which
originally had been computed in 1990 on certain privatized
utilities. The windfall tax is actually an adjustment by the UK
government of the original privatization price. The windfall tax
liability for Yorkshire was 134 million pounds sterling ($219
million) and was paid in two equal installments made in December
1997 and December 1998. The Company's $109.4 million share of the
tax is reported as an extraordinary loss in 1997.
The 1998 equity earnings from the Yorkshire investment are $38.5
million and are included in nonoperating income. Equity earnings
from the Yorkshire investment for 1997, excluding the extraordinary
loss, were $34 million.
The following amounts which are not included in AEP's consolidated
financial statements represent summarized consolidated financial
information of YPG:
December 31,
1998 1997
(in millions)
Assets:
Property, Plant and Equipment $1,602.2 $1,644.6
Current Assets 552.2 602.2
Goodwill (net) 1,547.3 1,602.5
Other Assets 294.5 292.9
Total Assets $3,996.2 $4,142.2
Capitalization and Liabilities:
Common Shareholders' Equity $ 666.4 $ 542.1
Long-term Debt 2,121.3 704.3
Other Noncurrent Liabilities 413.5 488.7
Long-term Debt Within One Year 13.3 1,776.4
Current Liabilities 781.7 630.7
Total Capitalization and
Liabilities $3,996.2 $4,142.2
Twelve Months Ended Nine Months Ended
December 31, 1998 December 31, 1997
(in millions)
Income Statement Data:
Operating Revenues $2,284.0 $1,492.9
Operating Income 298.0 202.3
Income Before
Extraordinary Item 76.9 67.5
Net Income (Loss) 76.9 (151.3)
8. Staff Reductions
During 1998 an internal evaluation of the power generation
organization was conducted with a goal of developing an optimum
organizational structure for a competitive generation market. The
study was completed in October 1998 and called for the elimination
of approximately 450 positions. In addition, a review of energy
delivery staffing levels in 1998 identified 65 positions for
elimination.
Severance accruals totaling $25.5 million were recorded in December
1998 for reductions in power generation and energy delivery staffs
and were charged to other operation expense in the Consolidated
Statements of Income. In January 1999, employment terminated for
65 energy delivery employees. In February 1999 the power
generation staff reductions were made.
9. Benefit Plans:
AEP System Pension and Other Postretirement Benefit Plans - The AEP
System sponsors a qualified pension plan and a nonqualified pension
plan. All employees, except participants in the United Mine
Workers of America (UMWA) pension plans are covered by one or both
of the pension plans. Other Postretirement Benefit Plans (OPEB)
are sponsored by the AEP System to provide medical and death
benefits for retired employees.
<PAGE>
The following tables provide a reconciliation of the changes in the
plans' benefit obligations and fair value of assets over the two-year
period ending December 31, 1998, and a statement of the funded
status as of December 31 for both years:
Pension Plan OPEB
1998 1997 1998 1997
(in thousands)
Reconciliation of benefit
obligation:
Obligation at January 1 $1,909,400 $1,676,200 $ 849,700 $726,400
Service Cost 45,100 36,000 17,500 14,000
Interest Cost 133,200 128,600 59,300 55,900
Participant Contributions - - 5,900 5,300
Plan Amendments (a) 48,400 - - -
Actuarial Loss 96,000 170,500 133,100 90,900
Acquisitions (b) 100 - 2,800 -
Benefit Payments (105,900) (101,900) (46,600) (42,800)
Obligation at December 31 $2,126,300 $1,909,400 $1,021,700 $849,700
Reconciliation of fair value
of plan assets:
Fair value of plan assets at
January 1 $2,370,300 $2,009,500 $311,900 $232,500
Actual Return on Plan Assets 385,900 462,700 52,600 44,100
Company Contributions 400 - 72,600 72,800
Participant Contributions - - 5,900 5,300
Benefit Payments (105,900) (101,900) (46,600) (42,800)
Fair value of plan assets at
December 31 $2,650,700 $2,370,300 $396,400 $311,900
Funded status:
Funded status at December 31 $ 524,400 $ 460,900 $(625,300)$(537,800)
Unrecognized Net Transition
(Asset) Obligation (49,200) (59,100) 360,700 416,400
Unrecognized Prior-Service Cost 157,400 123,500 - -
Unrecognized Actuarial
(Gain) Loss (756,300) (640,800) 175,000 66,100
Accrued Benefit Liability $(123,700) $(115,500) $ (89,600)$ (55,300)
(a) Early retirement factors for the Company pension plan were changed to
provide more generous benefits to participants retiring between ages
55 and 60.
(b) On December 1, 1998 the Company acquired midstream gas operations resulting
in approximately 170 new employees becoming participants in the Company's
pension and OPEB plans.
<PAGE>
The following table provides the amounts recognized in the
consolidated balance sheets as of December 31 of both years:
Pension Plan OPEB
1998 1997 1998 1997
(in thousands)
Accrued Benefit Liability $(123,700) $(115,500) $(89,600) $(55,300)
Additional Minimum Liability (3,400) (900) - -
Intangible Asset 3,400 900 - -
Net Amount Recognized $(123,700) $(115,500) $(89,600) $(55,300)
The Company's nonqualified pension plan had an accumulated benefit
obligation in excess of plan assets of $25 million and $19.4
million at December 31, 1998 and 1997, respectively. There are no
plan assets in the nonqualified plan due to the nature of the plan.
The Company's OPEB plans had accumulated benefit obligations in
excess of plan assets of $625.3 million and $537.8 million at
December 31, 1998 and 1997, respectively.
The following table provides the components of net periodic benefit
cost for the plans for fiscal years 1998 and 1997:
Pension Plan OPEB
1998 1997 1998 1997
(in thousands)
Service cost $ 45,100 $ 36,000 $ 17,500 $ 14,000
Interest cost 133,200 128,600 59,300 55,900
Expected return on
plan assets (172,000) (154,200) (28,500) (22,200)
Amortization of transition
(asset) obligation (9,900) (9,900) 32,000 32,000
Amortization of prior-service
cost 14,400 13,800 - -
Amortization of net actuarial
(gain) loss (2,600) (4,700) 200 (400)
Net periodic benefit cost 8,200 9,600 80,500 79,300
Curtailment loss - - 24,100(a) -
Net periodic benefit cost
after curtailments $ 8,200 $ 9,600 $104,600 $ 79,300
(a) Curtailment charges were recognized during 1998 in anticipation of the
October 31, 1999 shutdown of Muskingum Mine by Central Ohio Coal Company, a
subsidiary of AEP.
