<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
<PAGE> 83
<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
<PAGE> 84
<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
<PAGE> 85
<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 4(c)
April 22, 1998
Company Order and Officers' Certificate
Senior Notes, Series B
The Bank of New York, as Trustee
101 Barclay Street
New York, New York 10286
Attn: Corporate Trust Division
Ladies and Gentlemen:
Pursuant to Article Two of the Indenture, dated as of January 1, 1998 (as it may
be amended or supplemented, the "Indenture"), from Appalachian Power Company
(the "Company") to The Bank of New York, as trustee (the "Trustee"), and the
Board Resolutions dated December 17, 1997 and March 26, 1998, copies of which
certified by the Secretary or an Assistant Secretary of the Company are being
delivered herewith under Section 2.01 of the Indenture, and unless otherwise
provided in a subsequent Company Order pursuant to Section 2.04 of the
Indenture,
1. The Company's Senior Notes, Series B, Due 2038 (the "Notes") are
hereby established. The Notes shall be in substantially the form attached
hereto as Exhibit 1.
2. The terms and characteristics of the Notes shall be as follows
(the numbered clauses set forth below corresponding to the numbered
subsections of Section 2.01 of the Indenture, with terms used and not
defined herein having the meanings specified in the Indenture):
(i) the aggregate principal amount of Notes which may be
authenticated and delivered under the Indenture shall be limited to
$100,000,000, except as contemplated in Section 2.01(i) of the
Indenture;
(ii) the date on which the principal of the Notes shall be payable
shall be June 30, 2038;
(iii) interest shall accrue from the date of authentication of the
Notes; the Interest Payment Dates on which such interest will be
payable shall be March 31, June 30, September 30 and December 31,
and the Regular Record Date for the determination of holders to whom
interest is payable on any such Interest Payment Date shall be the
close of business on the business day next preceding the relevant
Interest Payment Date; except that if the Notes are no longer
represented by a Global Note, as specified in Paragraph 2(vi) below,
the Regular Record Date will be the March 15, June 15, September 15
or December 15, as the case may be, next preceding such Interest
Payment Date (whether or not a business day); provided that interest
payable on the Stated Maturity Date or any Redemption Date shall be
paid to the Person to whom principal shall be paid;
(iv) the interest rate at which the Notes shall bear interest shall
be 7.30% per annum;
(v) the Notes shall be redeemable at the option of the Company, in
whole or in part, at any time on or after April 22, 2003, upon not
less than 30 nor more than 60 days' notice, at 100% of the principal
amount redeemed together with accrued and unpaid interest to the
redemption date;
(vi) (a) the Notes shall be issued in the form of a Global Note; (b)
the Depositary for such Global Note shall be The Depository Trust
Company; and (c) the procedures with respect to transfer and
exchange of Global Notes shall be as set forth in the form of Note
attached hereto;
(vii) the title of the Notes shall be "Senior Notes, Series B, Due
2038";
(viii) the form of the Notes shall be as set forth in Paragraph 1,
above;
(ix) not applicable;
(x) the Notes shall not be subject to a Periodic
Offering;
(xi) not applicable;
(xii) not applicable;
(xiii) not applicable;
(xiv) the Notes shall be issuable in denominations of $25 and any
integral multiple thereof;
(xv) not applicable;
(xvi) the Notes shall not be issued as Discount Securities;
(xvii) not applicable;
(xviii) not applicable; and
(xix) not applicable.
3. You are hereby requested to authenticate $100,000,000 aggregate
principal amount of 7.30% Senior Notes, Series B, Due 2038 in such name as
requested by The Depository Trust Company ("DTC") in the Letter of
Representations dated April 17, 1998, from the Company and the Trustee to
DTC in the manner provided by the Indenture.
4. You are hereby requested to hold the Notes as custodian for DTC
in accordance with the Letter of Representations.
5. Concurrently with this Company Order, an Opinion of Counsel under
Sections 2.04 and 13.06 of the Indenture is being delivered to you.
6. The undersigned Armando A. Pena and Thomas G. Berkemeyer, the
Treasurer and Assistant Secretary, respectively, of the Company do hereby
certify that:
(i) we have read the relevant portions of the Indenture, including
without limitation the conditions precedent provided for therein
relating to the action proposed to be taken by the Trustee as
requested in this Company Order and Officers' Certificate, and the
definitions in the Indenture relating thereto;
(ii) we have read the Board Resolutions of the Company and the
Opinion of Counsel referred to above;
(iii) we have conferred with other officers of the Company, have
examined such records of the Company and have made such other
investigation as we deemed relevant for purposes of this
certificate;
(iv) in our opinion, we have made such examination or investigation
as is necessary to enable us to express an informed opinion as to
whether or not such conditions have been complied with; and
(v) on the basis of the foregoing, we are of the opinion that all
conditions precedent provided for in the Indenture relating to the
action proposed to be taken by the Trustee as requested herein have
been complied with.
Kindly acknowledge receipt of this Company Order and Officers' Certificate,
including the documents listed herein, and confirm the arrangements set forth
herein by signing and returning the copy of this document attached hereto.
Very truly yours,
APPALACHIAN POWER COMPANY
By: /s/ A. A. Pena
Treasurer
And: /s/ Thomas G. Berkemeyer
Assistant Secretary
Acknowledged by Trustee:
By: /s/ Michael Culhane
Vice President
Exhibit 1
Unless this certificate is presented by an authorized representative of The
Depository Trust Company (55 Water Street, New York, New York) to the issuer or
its agent for registration of transfer, exchange or payment, and any certificate
to be issued is registered in the name of Cede & Co. or in such other name as is
requested by an authorized representative of The Depository Trust Company and
any payment is made to Cede & Co., ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR
VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL inasmuch as the registered
owner hereof, Cede & Co., has an interest herein. Except as otherwise provided
in Section 2.11 of the Indenture, this Security may be transferred, in whole but
not in part, only to another nominee of the Depository or to a successor
Depository or to a nominee of such successor Depository.
No. R-1 4,000,000 Senior Notes
$25 principal amount each
APPALACHIAN POWER COMPANY
7.30% Senior Notes, Series B, Due 2038
CUSIP: 037735 78 4 Original Issue Date: April 22, 1998
Stated Maturity Date: June 30, 2038 Interest Rate: 7.30%
Principal Amount: $100,000,000
Redeemable: Yes X No ____
In Whole: Yes X No ____
In Part: Yes X No ____
Initial Redemption Date: April 22, 2003
Initial Redemption Price: 100%
APPALACHIAN POWER COMPANY, a corporation duly organized and existing under
the laws of the Commonwealth of Virginia (herein referred to as the "Company",
which term includes any successor corporation under the Indenture hereinafter
referred to), for value received, hereby promises to pay to CEDE & CO. or
registered assigns, the Principal Amount specified above on the Stated Maturity
Date specified above, and to pay interest on said Principal Amount from the
Original Issue Date specified above or from the most recent interest payment
date (each such date, an "Interest Payment Date") to which interest has been
paid or duly provided for, quarterly in arrears on March 31, June 30, September
30 and December 31 in each year, commencing (except as provided below) with the
Interest Payment Date next succeeding the Original Issue Date specified above,
at the Interest Rate per annum specified above, until the Principal Amount shall
have been paid or duly provided for. Interest shall be computed on the basis of
a 360-day year of twelve 30-day months.