The assumptions used in the measurement of the Company's benefit
obligation are shown in the following table:
Pension Plan OPEB
1998 1997 1998 1997
Weighted-average assumptions
as of December 31
Discount rate 6.75% 7.00% 6.75% 7.00%
Expected return on plan assets 9.00% 9.00% 8.75% 8.75%
Rate of compensation increase 3.2% 3.2% N/A N/A
<PAGE>
For measurement purposes, a 5.5% annual rate of increase in the per
capita cost of covered health care benefits was assumed for 1999.
The rate was assumed to decrease gradually each year to a rate of
4.25% for 2005 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on
the amounts reported for the OPEB health care plans. A 1% change
in assumed health care cost trend rates would have the following
effects:
1% Increase 1% Decrease
(in thousands)
Effect on total of service and
interest cost components of
net periodic postretirement
health care benefit cost $ 9,700 $ (8,400)
Effect on the health care
component of the accumulated
postretirement benefit obligation 113,000 (99,800)
CitiPower, a subsidiary acquired on December 31, 1998 sponsors a
defined benefit pension plan. At December 31, 1998, the fair value
of the plan assets was $24.6 million and the accumulated benefit
obligation of this plan was $25.3 million. This plan's actuarial
assumptions are not significantly different from AEP's.
AEP System Savings Plan - The AEP System Savings Plan is a defined
contribution plan offered to non-UMWA employees. The cost for
contributions to this plan totaled $20.5 million in 1998, $19.6
million in 1997 and $19 million in 1996.
Other UMWA Benefits - The Company provides UMWA pension, health and
welfare benefits for certain unionized mining employees, retirees,
and their survivors who meet eligibility requirements. The
benefits are administered by UMWA trustees and contributions are
made to their trust funds. Contributions based on hours worked are
expensed as paid as part of the cost of active mining operations
and were not material in 1998, 1997 and 1996. Based upon the UMWA
actuary estimate, the Company's share of unfunded pension liability
was $28 million at June 30, 1998. In the event the Company should
significantly reduce or cease mining operations or contributions to
the UMWA trust funds, a withdrawal obligation will be triggered for
both the pension and health and welfare plans. If the mining
operations had been closed on December 31, 1998 the estimated
annual withdrawal liability for all UMWA benefit plans would have
been $6.5 million. The UMWA withdrawal liability for the
anticipated shutdown of Central Ohio Coal Company's Muskingum mine
has been included as a curtailment loss in the net periodic benefit
cost under the Company's OPEB plans in 1998.
10. Business Segments
As of December 31, 1998, the Company adopted SFAS 131, "Disclosure
about Segments of an Enterprise and Related Information." SFAS 131
established standards for reporting information about operating
segments in annual financial statements and requires selected
information about operating segments in interim financial reports
issued to shareholders. It also established standards for related
disclosures about products and services, and geographic areas.
Operating segments are defined as components of an enterprise about
which separate financial information is available and evaluated
regularly by the chief operating decision maker.
The Company's reportable segments are primarily differentiated
based on whether the business activity is conducted within a
regulated environment. The Company manages its operations on this
basis because of the substantial impact of regulatory oversight on
business processes, cost structures and operating results.
The Company's principal business segment is its cost based rate
regulated Domestic Electric Utilities business consisting of seven
regulated utility operating companies providing retail, commercial,
industrial and wholesale electric services in seven Atlantic and
Midwestern states. Also included in this segment are the Company's
electric power wholesale marketing and trading activities that are
conducted as part of regulated operations and subject to regulatory
ratemaking oversight. The World Wide Energy Investments segment
represents principally international investments in energy-related
projects and operations. It also includes the development and
management of such projects and operations. Such investment
activities include electric generation, supply and distribution,
and natural gas pipeline, storage and other natural gas services.
Other business segments include non-regulated electric and gas
trading activities, telecommunication services, and the marketing
of various energy saving products and services. Intersegment
revenues, ie. revenues from transactions with operating segments,
are not material. As of December 31, 1998 and 1997 less than 6% of
long-lived assets were located in foreign countries.