The interest so payable, and punctually paid or duly provided for, on any
Interest Payment Date, as provided in the Indenture, as hereinafter defined,
shall be paid to the Person in whose name this Note (or one or more Predecessor
Securities) shall have been registered at the close of business on the Regular
Record Date with respect to such Interest Payment Date, which shall be the close
of business on the Business Day next preceding such Interest Payment Date. Any
such interest not so punctually paid or duly provided for shall forthwith cease
to be payable to the Holder on such Regular Record Date and shall be paid as
provided in said Indenture.
If any Interest Payment Date, any Redemption Date or the Stated Maturity
Date is not a Business Day, then payment of the amounts due on this Note on such
date will be made on the next succeeding Business Day, and no interest shall
accrue on such amounts for the period from and after such Interest Payment Date,
Redemption Date or Stated Maturity Date, as the case may be, except that, if
such Business Day is in the next succeeding calendar year, such payment shall be
made on the immediately preceding Business Day, with the same force and effect
as if made on such date. The principal of (and premium, if any) and the interest
on this Note shall be payable at the office or agency of the Company maintained
for that purpose in the Borough of Manhattan, the City of New York, New York, in
any coin or currency of the United States of America which at the time of
payment is legal tender for payment of public and private debts; provided,
however, that payment of interest (other than interest payable on the Stated
Maturity Date or any Redemption Date) may be made at the option of the Company
by check mailed to the registered holder at such address as shall appear in the
Note Register.
This Note is one of a duly authorized series of Notes of the Company
(herein sometimes referred to as the "Notes"), specified in the Indenture, all
issued or to be issued in one or more series under and pursuant to an Indenture
dated as of January 1, 1998 duly executed and delivered between the Company and
The Bank of New York, a New York banking corporation organized and existing
under the laws of the State of New York, as Trustee (herein referred to as the
"Trustee") (such Indenture, as originally executed and delivered and as
thereafter supplemented and amended being hereinafter referred to as the
"Indenture"), to which Indenture and all indentures supplemental thereto or
Company Orders reference is hereby made for a description of the rights,
limitations of rights, obligations, duties and immunities thereunder of the
Trustee, the Company and the holders of the Notes. By the terms of the
Indenture, the Notes are issuable in series which may vary as to amount, date of
maturity, rate of interest and in other respects as in the Indenture provided.
This Note is one of the series of Notes designated on the face hereof.
Subject to the terms of Article Three of the Indenture, the Company shall
have the right to redeem this Note at its option, without premium or penalty, in
whole or, in part, at any time on or after April 22, 2003, at a redemption price
equal to 100% of the principal amount thereof plus any accrued but unpaid
interest to the date of such redemption.
This Note shall be redeemable to the extent set forth herein and in the
Indenture upon not less than thirty, but not more than sixty, days previous
notice by mail to the registered owner.
The Company shall not be required to (i) issue, exchange or register the
transfer of any Notes during a period beginning at the opening of business 15
days before the day of the mailing of a notice of redemption of less than all
the outstanding Notes of the same series and ending at the close of business on
the day of such mailing, nor (ii) register the transfer of or exchange of any
Notes of any series or portions thereof called for redemption. This Global Note
is exchangeable for Notes in definitive registered form only under certain
limited circumstances set forth in the Indenture.
In the event of redemption of this Note in part only, a new Note or Notes
of this series, of like tenor, for the unredeemed portion hereof will be issued
in the name of the Holder hereof upon the surrender of this Note.
In case an Event of Default, as defined in the Indenture, shall have
occurred and be continuing, the principal of all of the Notes may be declared,
and upon such declaration shall become, due and payable, in the manner, with the
effect and subject to the conditions provided in the Indenture.
The Indenture contains provisions for defeasance at any time of the entire
indebtedness of this Note upon compliance by the Company with certain conditions
set forth therein.
The Indenture contains provisions permitting the Company and the Trustee,
with the consent of the Holders of not less than a majority in aggregate
principal amount of the Notes of each series affected at the time outstanding,
as defined in the Indenture, to execute supplemental indentures for the purpose
of adding any provisions to or changing in any manner or eliminating any of the
provisions of the Indenture or of any supplemental indenture or of modifying in
any manner the rights of the Holders of the Notes; provided, however, that no
such supplemental indenture shall (i) extend the fixed maturity of any Notes of
any series, or reduce the principal amount thereof, or reduce the rate or extend
the time of payment of interest thereon, or reduce any premium payable upon the
redemption thereof, or reduce the amount of the principal of a Discount Security
that would be due and payable upon a declaration of acceleration of the maturity
thereof pursuant to the Indenture, without the consent of the holder of each
Note then outstanding and affected; (ii) reduce the aforesaid percentage of
Notes, the holders of which are required to consent to any such supplemental
indenture, or reduce the percentage of Notes, the holders of which are required
to waive any default and its consequences, without the consent of the holder of
each Note then outstanding and affected thereby; or (iii) modify any provision
of Section 6.01(c) of the Indenture (except to increase the percentage of
principal amount of securities required to rescind and annul any declaration of
amounts due and payable under the Notes), without the consent of the holder of
each Note then outstanding and affected thereby. The Indenture also contains
provisions permitting the Holders of a majority in aggregate principal amount of
the Notes of all series at the time outstanding affected thereby, on behalf of
the Holders of the Notes of such series, to waive any past default in the
performance of any of the covenants contained in the Indenture, or established
pursuant to the Indenture with respect to such series, and its consequences,
except a default in the payment of the principal of or premium, if any, or
interest on any of the Notes of such series. Any such consent or waiver by the
registered Holder of this Note (unless revoked as provided in the Indenture)
shall be conclusive and binding upon such Holder and upon all future Holders and
owners of this Note and of any Note issued in exchange herefor or in place
hereof (whether by registration of transfer or otherwise), irrespective of
whether or not any notation of such consent or waiver is made upon this Note.
No reference herein to the Indenture and no provision of this Note or of
the Indenture shall alter or impair the obligation of the Company, which is
absolute and unconditional, to pay the principal of and premium, if any, and
interest on this Note at the time and place and at the rate and in the money
herein prescribed.
As provided in the Indenture and subject to certain limitations therein
set forth, this Note is transferable by the registered holder hereof on the Note
Register of the Company, upon surrender of this Note for registration of
transfer at the office or agency of the Company as may be designated by the
Company accompanied by a written instrument or instruments of transfer in form
satisfactory to the Company or the Trustee duly executed by the registered
Holder hereof or his or her attorney duly authorized in writing, and thereupon
one or more new Notes of authorized denominations and for the same aggregate
principal amount and series will be issued to the designated transferee or
transferees. No service charge will be made for any such transfer, but the
Company may require payment of a sum sufficient to cover any tax or other
governmental charge payable in relation thereto.
Prior to due presentment for registration of transfer of this Note, the
Company, the Trustee, any paying agent and any Note Registrar may deem and treat
the registered Holder hereof as the absolute owner hereof (whether or not this
Note shall be overdue and notwithstanding any notice of ownership or writing
hereon made by anyone other than the Note Registrar) for the purpose of
receiving payment of or on account of the principal hereof and premium, if any,
and interest due hereon and for all other purposes, and neither the Company nor
the Trustee nor any paying agent nor any Note Registrar shall be affected by any
notice to the contrary.
No recourse shall be had for the payment of the principal of or the
interest on this Note, or for any claim based hereon, or otherwise in respect
hereof, or based on or in respect of the Indenture, against any incorporator,
stockholder, officer or director, past, present or future, as such, of the
Company or of any predecessor or successor corporation, whether by virtue of any
constitution, statute or rule of law, or by the enforcement of any assessment or
penalty or otherwise, all such liability being, by the acceptance hereof and as
part of the consideration for the issuance hereof, expressly waived and
released.
The Notes of this series are issuable only in registered form without
coupons in denominations of $25 and any integral multiple thereof. As provided
in the Indenture and subject to certain limitations, Notes of this series are
exchangeable for a like aggregate principal amount of Notes of this series of a
different authorized denomination, as requested by the Holder surrendering the
same.
All terms used in this Note which are defined in the Indenture shall have
the meanings assigned to them in the Indenture.
This Note shall not be entitled to any benefit under the Indenture
hereinafter referred to, be valid or become obligatory for any purpose until the
Certificate of Authentication hereon shall have been signed by or on behalf of
the Trustee.
IN WITNESS WHEREOF, the Company has caused this Instrument to be executed.
APPALACHIAN POWER COMPANY
By:_______________________
Treasurer
Attest:
By:___________________________
Assistant Secretary
CERTIFICATE OF AUTHENTICATION
This is one of the Notes of the series of Notes designated in accordance
with, and referred to in, the within-mentioned Indenture.
Dated: April 22, 1998
THE BANK OF NEW YORK, as Trustee
By:___________________________
Authorized Signatory
FOR VALUE RECEIVED, the undersigned hereby sell(s), assign(s)
and transfer(s) unto
(PLEASE INSERT SOCIAL SECURITY OR OTHER
IDENTIFYING NUMBER OF ASSIGNEE)
- ---------------------------------------
- ----------------------------------------------------------------
- ----------------------------------------------------------------
(PLEASE PRINT OR TYPE NAME AND ADDRESS, INCLUDING ZIP CODE, OF
- ----------------------------------------------------------------
ASSIGNEE) the within Note and all rights thereunder, hereby
- ----------------------------------------------------------------
irrevocably constituting and appointing such person attorney to
- ----------------------------------------------------------------
transfer such Note on the books of the Issuer, with full
- ----------------------------------------------------------------
power of substitution in the premises.
Dated:________________________ _________________________
NOTICE: The signature to this assignment must correspond with the
name as written upon the face of the within Note in every
particular, without alteration or enlargement or any
change whatever and NOTICE: Signature(s) must be
guaranteed by a financial institution that is a member of
the Securities Transfer Agents Medallion Program
("STAMP"), the Stock Exchange Medallion Program ("SEMP")
or the New York Stock Exchange, Inc. Medallion Signature
Program ("MSP").
<PAGE>
<TABLE>
EXHIBIT 12
APPALACHIAN POWER COMPANY
Computation of Consolidated Ratio of Earnings to Fixed Charges
(in thousands except ratio data)
<CAPTION>
Year Ended December 31,
1994 1995 1996 1997 1998
<S> <C> <C> <C> <C> <C>
Fixed Charges:
Interest on First Mortgage Bonds. . . . . . . . . . . $ 75,815 $ 80,777 $ 82,082 $ 81,009 $ 72,057
Interest on Other Long-term Debt. . . . . . . . . . . 16,415 16,404 18,025 28,163 40,642
Interest on Short-term Debt . . . . . . . . . . . . . 3,366 5,119 3,639 4,569 4,245
Miscellaneous Interest Charges. . . . . . . . . . . . 3,913 5,323 7,327 6,857 11,470
Estimated Interest Element in Lease Rentals . . . . . 7,700 7,000 6,600 6,000 5,900
Total Fixed Charges. . . . . . . . . . . . . . . $107,209 $114,623 $117,673 $126,598 $134,314
Earnings:
Net Income. . . . . . . . . . . . . . . . . . . . . . $102,345 $115,900 $133,689 $120,514 $ 93,330
Plus Federal Income Taxes . . . . . . . . . . . . . . 39,599 53,355 65,801 54,835 43,941
Plus State Income Taxes . . . . . . . . . . . . . . . 5,910 7,273 10,180 8,109 6,845
Plus Fixed Charges (as above) . . . . . . . . . . . . 107,209 114,623 117,673 126,598 134,314
Total Earnings . . . . . . . . . . . . . . . . . $255,063 $291,151 $327,343 $310,056 $278,430
Ratio of Earnings to Fixed Charges. . . . . . . . . . . 2.37 2.54 2.78 2.44 2.07
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
1998 1997 1996 1995 1994
(in thousands)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENTS DATA:
Operating Revenues $1,672,244 $1,628,515 $1,624,869 $1,545,039 $1,535,500
Operating Expenses 1,443,701 1,388,521 1,381,993 1,317,937 1,330,282
Operating Income 228,543 239,994 242,876 227,102 205,218
Nonoperating Income (Loss) (8,301) (222) 128 (4,699) (4,716)
Income Before Interest Charges 220,242 239,772 243,004 222,403 200,502
Interest Charges 126,912 119,258 109,315 106,503 98,157
Net Income 93,330 120,514 133,689 115,900 102,345
Preferred Stock Dividend
Requirements 2,497 7,006 15,938 16,405 15,660
Earnings Applicable to
Common Stock $ 90,833 $ 113,508 $ 117,751 $ 99,495 $ 86,685
Year Ended December 31,
1998 1997 1996 1995 1994
(in thousands)
<S> <C> <C> <C> <C> <C>
BALANCE SHEETS DATA:
Electric Utility Plant $5,087,359 $4,901,046 $4,717,132 $4,558,436 $4,398,727
Accumulated Depreciation and
Amortization 1,984,856 1,869,057 1,782,017 1,694,746 1,627,852
Net Electric Utility Plant $3,102,503 $3,031,989 $2,935,115 $2,863,690 $2,770,875
Total Assets $4,047,038 $3,883,430 $3,800,737 $3,723,975 $3,635,632
Common Stock and
Paid-in Capital $ 924,091 $ 873,506 $ 835,838 $ 785,509 $ 764,866
Retained Earnings 179,461 207,544 208,472 199,021 206,361
Total Common Shareholder's
Equity $1,103,552 $1,081,050 $1,044,310 $ 984,530 $ 971,227
Cumulative Preferred Stock:
Not Subject to Mandatory
Redemption $ 19,359 $ 19,747 $ 29,815 $ 55,000 $ 55,000
Subject to Mandatory
Redemption (a) 22,310 22,310 190,000 190,235 190,385
Total Cumulative
Preferred Stock $ 41,669 $ 42,057 $ 219,815 $ 245,235 $ 245,385
Long-term Debt (a) $1,552,455 $1,494,535 $1,365,842 $1,285,684 $1,228,911
Obligations Under Capital
Leases (a) $ 65,175 $ 60,110 $ 51,969 $ 48,937 $ 43,138
Total Capitalization and
Liabilities $4,047,038 $3,883,430 $3,800,737 $3,723,975 $3,635,632
</TABLE>
(a) Including portion due within one year.
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
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 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 deregulation of generation, new legislation and government
regulations; the ability of the Company to successfully control its
costs; the economic climate and growth in our service territory;
unforeseen problems or failures related to Year 2000 readiness of
computer software and hardware; inflationary trends; electricity
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.