<TABLE>
<CAPTION>
World
Regulated Domestic Wide Energy Reconciling AEP
Year Electric Utilities Investments Other Adjustments Consolidated
<S> <C> <C> <C> <C> <C>
(in thousands)
1998
Revenues from
external customers $6,345,900 $57,600 $(28,300) $(29,300) $6,345,900
Revenues from transactions
with other operating
segments - 1,600 1,900 (3,500) -
Interest revenues 400 200 600
Interest expense 399,200 16,900 3,000 419,100
Depreciation, depletion and
amortization expense 580,000 1,000 1,400 (2,400) 580,000
Net income (loss) for equity
method subsidiaries - 38,600 - 38,600
Income tax expense (benefit) 299,100 (15,300) (21,200) 262,600
Segment net income (loss) 563,400 12,300 (39,500) 536,200
Total assets 16,837,300 2,063,300 582,600 19,483,200
Investments in equity method
subsidiaries 100 335,200 - 335,300
Gross property additions 699,700 1,481,000 23,000 2,203,700
1997
Revenues from
external customers $5,879,800 $14,600 $ 2,200 $(16,800) $5,879,800
Revenues from transactions
with other operating
segments - - - - -
Interest revenues - 1,700 - 1,700
Interest expense 390,300 14,900 600 405,800
Depreciation, depletion and
amortization expense 591,100 - - - 591,100
Net income for equity method
subsidiaries - 33,300 - - 33,300
Income tax expense (benefit) 330,100 (25,000) (6,600) 298,500
Extraordinary Loss -
UK Windfall Tax - (109,400) - - (109,400)
Segment net income (loss) 602,900 (79,600) (12,300) 511,000
Total assets 16,223,700 367,100 24,500 16,615,300
Investments in equity method
subsidiaries 100 287,300 - 287,400
Gross property additions 694,400 62,400 3,600 760,400
1996
Revenues from
external customers $5,849,200 $12,500 $ - $(12,500) $5,849,200
Revenues from transactions
with other operating
segments - 100 - (100) -
Interest revenues - - - - -
Interest expense 381,000 300 - - 381,300
Depreciation, depletion and
amortization expense 600,900 - - - 600,900
Income tax expense (benefit) 325,500 (1,000) (1,900) 322,600
Segment net income (loss) 597,600 (6,600) (3,600) 587,400
Total assets 15,858,900 5,100 19,000 15,883,000
Investments in equity method
subsidiaries 100 - - 100
Gross property additions 577,700 - - 577,700
</TABLE>
11. Financial Instruments, Credit and Risk Management
The Company is subject to market risk as a result of changes in
commodity prices, foreign currency exchange rates, and interest
rates. The Company has a wholesale electricity and gas trading and
marketing operation that manages the exposure to commodity price
movements using physical forward purchase and sale contracts at
fixed and variable prices, and financial derivative instruments
including exchange traded futures and options, over-the-counter
options, swaps and other financial derivative contracts at both
fixed and variable prices. Physical forward electricity contracts
and certain qualifying hedges within AEP's traditional economic
market area are recorded as net operating revenues in the month
when the physical contract settles. Net gains for the year ended
December 31, 1998 were $111 million. Physical forward electricity
contracts outside AEP's traditional marketing area, and all
financial electricity trading transactions which do not qualify as
a hedge, and/or where the underlying physical commodity is outside
AEP's traditional economic market area are marked to market and
recorded net in nonoperating income. Net losses for the year ended
December 31, 1998 were $37 million. All physical and financial
instruments for natural gas are marked to market and are included
on a net basis in nonoperating income. Net gains for the year
ended December 31, 1998 were $6 million. The unrealized mark-to-market
gains and losses from such trading of financial instruments
are reported as assets and liabilities, respectively. These
activities were not material in prior periods.
Investment in foreign ventures exposes the Company to risk of
foreign currency fluctuations. Also, the Company is exposed to
changes in interest rates primarily due to short- and long-term
borrowings used to fund its business operations. The debt
portfolio has both fixed and variable interest rates with terms
from one day to forty years and an average duration of 5 years at
December 31, 1998. The Company does not presently utilize
derivatives to manage its exposures to foreign currency exchange
rate movements.
Market Valuation - The book value 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. The book value amount of the pre-April 1983
spent nuclear fuel disposal liability approximates the Company's
best estimate of its fair value.
The book value amounts and fair values of the Company's significant
financial instruments at December 31, 1998 are summarized in the
following table. The fair values of long-term debt and preferred
stock 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 fair value of
those financial instruments that are marked-to-market are based on
management's best estimates using over-the-counter quotations,
exchange prices, volatility factors and valuation methodology. The
estimates presented herein are not necessarily indicative of the
amounts that the Company could realize in a current market
exchange.
<PAGE>
Book Value Fair Value
(in thousands)
Non-Derivatives
1998
Long-term Debt $7,006,100 $7,291,200
Preferred Stock 127,600 134,100
1997
Long-term Debt 5,423,900 5,670,400
Preferred Stock 127,600 136,000
Derivatives
Trading Assets
Notional Amount Fair Value Average Fair Value
(in thousands)
Electric
Physicals $ (62,000) $ 46,100 $ 40,800
Options (4,700) 32,200 79,000
Swaps (15,600) 3,400 1,000
Gas
Futures (70,300) 5,900 1,900
Physicals (285,200) 43,600 29,900
Options (3,600) 18,000 11,700
Swaps 1,477,900 245,600 143,000
Trading Liabilities
Electric
Futures 20,300 (7,200) (1,800)
Physicals 27,500 (50,600) (46,300)
Options 9,700 (28,700) (78,300)
Swaps 16,200 (7,700) (1,900)
Gas
Physicals 283,900 (42,400) (28,700)
Options 4,700 (22,600) (14,100)
Swaps (1,524,900) (231,200) (135,700)
At December 31, 1998 the fair value of the assets and liabilities
related to the wholesale electric forward contracts was $367
million and $356 million, respectively. The respective notional
amounts were $828 million and $772 million, respectively. The
average fair value amounts outstanding during the period were $922
million of assets and $882 million of liabilities.
AEP routinely enters into exchange traded futures and options
transactions for electricity and natural gas as part of its
wholesale trading operations. These transactions are executed
through brokerage accounts with brokers who are registered with the
Commodity Futures Trading Commission. Brokers require cash or cash
related instruments to be deposited on these accounts as margin
calls against the customer's open position. The amount of these
deposits at December 31, 1998 was $10 million.
Credit and Risk Management - In addition to market risk associated
with price movements, AEP is also subject to the credit risk
inherent in its risk management activities. Credit risk refers to
the financial risk arising from commercial transactions and/or the
intrinsic financial value of contractual agreements with trading
counter parties, by which there exists a potential risk of
nonperformance. The Company has established and enforced credit
policies that minimize or eliminate this risk. AEP accepts as
counter parties to forwards, futures, and other derivative
contracts primarily those entities that are classified as
Investment Grade, or those that can be considered as such due to
the effective placement of credit enhancements and/or collateral
agreements. Investment Grade is the designation given to the four
highest debt rating categories (i.e., AAA, AA, A, BBB) of the major
rating services, e.g., ratings BBB- and above at Standard & Poor's
and Baa3 and above at Moody's. When adverse market conditions have
the potential to negatively affect a counter party's credit
position, the Company will require further enhancements to mitigate
risk. Since the formation of the trading business in July of 1997,
the Company has experienced no significant losses due to the credit
risk associated with its risk management activities; furthermore,
the Company does not anticipate any future material effect on its
results of operations, cash flow or financial condition as a result
of counter party nonperformance.