Appalachian Power Company (the Company) is a wholly-owned
subsidiary of American Electric Power Company, Inc. (AEP Co.,
Inc.), a public utility holding company. The Company is engaged in
the generation, purchase, sale, transmission and distribution of
electric power to 888,000 retail customers in southwestern Virginia
and southern West Virginia and does business as American Electric
Power (AEP). The Company supplies electric power to the AEP System
Power Pool (AEP Power Pool) and shares the revenues and costs of
AEP Power Pool wholesale sales to neighboring utility systems and
power marketers. The Company also sells wholesale power to
municipalities. As a member of the AEP Power Pool and a signatory
company to the AEP System Transmission Equalization Agreement, the
Company's generation and transmission facilities are operated in
conjunction with the facilities of certain other AEP affiliated
utilities as an integrated utility system.
Results of Operations
Net Income
Although operating revenues increased in 1998, net income
declined $27.2 million or 23% due primarily to increased fuel and
maintenance expenses, losses on certain non-regulated electricity
trading activities outside of the AEP Power Pool's traditional
marketing area, increased interest charges and provisions for
revenue refunds. The $13.2 million or 10% decline in 1997 was
primarily due to increased interest charges reflecting additional
amounts of long-term debt outstanding.<PAGE>
Operating Revenues Increase
Operating revenues increased 3% in 1998 primarily due to
increased revenues from trading and transmission services. In 1997
revenues were relatively unchanged. The changes in the components
of revenues are as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1998 1997
Amount % Amount %
Retail:
Residential $(5.1) $ (8.4)
Commercial 2.3 (2.8)
Industrial (0.3) 13.6
Other 2.2 0.2
(0.9) (0.1) 2.6 0.2
Wholesale 30.7 9.6 (13.5) (4.1)
Transmission 19.3 69.9 6.5 30.9
Miscellaneous (5.4) (25.5) 8.0 59.6
Total $43.7 2.7 $ 3.6 0.2
The Company as part of the AEP System shares the benefits and
costs of the System's generation through the AEP Power Pool. The
cost of the System's generating capacity is allocated among the AEP
Power Pool members, based on their relative peak demands and
generating reserves through the payment or receipt of capacity
charges and credits. AEP Power Pool members are also compensated
for their out-of-pocket costs of energy delivered to the AEP Power
Pool and charged for energy received from the AEP Power Pool.
The AEP Power Pool calculates each Company's prior twelve
month peak demand relative to the total peak demand of all member
companies as a basis for sharing revenues and costs. The result of
this calculation is each Company's member load ratio (MLR) which
determines each Company's percentage share of revenues or costs.
During 1998 the Company's MLR decreased resulting in the Company
being allocated a smaller share of wholesale revenues and expenses
from the AEP Power Pool.
In 1997 management decided to develop a power marketing and
trading business. The power marketing and trading business is
conducted by American Electric Power Service Corporation as agent
for the AEP Power Pool and its revenues and expenses are allocated
to AEP Power Pool members based on MLR.
The volume of the power marketing and trading business grew
substantially during 1998 and accounted for the increase in
wholesale revenues which reflects the Company's share of net
revenues from electricity trading with other utilities and power
marketers. Trading revenues are recorded net of purchases.
Wholesale revenues decreased in 1997 primarily due to a decline in
energy sales to the AEP Power Pool reflecting the AEP Power Pool's
reduced need for energy as energy sales to unaffiliated entities
declined.
Transmission service revenues increased due to a substantial
rise in the volume of energy transmitted for other entities over
the AEP System's transmission lines. The issuance of open access
transmission rules by the Federal Energy Regulatory Commission
(FERC) facilitated the growth in transmission services. The Company
receives its MLR share of transmission revenues.
In 1998 miscellaneous revenues declined due to the recordation
of provisions for revenue refunds under final rate orders. The
increase in miscellaneous operating revenues in 1997 was due to the
favorable effect of a provision recorded in 1996 for the completion
of rate refunds under a settlement in the Virginia jurisdiction.
Operating Expenses Increase
Operating expenses increased 4% in 1998 and less than one
percent in 1997. The increase in 1998 is mainly due to increased
fuel and maintenance costs. Changes in the components of operating
expenses are as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1998 1997
Amount % Amount %
Fuel $33.7 8.4 $ 36.1 9.8
Purchased Power (8.4) (2.7) (21.5) (6.5)
Other Operation 7.9 3.2 6.5 2.7
Maintenance 22.0 19.5 (4.6) (3.9)
Depreciation and
Amortization 6.1 4.5 4.6 3.5
Taxes Other Than
Federal Income Taxes (0.5) (0.4) (3.7) (3.1)
Federal Income Taxes (5.6) (9.6) (10.9) (15.5)
Total $55.2 4.0 $ 6.5 0.5
The increase in fuel expense in 1998 is primarily due to an
increase in generation. Fuel expense increased 10% in 1997
primarily due to increased generation and the operation of the West
Virginia power supply cost recovery mechanism which requires that
overcollections of fuel costs be deferred for future refund to
customers through a charge to fuel expense. The level of
generation increased primarily in the fourth quarter of 1997 when
both units of the affiliate's nuclear plant were unavailable.
The reduction in purchased power expense was due to reduced
capacity charges from the AEP Power Pool as a result of the
decrease in the Company's MLR and decreased purchases from the AEP
Power Pool. The decline in purchased power expense in 1997 was
mainly due to decreased purchases from the AEP Power Pool.
Maintenance expense increased in 1998 primarily as a result of
expenditures to restore service and make repairs following two
severe snow storms and to clear and maintain right-of-ways.
Federal income taxes attributable to operations decreased in
both years primarily due to a decline in pre-tax operating income.
Nonoperating Income
Nonoperating income declined in 1998 primarily due to losses
from forward electricity sales and purchases outside of the AEP
Power Pool's traditional marketing area and electricity derivatives
such as options, swaps, etc. Open non-regulated trades are
marked-to-market and recorded in nonoperating income.
Interest Charges and Preferred Stock Dividends
The increase in interest charges in 1998 is primarily due to
increased long-term borrowings and the accrual of interest to be
paid to customers under rate refund orders.
Interest charges increased in 1997 primarily as a result of an
increase in the balance of long-term debt outstanding to replace
preferred stock. Preferred stock dividend requirements decreased
significantly due to a decrease in the number of shares outstanding
reflecting the reacquisition of 1.3 million shares in the first
quarter of 1997 as part of a tender offer and the redemption of the
remaining 477,500 outstanding shares of the 7.80% series in April
1997.
Business Outlook
The most significant factor affecting the Company's future
earnings is its ability to recover its costs as the electric
generating business becomes more competitive. Although the FERC
instituted open transmission access and competition in the
wholesale market in 1996, the introduction of competition and
customer choice for retail customers 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. The Company's retail operations are in West Virginia and
Virginia. West Virginia is currently considering initiatives to
move to customer choice, although the timing is uncertain.
<PAGE>
In February 1999 the Virginia legislature passed comprehensive
legislation, which will become law upon the Governor's signature,
to restructure the electric utility industry and taxes applicable
to electric utility services. Under the restructuring bill a
transition to choice of supplier for retail customers will commence
on January 1, 2002 and be completed, subject to a finding by the
State Corporation Commission (SCC) that an effective competitive
market exists, on January 1, 2004. Provisions allowing for an
acceleration or limited delay in this schedule are also contained
in the bill. Except as provided in the legislation, the generation
of electricity will not be subject to rate regulation after January
1, 2002. Additionally, each Virginia electric utility is required
by 2001 to join or establish a regional transmission entity which
will manage and control transmission assets.