Other Financial Instruments - Nuclear Trust Funds Recorded at
Market Value - The trust investments, reported in other property
and investments, are recorded at market value in accordance with
SFAS 115 and consist of tax-exempt municipal bonds and other
securities.
At December 31, 1998 and 1997 the fair values of the trust
investments were $648 million and $566 million, respectively, and
had a cost basis of $584 million and $527 million, respectively.
Accumulated gross unrealized holding gains were $65 million and $41
million at December 31, 1998 and 1997, respectively and accumulated
gross unrealized holding losses were $1.1 million and $1.2 million
at December 31, 1998 and 1997, respectively. The change in market
value in 1998, 1997, and 1996 was a net unrealized holding gain of
$24 million, $19.1 million, and $2.6 million, respectively.
<PAGE>
The trust investments' cost basis by security type were:
December 31,
1998 1997
(in thousands)
Tax-Exempt Bonds $326,239 $335,358
Equity Securities 95,854 74,398
Treasury Bonds 71,194 44,200
Corporate Bonds 10,661 9,167
Cash, Cash Equivalents and
Accrued Interest 80,065 63,392
Total $584,013 $526,515
Proceeds from sales and maturities of securities of $225 million
during 1998 resulted in $8.2 million of realized gains and $2.8
million of realized losses. Proceeds from sales and maturities of
securities of $147.3 million during 1997 resulted in $3.9 million
of realized gains and $1.4 million of realized losses. 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. The cost of securities for determining realized
gains and losses is original acquisition cost including amortized
premiums and discounts.
At December 31, 1998, the year of maturity of trust fund
investments other than equity securities, was:
(in thousands)
1999 $106,316
2000 - 2003 157,224
2004 - 2008 175,751
After 2008 48,868
Total $488,159
An AEP Resources' subsidiary established a non-recourse variable-rate credit
facility in the aggregate amount of $775 million on
December 31, 1998. Certain assets of the subsidiary support the
facility. The facility is comprised of three tranches: $244
million maturing on December 31, 2000, $488 million maturing on
December 31, 2003, and a $43 million short-term capital facility.
As of December 31, 1998 $732 million were outstanding at an average
interest rate of 5.833%.
The subsidiary entered into several interest rate swap agreements
for $586 million of the borrowings under the credit facility. The
swap agreements involve the exchange of floating-rate for fixed-rate
interest payments. Interest is recognized currently based on
the fixed rate of interest resulting from use of these swap
agreements. Market risks arise from the movements in interest
rates. If counterparties to an interest rate swap agreement were
to default on contractual payments, the subsidiary could be exposed
to increased costs related to replacing the original agreement.
However, the subsidiary does not anticipate non-performance by any
counterparty to any interest rate swap in effect as of December 31,
1998. As of December 31, 1998, the subsidiary was a party to
interest rate swaps having a aggregate notional amount of $586
million, with $342 million maturing on December 31, 2000, and $244
million maturing on December 31, 2003. The average fixed interest
rate payable on the aggregate of the interest rate swaps is 5.32%.
The floating rate for interest rate swaps was 4.9% at December 31,
1998. The estimated fair value of the interest rate swaps, which
represents the estimated amount the subsidiary would pay to
terminate the swaps at December 31, 1998, based on quoted interest
rates, is a net liability of $5 million.
In accordance with the debt covenants included in the financing
provisions of this facility, the subsidiary must hedge at least 80%
of its energy purchase requirements through energy trading
derivative instruments entered into with market participants,
predominantly generators. As of December 31, 1998, the subsidiary
had outstanding energy trading derivatives with a total contracted
load of 12,545 GWh's. These contracts have maturities in the range
of 3 months to twelve years. Management's estimate of the fair
value of these derivatives as of December 31, 1998, is $3.3 million
in excess of book value.
12. Federal Income Taxes:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1998 1997 1996
(in thousands)
Charged (Credited) to Operating Expenses (net):
Current $294,139 $346,290 $375,528
Deferred 37,877 11,124 (17,008)
Deferred Investment Tax Credits (15,815) (16,134) (16,298)
Total 316,201 341,280 342,222
Charged (Credited) to Nonoperating Income (net):
Current (47,718) (16,038) (5,636)
Deferred 3,572 (17,673) (4,470)
Deferred Investment Tax Credits (9,489) (9,107) (9,510)
Total (53,635) (42,818) (19,616)
Total Federal Income Tax as Reported $262,566 $298,462 $322,606
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.
<PAGE>
Year Ended December 31,
1998 1997 1996
(in thousands)
Income Before Preferred Stock Dividend
Requirements of Subsidiaries $547,109 $ 638,211 $628,856
Extraordinary Loss - UK Windfall Tax (Note 7) - (109,419) -
Federal Income Taxes 262,566 298,462 322,606
Pre-Tax Book Income $809,675 $ 827,254 $951,462
Federal Income Tax on Pre-Tax Book Income
at Statutory Rate (35%) $283,386 $289,539 $333,012
Increase (Decrease) in Federal Income Tax
Resulting from the Following Items:
Depreciation 57,663 53,239 50,537
Corporate Owned Life Insurance (16,428) (18,240) (12,009)
Investment Tax Credits (net) (25,304) (25,241) (25,813)
Extraordinary Loss - UK Windfall Tax - 38,297 -
Other (36,751) (39,132) (23,121)
Total Federal Income Taxes as Reported $262,566 $298,462 $322,606
Effective Federal Income Tax Rate 32.4% 36.1% 33.9%
The following tables show the elements of the net deferred tax
liability and the significant temporary differences:
December 31,
1998 1997
(in thousands)
Deferred Tax Assets $ 879,322 $ 807,226
Deferred Tax Liabilities (3,480,724) (3,368,147)
Net Deferred Tax Liabilities $(2,601,402) $(2,560,921)
Property Related Temporary Differences $(2,170,077) $(2,161,484)
Amounts Due From Customers For Future
Federal Income Taxes (395,605) (410,255)
Deferred State Income Taxes (193,867) (201,843)
All Other (net) 158,147 212,661
Total Net Deferred Tax Liabilities $(2,601,402) $(2,560,921)
The Company has settled with the 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 1996 are presently being
audited by the IRS. With the exception of interest deductions
related to AEP's corporate owned life insurance program, which are
discussed under the heading, Litigation, in Note 4, management is
not aware of any issues for open tax years that upon final
resolution are expected to have a material adverse effect on
results of operations.