The Virginia restructuring bill also provides an opportunity
for recovery of just and reasonable net stranded costs. Stranded
costs are those costs above market that potentially would not be
recoverable in a competitive market. The mechanisms in the
Virginia legislation for stranded cost recovery are dual: a capping
of incumbent utility rates until as late as July 1, 2007, and the
application of a wires charge upon customers who may depart the
incumbent utility in favor of an alternative supplier prior to the
termination of the rate cap. The legislation provides for the
establishment of capped rates prior to January 1, 2001. The capped
rates may be terminated after January 1, 2004, and prior to July 1,
2007, based upon the SCC determining that an effective competitive
market exists. The wires charge will be equal to the difference
between the generation component of the capped rates and the market
price for generation service and will be imposed upon departing
customers through the expiration of the rate cap period.
Related tax legislation, which is intended to be revenue
neutral, provides for replacement of the gross receipts and certain
other taxes on electric utilities with a consumption tax levied
upon customers on the basis of kilowatt-hour usage, and a state
corporate net income tax.
Under the provisions of Statement of Financial Accounting
Standards (SFAS) 71 "Accounting for the Effects of Certain Types of
Regulation," regulatory assets (deferred expenses) and regulatory
liabilities (deferred revenues) are included in the consolidated
balance sheets of regulated utilities in accordance with regulatory
actions to match expenses and revenues with cost-based rates in the
same accounting period. In order to maintain net regulatory assets
on the balance sheet, SFAS 71 requires that rates charged to
customers be cost-based and the recovery of regulatory assets must
be probable. In the event a portion of the Company'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 would provide for recovery of stranded costs during and
after a transition period. In July 1997 the Financial Accounting
Standards Board's (FASB) Emerging Issues Task Force (EITF)
addressed such a situation with the consensus reached on issue 97-4
that 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 probable of recovery in future regulated rates.
The Company's firm wholesale sales are a relatively small part
of our business and are still under cost-of-service contracts. Our
Virginia rates for generation will continue to be cost-based
regulated until the establishment of capped rates. Until the
capped rates are determined the Company does not have sufficient
detail to reasonably determine what the legislature's approved plan
for competition will entail. In West Virginia retail rates
continue to be based upon cost-of-service. Consequently, as of
December 31, 1998 the Company's generation business is still
cost-based regulated.
When capped rates are established in Virginia the application
of SFAS 71 would be discontinued for the Virginia retail
jurisdiction portion of the generating business, generation-related
regulatory assets applicable to the Virginia jurisdiction will have
to be written off to the extent that they cannot be recovered under
the provisions of the restructuring legislation and generating
assets for the Virginia retail jurisdiction will have to be
evaluated for impairment. Based upon initial reviews the amount of
regulatory assets applicable to the Virginia generating business at
December 31, 1998 is estimated to be $64 million before related tax
effects and any possible offsetting regulatory liabilities.
Regulatory liabilities applicable to the Virginia generation
business at December 31, 1998 are estimated to be $39 million of
which $26 million represents deferred investment tax credits. The
Company is evaluating the tax normalization rules regarding the
timing of the reversal of deferred investment tax credits in
connection with the Virginia restructuring legislation. Should it
not be possible under the Virginia legislation to recover any
portion of the generation net regulatory assets, it could have a
material adverse impact on results of operations; however, the
amount of any impairment loss for Virginia retail jurisdictional
generating assets and any loss from a possible inability to recover
net generation regulatory assets cannot be estimated until such
time as capped rates are determined under the legislation.
In the event West Virginia were to provide some form of retail
competition such that the Company's West Virginia jurisdiction was
no longer cost-based regulated for generation, and if it were not
possible to demonstrate probability of recovery of resultant
stranded costs including net regulatory assets during the
transition period or from regulated distribution rates, then
results of operations, cash flows and financial condition would be
adversely affected. At the current time the timing and status of
initiatives to move to customer choice in West Virginia is
uncertain and the Company is in no position to determine whether it
will incur a loss if and when West Virginia adopts restructuring.
Litigation
Corporate Owned Life Insurance
The Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns for the years 1991
to 1993 requested a ruling from their National Office that certain
interest deductions claimed by the Company relating to a corporate
owned life insurance (COLI) program should not be allowed. As a
result of a suit filed by the Company 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 $79 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 and cash
flows.
The Company 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.
Cost Containment and Process Improvement
Efforts continue to reduce the cost of 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 cost
reductions. In 1998 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, the Company continues to incur expenses
related to investments in marketing and customer services and the
reengineering and improvement of business processes.
During 1998, the Company 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
employees to maximize the benefits of their personal computers and
will position them to better access the power of the Internet and
other new technologies.
Fuel Costs
The management and control of coal costs is critical to our
competitive position. Approximately 98% of the Company's
generation is coal fired with coal supplied under long-term
contracts and purchased 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.
Environmental Concerns
We take great pride in our efforts to economically produce and
deliver electricity while minimizing the impact on the environment.
Over the years the Company has spent hundreds of millions of
dollars to equip its facilities with the latest economical clean
air and water technologies and to research new technologies. 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 and sludge. Coal combustion by-products
are typically disposed of or treated in captive disposal
facilities or are beneficially utilized. In addition, our
generating plants and transmission and distribution facilities have
used asbestos, polychlorinated biphenyls (PCBs) and other hazardous
and nonhazardous materials. The Company is 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, there is one site for
which the Company has received an information request which could
lead to a potentially responsible party designation. The Company's
liability has been resolved for a number of sites with no
significant effect on results of operations and present estimates
do not anticipate material cleanup costs for the identified site in
which the Company is involved. However, if for reasons not
currently identified significant costs are incurred for cleanup,
future results of operations, cash flows and possibly financial
condition could be adversely affected unless the costs can be
recovered from customers.
Federal EPA is required by the Clean Air Act Amendments of
1990 (CAAA) to issue rules to implement the law. In 1996 Federal
EPA issued final rules governing nitrogen oxide (NOx) that must be
met after January 1, 2000 (Phase II of the CAAA). The final rules
will require substantial reductions in NOx emissions from certain
types of boilers including those in power plants of the Company and
its affiliates in the AEP System. 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 $55 million of which $37 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 Company and the other
operating companies of the AEP System, filed a petition in the
United States (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 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 could result in
required capital expenditures of approximately $325 million.
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 US, 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 US Senate for
ratification, would require the US to reduce greenhouse gas
emissions seven percent below 1990 levels in the years 2008-2012.
Although the US 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.
Financial Condition
The Company issued $220 million principal amount of long-term
obligations in 1998 at interest rates ranging from 5% to 7.3% and
received from its parent a $50 million capital contribution. The
principal amount of long-term debt retirements, including
maturities, totaled $157 million with interest rates ranging from
7-1/4% to 8.75%. The Company's senior secured debt/first mortgage
bond ratings are: Moody's, A3; Standard and Poor's (S&P), A; Fitch,
A; and Duff & Phelps, LLC (D & P), A.
Gross plant and property additions were $226 million in 1998
and $233 million in 1997. Management estimates construction
expenditures for the next three years to be $766 million which
includes the cost of transmission and distribution projects for the
improvement of and addition to electric energy delivery facilities.