<PAGE>
13. Supplementary Information:
Year Ended December 31,
1998 1997 1996
(in thousands)
Purchased Power -
Ohio Valley Electric Corporation
(44.2% owned by AEP System) $42,612 $29,631 $22,156
Cash was paid for:
Interest (net of capitalized amounts) $413,341 $390,491 $373,570
Income Taxes $281,709 $398,833 $404,297
Noncash Investing and Financing Activities:
Acquisitions under Capital Leases $119,188 $234,846 $136,988
Assumption of Liabilities related
to Acquisitions $151,506 $ - $ -
14. Leases:
Leases of property, plant and equipment are for periods up to 35
years and require payments of related property taxes, maintenance
and operating costs. The majority of the leases have purchase or
renewal options and will be renewed or replaced by other leases.
Lease rentals are primarily charged to operating expenses in
accordance with rate-making treatment. The components of rentals
are as follows:
Year Ended December 31,
1998 1997 1996
(in thousands)
Operating Leases $254,467 $257,042 $262,451
Amortization of Capital Leases 91,359 104,732 114,050
Interest on Capital Leases 37,516 31,601 28,696
Total Rental Payments $383,342 $393,375 $405,197
Properties under capital leases and related obligations on the
Consolidated Balance Sheets are as follows:
December 31,
1998 1997
(in thousands)
LEASED ASSETS IN ELECTRIC UTILITY PLANT:
Production $ 46,532 $ 47,246
Transmission 4 3
Distribution 14,650 14,660
General:
Nuclear Fuel (net of amortization) 103,939 103,939
Mining Plant and Other 530,291 516,843
Total Electric Utility Plant 695,416 682,691
Accumulated Amortization 208,548 196,145
Net Electric Utility Plant 486,868 486,546
LEASED ASSETS IN OTHER PROPERTY 54,102 57,763
Accumulated Amortization 8,387 5,917
Net Other Property 45,715 51,846
Net Property under Capital Leases $532,583 $538,392
Capital Lease Obligations:*
Noncurrent Liability $450,922 $437,303
Liability Due Within One Year 81,661 101,089
Total Capital Lease Obligations $532,583 $538,392
*Represents the present value of future minimum lease payments for plant and
nuclear fuel. The noncurrent portion of capital lease obligations is included
in other noncurrent liabilities in the Consolidated Balance Sheet.
Properties under operating leases and related obligations are not
included in the Consolidated Balance Sheets.
Future minimum lease rentals, consisted of the following at
December 31, 1998:
Noncancelable
Capital Operating
Leases Leases
(in thousands)
1999 $109,395 $ 239,361
2000 97,132 237,522
2001 79,976 234,147
2002 67,103 228,144
2003 45,161 227,618
Later Years 148,121 3,437,925
Total Future Minimum Lease Rentals 546,888 (a) $4,604,717
Less Estimated Interest Element 118,244
Estimated Present Value of Future
Minimum Lease Rentals 428,644
Unamortized Nuclear Fuel 103,939
Total $532,583
(a) Minimum lease rentals do not include nuclear fuel rentals. The rentals are
paid in proportion to heat produced and carrying charges on the unamortized
nuclear fuel balance. There are no minimum lease payment requirements for
leased nuclear fuel.
15. Capital Stocks and Paid-In Capital:
Changes in capital stocks and paid-in capital during the period
January 1, 1996 through December 31, 1998 were:
<TABLE>
<CAPTION> Cumulative Preferred Stocks
Shares of Subsidiaries
Cumulative Not Subject Subject to
Common Stock- Preferred Stocks Paid-in To Mandatory Mandatory
Par Value $6.50(a) of Subsidiaries Common Stock Capital Redemption Redemption(b)
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C> <C>
January 1, 1996 195,634,992 6,709,751 $1,271,627 $1,658,524 $ 148,240 $ 522,735
Issuances 1,600,000 - 10,400 55,061 - -
Retirements and
Other - (707,518) - 1,969 (57,917) (12,835)
December 31, 1996 197,234,992 6,002,233 1,282,027 1,715,554 90,323 509,900
Issuances 1,754,989 - 11,408 65,337 - -
Retirements and
Other - (4,258,947) - (2,109) (43,599) (382,295)
December 31, 1997 198,989,981 1,743,286 1,293,435 1,778,782 46,724 127,605
Issuances 1,826,488 - 11,872 73,643 - -
Retirements and
Other - (7,220) - 487 (722) -
December 31, 1998 200,816,469 1,736,066 $1,305,307 $1,852,912 $ 46,002 $ 127,605
(a) Includes 8,999,992 shares of treasury stock.
(b) Including portion due within one year.
</TABLE>
<PAGE>
16. Lines of Credit and Commitment Fees:
At December 31, 1998 and 1997, unused short-term bank lines of
credit were available in the amounts of $763 million and $442
million, respectively. In addition several of the subsidiaries
engaged in providing non-regulated energy services share a line of
credit under a revolving credit agreement. The amounts of credit
available under the revolving credit agreement were $60 million and
$330 million at December 31, 1998 and 1997, respectively. The
short-term bank lines of credit and the revolving credit agreement
require the payment of facility fees of approximately 1/10 of 1% on
the daily amount of such commitments.
Outstanding short-term debt consisted of:
December 31,
1998 1997
(dollars in thousands)
Balance Outstanding:
Notes Payable $197,304 $199,285
Commercial Paper 419,300 355,790
Total $616,604 $555,075
Year-End Weighted
Average Interest Rate:
Notes Payable 5.8% 6.3%
Commercial Paper 6.2% 6.8%
Total 6.1% 6.6%
17. Unaudited Quarterly Financial Information:
Quarterly Periods Ended
1998
March 31 June 30 Sept. 30 Dec. 31
(In Thousands - Except
Per Share Amounts)
Operating Revenues $1,509,410 $1,560,944 $1,845,228 $1,430,320
Operating Income 255,932 227,190 311,579 162,033
Net Income 150,586 118,084 195,365 72,148
Earnings per Share 0.79 0.62 1.02 0.38
<PAGE>
Fourth quarter 1998 earnings declined primarily as a result of
unseasonably mild weather, severance accruals and the negative
impact of the extended Cook Plant outage.
Quarterly Periods Ended
1997
March 31 June 30 Sept. 30 Dec. 31
(In Thousands - Except
Per Share Amounts)
Operating Revenues $1,492,069 $1,382,158 $1,507,075 $1,498,518
Operating Income 271,978 221,255 275,090 216,131
Income Before
Extraordinary Item 172,562 121,139 201,746 124,933
Net Income 172,562 121,139 91,181 126,079
Earnings per Share
Before Extraordinary
Item* 0.92 0.64 1.07 0.66
Earnings per Share 0.92 0.64 0.48 0.66
*Amounts for 1997 do not add to $3.28 earnings per share due to
rounding.
The third quarter of 1997 includes an extraordinary loss of $110.6
million or $0.59 per share for a UK Windfall Tax which
retroactively adjusted upward Yorkshire's privatization price
discussed in Note 7.
See "Reclassification" in Note 1 regarding reclassification of
prior period amounts.
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
<TABLE>
<CAPTION>
December 31, 1998
Call
Price per Shares Shares Amount (In
Share (a) Authorized(b) Outstanding Thousands)
<S> <C> <C> <C> <C>
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 460,016 $ 46,002
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 388,100 $ 38,810
6.02% - 6-7/8% (c) (e) 1,950,000 637,950 63,795
7% (f) (f) 250,000 250,000 25,000
Total Subject to Mandatory
Redemption (c) $127,605
______________________________________________________________________________________________________
December 31, 1997
Call
Price per Shares Shares Amount (In
Share (a) Authorized(b) Outstanding Thousands)
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 467,236 $ 46,724
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 388,100 $ 38,810
6.02% - 6-7/8% (c) (e) 1,950,000 637,950 63,795
7% (f) (f) 250,000 250,000 25,000
Total Subject to Mandatory
Redemption (c) $127,605
NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
(a) At the option of the subsidiary the shares may be redeemed at the call price
plus accrued dividends.
The involuntary liquidation preference is $100 per share for all outstanding shares.
(b) As of December 31, 1998 the subsidiaries had 7,193,024, 22,200,000 and 7,583,313 shares of $100, $25
and no par value preferred stock, respectively, that were authorized but unissued.
(c) Shares outstanding and related amounts are stated net of applicable retirements through sinking funds
(genera lly at par) and reacquisitions of shares in anticipation of future requirements.
The subsidiaries reacquired enough shares in 1997 to meet all sinking fund
requirements on certain series until 2008 and on certain series until 2009
when all remaining outstanding shares must be redeemed.The sinking fund provisions of the series
subject to mandatory redemption aggregate $5,000,000 eachyear for the years
2000, 2001, 2002 and $15,000,000 in 2003.
(d) Not callable prior to 2003; after that the call price is $100 per share.
(e) Not callable prior to 2000; after that the call price is $100 per share.
(f) With sinking fund. Redemption is restricted prior to 2000.
</TABLE>
<TABLE>
<CAPTION>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
Weighted Average
Maturity Interest Rate Interest Rates at December 31, December 31,
December 31, 1998 1998 1997 1998 1997
(in thousands)
<S> <C> <C> <C> <C> <C>
FIRST MORTGAGE BONDS
1998-2002 7.23% 6.35%-8.95% 6.35%-9.15% $ 759,000 $1,131,411
2003-2006 6.70% 6%-8% 6%-8% 846,000 846,000
2022-2025 7.90% 7.10%-8.80% 7.10%-8.80% 1,020,768 1,120,419
INSTALLMENT PURCHASE CONTRACTS (a)
1998-2002 4.40% 4.05%-5.15% 3.70%-7-1/4% 145,000 189,500
2007-2025 6.42% 5.00%-7-7/8% 5.45%-7-7/8% 776,245 756,745
NOTES PAYABLE (b)
1998-2008 5.97% 5.49%-9.60% 5.29%-9.60% 1,493,360 527,681
SENIOR UNSECURED NOTES
2003-2008 6.54% 6.24%-6.91% 6.73%-6.91% 786,000 144,000
2038 7.30% 7.20%-7-3/8% - 340,000 -
JUNIOR DEBENTURES
2025 - 2038 8.05% 7.60%-8.72% 7.92%-8.72% 620,000 495,000
OTHER LONG-TERM DEBT (c) 269,319 250,357
Unamortized Discount (net) (49,575) (37,196)
Total Long-term Debt
Outstanding (d) 7,006,117 5,423,917
Less Portion Due Within One Year 206,476 294,454
Long-term Portion $6,799,641 $5,129,463
NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
(a) For certain series of installment purchase contracts interest rates are subject to periodic adjustment.
Certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from
banks and standby bond purchase agreements support certain series.
(b) Notes payable represent outstanding promissory notes issued under term loan agreements and revolving
credit agreements with a number of banks and other financial institutions. At expiration all notes then
issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates
generally relate to specified short-term interest rates.
(c) Other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear
fuel (see Note 4 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease
back agreements.
(d) Long-term debt outstanding at December 31, 1998 is payable as follows:
Principal Amount (in thousands)
1999 $ 206,476
2000 786,222
2001 512,028
2002 294,546
2003 934,547
Later Years 4,321,873
Total Principal
Amount 7,055,692
Unamortized
Discount 49,575
Total $7,006,117
</TABLE>
<PAGE>
Management's Responsibility
The management of American Electric Power Company, Inc. is
responsible for the integrity and objectivity of the information and
representations in this annual report, including the consolidated
financial statements. These statements have been prepared in conformity
with generally accepted accounting principles, using informed estimates
where appropriate, to reflect the Company's financial condition and
results of operations. The information in other sections of the annual
report is consistent with these statements.