The funds for construction of new facilities and improvement of
existing facilities can come from a combination of internally
generated funds, short-term and long-term borrowings and
investments in common equity by the Company's parent, AEP Co., Inc.
Approximately 65% of the construction expenditures for the next
three years are expected to be financed with internally generated
funds.
When necessary the Company generally issues short-term debt to
provide for interim financing of capital expenditures that exceed
internally generated funds. At December 31, 1998, $763 million of
unused short-term lines of credit shared with other AEP System
companies were available. Short-term debt borrowings are limited
by provisions of the 1935 Act to $325 million. Generally periodic
reductions of outstanding short-term debt are made through
issuances of long-term debt and through additional capital
contributions by the parent company.
The Company's earnings coverage presently exceeds all minimum
coverage requirements for the issuance of mortgage bonds and
preferred stock. The minimum coverage ratio is 2.0 for mortgage
bonds and 1.5 for preferred stock. At December 31, 1998, the
mortgage bonds and preferred stock coverage ratios were 3.88 and
1.8, respectively.
Market Risks
The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and
interest rates. The allocation of trading of electricity and
related financial derivative instruments through the AEP Power Pool
exposes the Company to market risk. Market risk represents the
risk of loss that may impact the Company due to adverse changes in
electricity commodity market prices and rates. In 1998 the AEP
Power Pool substantially increased the volume of its wholesale
power 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
Company's share of the highest, lowest and average quarterly VaR in
the wholesale trading portfolio was less than $3 million at a 95%
confidence level with a holding period of three business days. The
AEP Power Pool uses 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 electricity
commodity prices is not expected to have a material effect on the
Company's results of operations, cash flows or financial condition.
The Company is exposed to changes in interest rates primarily
due to short-term and long-term borrowings to fund its business
operations. The debt portfolio has fixed and variable interest
rates with terms from one day to forty years and an average
duration of six 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 are 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 $135
million at December 31, 1998. 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. Also since the Company's rates
are cost-based regulated, the risk of interest rate changes on debt
used to finance regulated operations is mitigated.
Inflation affects the Company'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.
Readiness Program
Internally, the Company, through the AEP System, 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. The Company, 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 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.
Costs to Address the Company's Year 2000 Issues
Through December 31, 1998, the Company has spent $6 million on
the Year 2000 project and, estimates spending an additional $10
million to $14 million to achieve Year 2000 readiness. Most Year
2000 costs are for software modifications, 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 and
* 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.
In addition, although as discussed relationships with third
parties, such as suppliers, customers and other electric utilities,
are being monitored, 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 who impact the AEP System's operations but are
not affiliated with the AEP System, fail for critical applications,
Year 2000-related issues may materially adversely affect the
Company.
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 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.
Contingency plans will be developed by the end of 1999. The
Company's plans build upon the disaster recovery, system
restoration, and contingency planning that we have had in place.
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 standards for annual and interim financial
statements to report 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. 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 an effect on results of operations, cash
flows or financial condition.
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. Initial 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.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
1998 1997 1996
(in thousands)
<S> <C> <C> <C>
OPERATING REVENUES $1,672,244 $1,628,515 $1,624,869
OPERATING EXPENSES:
Fuel 437,500 403,777 367,651
Purchased Power 303,116 311,514 333,014
Other Operation 254,718 246,785 240,249
Maintenance 134,856 112,873 117,483
Depreciation and Amortization 143,809 137,670 133,074
Taxes Other Than Federal Income Taxes 116,070 116,590 120,307
Federal Income Taxes 53,632 59,312 70,215
Total Operating Expenses 1,443,701 1,388,521 1,381,993
OPERATING INCOME 228,543 239,994 242,876
NONOPERATING INCOME (LOSS) (8,301) (222) 128
INCOME BEFORE INTEREST CHARGES 220,242 239,772 243,004
INTEREST CHARGES 126,912 119,258 109,315
NET INCOME 93,330 120,514 133,689
PREFERRED STOCK DIVIDEND REQUIREMENTS 2,497 7,006 15,938
EARNINGS APPLICABLE TO COMMON STOCK $ 90,833 $ 113,508 $ 117,751
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
1998 1997
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production $1,976,729 $1,942,325
Transmission 1,116,421 1,079,919
Distribution 1,641,278 1,583,161
General 233,465 207,380
Construction Work in Progress 119,466 88,261
Total Electric Utility Plant 5,087,359 4,901,046
Accumulated Depreciation and Amortization 1,984,856 1,869,057
NET ELECTRIC UTILITY PLANT 3,102,503 3,031,989
OTHER PROPERTY AND INVESTMENTS 111,020 34,544
CURRENT ASSETS:
Cash and Cash Equivalents 7,755 6,947
Accounts Receivable:
Customers 122,746 129,924
Affiliated Companies 35,802 24,502
Miscellaneous 8,572 10,231
Allowance for Uncollectible Accounts (2,234) (1,333)
Fuel - at average cost 49,826 47,901
Materials and Supplies - at average cost 60,440 57,359
Accrued Utility Revenues 45,985 51,208
Energy Marketing and Trading Contracts 22,436 923
Prepayments 8,151 6,037
TOTAL CURRENT ASSETS 359,479 333,699
REGULATORY ASSETS 426,193 441,223
DEFERRED CHARGES 47,843 41,975
TOTAL $4,047,038 $3,883,430
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
December 31,
1998 1997
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares $ 260,458 $ 260,458
Paid-in Capital 663,633 613,048
Retained Earnings 179,461 207,544
Total Common Shareholder's Equity 1,103,552 1,081,050
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 19,359 19,747
Subject to Mandatory Redemption 22,310 22,310
Long-term Debt 1,472,451 1,415,026
TOTAL CAPITALIZATION 2,617,672 2,538,133
OTHER NONCURRENT LIABILITIES 120,281 137,371
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 80,004 79,509
Short-term Debt 76,400 130,300
Accounts Payable - General 60,569 52,683
Accounts Payable - Affiliated Companies 50,313 44,133
Taxes Accrued 35,719 41,549
Customer Deposits 14,123 13,713
Interest Accrued 19,990 20,949
Revenue Refunds Accrued 95,267 3,311
Energy Marketing and Trading Contracts 24,076 729
Other 78,808 68,083
TOTAL CURRENT LIABILITIES 535,269 454,959
DEFERRED INCOME TAXES 643,711 658,655
DEFERRED INVESTMENT TAX CREDITS 62,231 67,496
DEFERRED CREDITS 67,874 26,816
COMMITMENTS AND CONTINGENCIES (Note 4)
TOTAL $4,047,038 $3,883,430
See Notes to Consolidated Financial Statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
1998 1997 1996
(in thousands)
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net Income $ 93,330 $ 120,514 $ 133,689
Adjustments for Noncash Items:
Depreciation and Amortization 144,967 138,975 134,381
Deferred Federal Income Taxes (2,338) (5,117) 592
Deferred Investment Tax Credits (5,265) (5,181) (5,602)
Deferred Power Supply Costs (net) 30,081 12,310 293
Provision for Rate Refunds (31,019) 7,601 (2,626)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (1,562) (3,990) (19,176)
Fuel, Materials and Supplies (5,006) 3,950 15,583
Accrued Utility Revenues 5,223 635 13,235
Accounts Payable 14,066 10,924 3,668