The Company's Board of Directors has oversight responsibilities for
determining that management has fulfilled its obligation in the
preparation of the financial statements and in the ongoing examination
of the Company's established internal control structure over financial
reporting. The Audit Committee, which consists solely of outside
directors and which reports directly to the Board of Directors, meets
regularly with management, Deloitte & Touche LLP - Certified Public
Accountants and the Company's internal audit staff to discuss
accounting, auditing and reporting matters. To ensure auditor
independence, both Deloitte & Touche LLP and the internal audit staff
have unrestricted access to the Audit Committee.
The financial statements have been audited by Deloitte & Touche
LLP, whose report appears on the next page. The auditors provide an
objective, independent review as to management's discharge of its
responsibilities insofar as they relate to the fairness of the Company's
reported financial condition and results of operations. Their audit
includes procedures believed by them to provide reasonable assurance
that the financial statements are free of material misstatement and
includes a review of the Company's internal control structure over
financial reporting.
<PAGE>
Independent Auditors' Report
To the Shareholders and Board of Directors
of American Electric Power Company, Inc.:
We have audited the accompanying consolidated balance sheets of
American Electric Power Company, Inc. and its subsidiaries as of
December 31, 1998 and 1997, and the related consolidated statements of
income, retained earnings, and cash flows for each of the three years in
the period ended December 31, 1998. These financial statements are the
responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made
by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for
our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of American
Electric Power Company, Inc. and its subsidiaries as of December 31,
1998 and 1997, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 1998 in
conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 23, 1999
<PAGE>
<TABLE>
EXHIBIT 21
Subsidiaries of
American Electric Power Company, Inc.
As of January 1, 1999
The voting stock of each company shown indented is owned by the company
immediately above which is not indented to the same degree. Subsidiaries not
indented are directly owned by American Electric Power Company, Inc.
<CAPTION>
Percentage
of Voting
Securities
Location of Owned By
Name of Company Incorporation Immediate Parent
<S> <S> <C>
American Electric Power Service Corporation New York 100.0
AEP Communications, Inc. Ohio 100.0
AEP Communications, LLC Virginia 100.0
AEP Energy Services, Inc. Ohio 100.0
AEP Generating Company Ohio 100.0
AEP Investments, Inc. Ohio 100.0
AEP Power Marketing, Inc. Ohio 100.0
AEP Resources Service Company Ohio 100.0
AEP Energy Services International, Limited Cayman Islands 100.0
AEP Resources, Inc. Ohio 100.0
AEP Resources Australia Holdings Pty Ltd Australia 100.0
AEP Resources CitiPower I Pty Ltd Australia 100.0
Australia's Energy Partnership Australia 99.0 (a)
Marregon II Pty Ltd Australia 100.0
CitiPower Pty Australia 100.0
Marregon Pty Ltd Australia 100.0
AEP Resources CitiPower II Pty Ltd Australia 100.0
Australia's Energy Partnership Australia 1.0 (a)
Marregon II Pty Ltd Australia 100.0
CitiPower Pty Australia 100.0
Marregon Pty Ltd Australia 100.0
AEP Resources Australia Pty., Ltd. Australia 100.0
AEP Resources Delaware, Inc. Delaware 100.0
AEP Resources Gas Holding Company Delaware 100.0
AEP Resources Investments, Inc. Delaware 100.0
LIG Pipeline Company Nevada 100.0
LIG, Inc. Nevada 100.0
Louisiana Intrastate Gas Company,L.L.C. Louisiana 10.0 (b)
LIG Chemical Company Louisiana 100.0
LIG Liquids Company,L.L.C. Louisiana 10.0 (c)
LIG Liquids Company,L.L.C. Louisiana 90.0 (c)
Tuscaloosa Pipeline Company Louisiana 100.0
Louisiana Intrastate Gas Company,L.L.C. Louisiana 90.0 (b)
LIG Chemical Company Louisiana 100.0
LIG Liquids Company,L.L.C. Louisiana 10.0 (c)
LIG Liquids Company,L.L.C. Louisiana 90.0 (c)
Tuscaloosa Pipeline Company Louisiana 100.0
AEP Resources Ventures, Inc. Delaware 100.0
AEP Acquisition, L.L.C. Delaware 50.0 (d)
Jefferson Island Storage & Hub L.L.C. Delaware 100.0
AEP Resources Ventures II, Inc. Delaware 100.0
AEP Acquisition, L.L.C. Delaware 50.0 (d)
AEP Resources Ventures III, Inc. Delaware 100.0
AEP Resources International, Limited Cayman Islands 100.0
AEP Pushan Power, LDC Cayman Islands 99.0 (e)
Nanyang General Light Electric Co., Ltd. People's Republic of China 70.0 (f)
AEP Resources Mauritius Company Mauritius 99.0 (e)
AEP Resources Mauritius Investment Company Mauritius 100.0
AEP Resources Project Management Company, Ltd.Cayman Islands 100.0
AEP Pushan Power, LDC Cayman Islands 1.0 (e)
Nanyang General Light Electric Co., Ltd. People's Republic of China 70.0 (f)
AEP Resources Mauritius Company Mauritius 1.0 (e)
AEP Resources Limited Great Britain 100.0
AEPR Global Investments B.V. Netherlands 100.0
AEPR Global Holland Holding B.V. Netherlands 100.0
AEPR Global Ventures B.V. Netherlands 100.0
Appalachian Power Company Virginia 98.6 (g)
Cedar Coal Co. West Virginia 100.0
Central Appalachian Coal Company West Virginia 100.0
Central Coal Company West Virginia 50.0 (h)
Central Operating Company West Virginia 50.0 (h)
Southern Appalachian Coal Company West Virginia 100.0
West Virginia Power Company West Virginia 100.0
Columbus Southern Power Company Ohio 100.0
Colomet, Inc. Ohio 100.0
Conesville Coal Preparation Company Ohio 100.0
Simco Inc. Ohio 100.0
Franklin Real Estate Company Pennsylvania 100.0
Indiana Franklin Realty, Inc. Indiana 100.0
Indiana Michigan Power Company Indiana 100.0
Blackhawk Coal Company Utah 100.0
Price River Coal Company, Inc. Indiana 100.0
Kentucky Power Company Kentucky 100.0
Kingsport Power Company Virginia 100.0
Ohio Power Company Ohio 99.1 (i)
Cardinal Operating Company Ohio 50.0 (j)
Central Coal Company West Virginia 50.0 (h)
Central Ohio Coal Company Ohio 100.0
Central Operating Company West Virginia 50.0 (h)
Southern Ohio Coal Company West Virginia 100.0
Windsor Coal Company West Virginia 100.0
Ohio Valley Electric Corporation Ohio 44.2 (k)
Indiana-Kentucky Electric Corporation Indiana 100.0
Wheeling Power Company West Virginia 100.0
(a) Owned 99% by AEP Resources CitiPower I Pty Ltd and 1% by AEP Resources
CitiPower II Pty Ltd
(b) Owned 90% by LIG Pipeline Company and 10% by LIG, Inc.
(c) Owned 90% by Louisiana Intrastate Gas Company, L.L.C. and 10% by Lig Chemical Company
(d) Owned 50% by Aep Resources Ventures, Inc and 50% by AEP Resources Ventures
II.
(e) Owned 99% by AEP Resources International, Ltd. and 1% by AEP Resources
Project Management Company, Ltd.
(f) AEP Pushan Power LDC owns 70% and the remaining 30% is owned by two unaffiliated
companies.
(g) 13,499,500 shares of Common Stock, all owned by parent, have one vote each
and 3,587 shares of Preferred Stock, all owned by public, have one vote
each.
(h) Owned 50% by Appalachian Power Company and 50% by Ohio Power Company.
(i) 27,952,473 shares of Common Stock, all owned by parent, have one vote each
and 256,200 shares of Preferred Stock, all owned by public, have one vote
each.
(j) Ohio Power Company owns 50% of the stock; the other 50% is owned by a
corporation not affiliated with American Electric Power Company, Inc.
(k) American Electric Power Company, Inc. and Columbus Southern Power Company own 39.9% and
4.3% of the stock, respectively, and the remaining 55.8% is owned by unaffiliated
companies.
</TABLE>
<PAGE>
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Post-Effective
Amendment No. 3 to Registration Statement No. 33-01052 of
American Electric Power Company, Inc. on Form S-8 and
Post-Effective Amendment No. 3 to Registration Statement No.
33-01734 of American Electric Power Company, Inc. on Form S-3 of
our reports dated February 23, 1999, appearing in and
incorporated by reference in this Annual Report on Form 10-K of
American Electric Power Company, Inc. for the year ended December
31, 1998.
Deloitte & Touche LLP
Columbus, Ohio
March 29, 1999
<PAGE>
Exhibit 24
POWER OF ATTORNEY
AMERICAN ELECTRIC POWER COMPANY, INC.
Annual Report on Form lO-K for the Fiscal Year
Ended
December 31, 1998
The undersigned directors of AMERICAN ELECTRIC POWER COMPANY, INC., a New
York corporation (the "Company"), do hereby constitute and appoint E. LINN
DRAPER, JR., ARMANDO A. PENA and HENRY W. FAYNE, 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, 1998, 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 24th
day of February, 1999.
/s/ John P. DesBarres /s/ Angus E. Peyton
John P. DesBarres Angus E. Peyton
/s/ E. Linn Draper, Jr. /s/ Donald G. Smith
E. Linn Draper, Jr. Donald G. Smith
/s/ Robert M. Duncan /s/ Linda Gillespie Stuntz
Robert M. Duncan Linda Gillespie Stuntz
/s/ Robert W. Fri /s/ Kathryn D. Sullivan
Robert W. Fri Kathryn D. Sullivan
/s/ Lester A. Hudson, Jr. /s/ Morris Tanenbaum
Lester A. Hudson, Jr. Morris Tanenbaum
/s/ Leonard J. Kujawa
Leonard J. Kujawa
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000004904
<NAME> AMERICAN ELECTRIC POWER COMPANY, INC.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 11,729,870
<OTHER-PROPERTY-AND-INVEST> 3,356,554
<TOTAL-CURRENT-ASSETS> 2,217,669
<TOTAL-DEFERRED-CHARGES> 332,391
<OTHER-ASSETS> 1,846,718
<TOTAL-ASSETS> 19,483,202
<COMMON> 1,305,307
<CAPITAL-SURPLUS-PAID-IN> 1,852,912
<RETAINED-EARNINGS> 1,683,561
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4,841,780
127,605
46,002
<LONG-TERM-DEBT-NET> 6,799,641
<SHORT-TERM-NOTES> 197,304
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 419,300
<LONG-TERM-DEBT-CURRENT-PORT> 206,476
0
<CAPITAL-LEASE-OBLIGATIONS> 450,922
<LEASES-CURRENT> 81,661
<OTHER-ITEMS-CAPITAL-AND-LIAB> 6,312,511
<TOT-CAPITALIZATION-AND-LIAB> 19,483,202
<GROSS-OPERATING-REVENUE> 6,345,902
<INCOME-TAX-EXPENSE> 334,548
<OTHER-OPERATING-EXPENSES> 5,054,620
<TOTAL-OPERATING-EXPENSES> 5,389,168
<OPERATING-INCOME-LOSS> 956,734
<OTHER-INCOME-NET> 9,463
<INCOME-BEFORE-INTEREST-EXPEN> 966,197
<TOTAL-INTEREST-EXPENSE> 419,088
<NET-INCOME> 536,183
10,926<F1>
<EARNINGS-AVAILABLE-FOR-COMM> 536,183
<COMMON-STOCK-DIVIDENDS> 457,638
<TOTAL-INTEREST-ON-BONDS> 202,889
<CASH-FLOW-OPERATIONS> 1,029,526
<EPS-PRIMARY> 2.81
<EPS-DILUTED> 2.81
<FN>
<F1>Represents preferred stock dividend requirements of subsidiaries; deducted
before computation of net income.
</FN>
</TABLE>