Taxes Accrued (5,830) 614 (7,731)
Revenue Refunds Accrued 91,956 (2,272) 5,583
Payment of Disputed Tax and Interest Related to COLI (68,316) - -
Change in Operating Reserves 30,631 16,473 6,906
Other (net) (16,754) (14,923) (3,052)
Net Cash Flows From Operating Activities 274,164 280,513 275,743
INVESTING ACTIVITIES:
Construction Expenditures (204,869) (218,074) (191,815)
Proceeds from Sales of Property and Other 2,930 4,971 1,933
Net Cash Flows Used For Investing Activities (201,939) (213,103) (189,882)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company 50,000 40,000 50,000
Issuance of Long-term Debt 211,944 183,257 273,340
Retirement of Cumulative Preferred Stock (294) (183,875) (25,904)
Retirement of Long-term Debt (157,973) (56,379) (195,910)
Change in Short-term Debt (net) (53,900) 69,600 (64,825)
Dividends Paid on Common Stock (118,916) (114,436) (108,300)
Dividends Paid on Cumulative Preferred Stock (2,278) (5,890) (15,666)
Net Cash Flows Used For Financing Activities (71,417) (67,723) (87,265)
Net Increase (Decrease) in Cash and Cash Equivalents 808 (313) (1,404)
Cash and Cash Equivalents January 1 6,947 7,260 8,664
Cash and Cash Equivalents December 31 $ 7,755 $ 6,947 $ 7,260
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
Year Ended December 31,
1998 1997 1996
(in thousands)
<S> <C> <C> <C>
Retained Earnings January 1 $207,544 $208,472 $199,021
Net Income 93,330 120,514 133,689
300,874 328,986 332,710
Deductions:
Cash Dividends Declared:
Common Stock 118,916 114,436 108,300
Cumulative Preferred Stock:
4-1/2% Series 875 892 1,348
4.50% Series - - 9
5.90% Series 455 455 2,950
5.92% Series 364 364 3,552
6.85% Series 579 579 2,055
7.40% Series - - 1,385
7.80% Series - 931 3,900
Total Cash Dividends Declared 121,189 117,657 123,499
Capital Stock Expense 224 3,785 739
Total Deductions 121,413 121,442 124,238
Retained Earnings December 31 $179,461 $207,544 $208,472
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Organization
Appalachian Power Company (the Company or APCo) is a wholly-owned
subsidiary of American Electric Power Company, Inc. (AEP Co.,
Inc.), a public utility holding company. The Company is engaged in
the generation, purchase, sale, transmission and distribution of
electric power to 888,000 retail customers in southwestern Virginia
and southern West Virginia and does business as American Electric
Power (AEP). The Company supplies electric power to the American
Electric Power System Power Pool (AEP Power Pool) and shares the
revenues and costs of Power Pool wholesale sales to neighboring
utility systems and power marketers. The Company also sells
wholesale power to municipalities. As a member of the American
Electric Power System (AEP System) Power Pool and a signatory
company to the AEP System Transmission Equalization Agreement, the
Company's generation and transmission facilities are operated in
conjunction with the facilities of certain other AEP affiliated
utilities as an integrated utility system.
The Company has four wholly-owned subsidiaries which are
consolidated in these financial statements: Cedar Coal Co., Central
Appalachian Coal Company and Southern Appalachian Coal Company
(which were formerly engaged in coal mining and now lease their
coal reserves to unaffiliated companies) and West Virginia Power
Company (which is inactive).
Regulation
As a subsidiary of AEP Co., Inc., the Company is subject to the
regulation of the Securities and Exchange Commission (SEC) under
the Public Utility Holding Company Act of 1935 (1935 Act). Retail
rates are regulated by the State Corporation Commission of Virginia
(Virginia SCC) and the Public Service Commission of West Virginia
(WVPSC). The Federal Energy Regulatory Commission (FERC) regulates
the Company's wholesale rates.
Principles of Consolidation
The consolidated financial statements include the revenues,
expenses, cash flows, assets, liabilities and equity of APCo and
its wholly-owned subsidiaries. Significant intercompany items are
eliminated in consolidation.
Basis of Accounting
As a cost-based rate-regulated entity, APCo's financial
statements reflect the actions of regulators that result in the
recognition of revenues and expenses in different time periods than
enterprises that are not rate regulated. In accordance with
Statement of Financial Accounting Standards (SFAS) 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.
Utility Plant
Electric utility plant is stated at original cost and is
generally subject to first mortgage liens. Additions, major
replacements and betterments are added to the plant accounts.
Retirements of plant are deducted from the electric utility plant
in service account and deducted from accumulated depreciation
together with associated removal costs, net of salvage. The costs
of labor, materials and overheads incurred to operate and maintain
utility plant are included in operating expenses.
Allowance for Funds Used During Construction (AFUDC)
AFUDC is a noncash nonoperating income item that is capitalized
and recovered through depreciation over the service life of utility
plant. It represents the estimated cost of borrowed and equity
funds used to finance construction projects. In the Virginia
jurisdiction, construction work in progress is included in rate
base and earns a return in regulated rates in lieu of recording
AFUDC. The amounts of AFUDC in 1998, 1997 and 1996 were not
significant.
Depreciation and Amortization
Depreciation of electric utility plant is provided on a
straight-line basis over the estimated useful lives of utility
plant and is calculated largely through the use of composite rates
by functional class. The annual composite depreciation rates for
1998, 1997 and 1996 are as follows:
Annual Composite
Functional Class Depreciation
of Property Rates
Production:
Steam 3.4%
Hydro 2.8%
Transmission 2.2%
Distribution 3.3%
General 3.1%
Expenditures for the demolition and removal of plant are
charged to the accumulated provision for depreciation and recovered
through depreciation charges included in rates.
Cash and Cash Equivalents
Cash and cash equivalents include temporary cash investments
with original maturities of three months or less.
Operating Revenues
Revenues include the accrual of electricity consumed but
unbilled at month-end as well as billed revenues.
Power Supply Costs and Fuel Costs
The Company practices deferred accounting with respect to over
or under collection of certain fuel and power supply costs pursuant
to the Virginia SCC's fuel cost recovery mechanism. In the
Virginia jurisdiction, changes in fuel costs and the fuel portion
of purchased power costs are deferred and reviewed for recovery or
refund annually by the Virginia SCC. In the West Virginia
jurisdiction, under the terms of a 1996 settlement agreement, a
modified version of deferral accounting will be practiced for the
over and under collection of fuel, Power Pool capacity charges and
certain transmission revenue for the period November 1996 through
December 1999. Although a cumulative over and under recovery
balance will be maintained, ratepayers will not be responsible for
any cumulative underrecovery balance at December 31, 1999.
Overrecoveries during the annual periods through December 31, 1999
in excess of $10 million per period would be accumulated and shared
equally between the Company and its ratepayers. Overrecoveries
under $10 million are not shared with rate payers and are included
in operating income annually.
Wholesale jurisdictional fuel cost changes are expensed and
billed as incurred through a FERC fuel clause.
Derivative Financial Instruments
During 1998, the AEP Power Pool substantially increased the
volume of its power marketing and trading transactions (trading
activities) in which the Company shares. Trading activities
involve the 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 net revenues from these transactions are
included in operating revenues for ratemaking, accounting and
financial and regulatory reporting purposes.
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 included in nonoperating income and accounted for on
a mark-to-market basis. 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 forward 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). Any resultant 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 7 - Financial Instruments, Credit and Risk Management
for further discussion.
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 (purchase
and sales are reported on a net basis as revenues). This
reclassification had no impact on net income. Certain prior year
amounts have been reclassified to conform to current year
presentation. Such reclassifications had no impact on previously
reported net income.
Income Taxes
The Company follows the liability method of accounting for
income taxes as prescribed by SFAS 109, "Accounting for Income
Taxes." Under the liability method, deferred income taxes are
provided for all temporary differences between book cost and tax
basis of assets and liabilities which will result in a future tax
consequence. Where the flow-through method of accounting for
temporary differences is reflected in rates, deferred income taxes
are recorded with related regulatory assets and liabilities in
accordance with SFAS 71.
Investment Tax Credits
Investment tax credits have been accounted for under the
flow-through method except where regulatory commissions have reflected
investment tax credits in the rate-making process on a deferral
basis. Investment tax credits that have been deferred are being
amortized over the life of regulated plant investment.
Debt and Preferred Stock
Gains and losses from the reacquisition of debt are deferred
as regulatory assets and amortized over the remaining term of the
reacquired debt in accordance with rate-making treatment. If debt
is refinanced, reacquisition costs are deferred and amortized over
the term of the replacement debt commensurate with their recovery
in rates.
Debt discount or premium and debt issuance expenses are
deferred and 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 the cost of preferred stock reacquired is credited to paid-in
capital and amortized to retained earnings.
Other Property and Investments
Other property and investments are stated at cost.
Comprehensive Income
There were no material differences between net income and
comprehensive income.
2. EFFECTS OF REGULATION:
In accordance with SFAS 71 the consolidated financial
statements include regulatory assets (deferred expenses) and
regulatory liabilities (deferred income) recorded in accordance
with regulatory actions in order to match expenses and revenues
from cost-based rates in the same accounting period. Regulatory
assets are expected to be recovered in future periods through the
rate-making process and regulatory liabilities are expected to
reduce future cost recoveries. Among other things, application of
SFAS 71 requires that the Company's regulated rates be cost-based
and the recovery of regulatory assets must be probable. In the
event a portion of the Company's business were to no longer meet
those requirements, net regulatory assets would have to be written
off for that portion of the business and assets 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.
In February 1999 the Virginia legislature passed comprehensive
legislation, which will become law upon the Governor's signature,
to restructure the electric utility industry. Under the
restructuring bill a transition to choice of supplier for retail
customers will commence on January 1, 2002 and be completed,
subject to a finding by the Virginia SCC that an effective
competitive market exists, on January 1, 2004. Provisions allowing
for an acceleration or limited delay in this schedule are also
contained in the bill. Except as provided in the legislation, the
generation of electricity will not be subject to rate regulation
after January 1, 2002. Additionally, each Virginia electric
utility is required by 2001 to join or establish a regional
transmission entity which will manage and control transmission
assets.
The Virginia restructuring bill also provides an opportunity
for recovery of just and reasonable net stranded costs. Stranded
costs are those costs above market that potentially would not be
recoverable in a competitive market. The mechanisms in the
Virginia legislation for stranded cost recovery are dual: a capping
of incumbent utility rates until as late as July 1, 2007, and the
application of a wires charge upon customers who may depart the
incumbent utility in favor of an alternative supplier prior to the
termination of the rate cap. The legislation provides for the
establishment of capped rates prior to January 1, 2001. The capped
rates may be terminated after January 1, 2004, and prior to July 1,
2007, based upon the Virginia SCC determining that an effective
competitive market exists. The wires charge will be equal to the
difference between the generation component of the capped rates and
the market price for generation service and will be imposed upon
departing customers through the expiration of the rate cap period.
Management has reviewed all the evidence currently available
and concluded that as of December 31, 1998 the requirements to
apply SFAS 71 continue to be met. Virginia rates for generation
will continue to be cost-based regulated until the establishment of
capped rates as provided in the legislation. When capped rates are
established the application of SFAS 71 would be discontinued for
the Virginia retail jurisdiction portion of the generating
business. At that time generation-related regulatory assets
applicable to the Virginia jurisdiction will have to be written off
to the extent that they cannot be recovered under the provisions of
the restructuring legislation and generating assets for the
Virginia retail jurisdiction will have to be evaluated for
impairment. Based upon initial reviews the amount of regulatory
assets applicable to the Virginia generating business at December
31, 1998 is estimated to be $64 million before related tax effects
and any possible offsetting regulatory liabilities. Regulatory
liabilities applicable to the Virginia generation business at
December 31, 1998 are estimated to be $39 million of which $26
million represents deferred investment tax credits. The Company is
evaluating the tax normalization rules regarding the timing of the
reversal of deferred investment tax credits in connection with the
Virginia restructuring legislation. Should it not be possible
under the Virginia legislation to recover any portion of the
generation net regulatory assets, it could have a material adverse
impact on results of operations; however, the amount of any
impairment loss for Virginia retail jurisdictional generating
assets and any loss from a possible inability to recover net
generation regulatory assets cannot be estimated until such time as
capped rates are determined under the legislation.
Recognized regulatory assets and liabilities are comprised of
the following:
December 31,
1998 1997
(in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $374,750 $386,127
Unamortized Loss On
Reacquired Debt 22,827 23,561
Deferred Storm Damage 6,101 8,542
Other 22,515 22,993
Total Regulatory Assets $426,193 $441,223
Regulatory Liabilities:
Deferred Investment Tax
Credits $ 62,231 $67,496
Other* 53,955 21,121
Total Regulatory Liabilities $116,186 $88,617
* Included in Deferred Credits on Consolidated Balance Sheets.
3. RATE MATTERS:
In June 1997 the Company filed an application with the Virginia
SCC for approval, among other things, of an increase of $30.5
million in base rates on an annual basis. In July 1997 the
Virginia SCC suspended implementation of the proposed rates until
November 11, 1997 when rates were placed into effect subject to
refund. On January 11, 1999, the Company and the Virginia SCC
Staff filed a Stipulation agreement with the Virginia SCC which was
approved in February 1999. The Stipulation's main provisions
include the retroactive elimination of the $30.5 million annual
increase in base rates that was being collected subject to refund;
a reduction in base rates of $6 million effective January 1, 1998;
the refund with interest of all amounts collected above the
approved rates; the intention to hold rates at these levels through
December 31, 2000; an investment of at least $90 million in
Virginia distribution facilities between January 1, 1998 and
December 31, 2000 (Plan Period); and a benchmark rate of return on
equity of 10.85% (Benchmark Rate) upon which future earnings will
be tested. During the Plan Period, one-third of any earnings above
the Benchmark Rate will be retained by the Company and the
remaining two-thirds will be refunded to ratepayers. The fuel
factor component of rates will continue to be administered under
current regulation. A refund liability, including interest, of
$51.6 million at December 31, 1998 has been accrued.
In September 1992 the Company implemented, subject to refund,
an $8.7 million annual rate increase to its wholesale customers
pending a final order from the Federal Energy Regulatory Commission
(FERC). On June 29, 1998 the FERC granted an annual rate increase
of $3.4 million and required a refund including interest of amounts
collected in excess of the $3.4 million annual increase. A
rehearing of the FERC's order has been requested. A refund
liability, including interest, of $42.8 million at December 31,
1998 has been accrued.
4. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Substantial construction commitments have been made to support
the Company's utility operations. Such commitments do not include
any expenditures for new generating capacity. Construction
expenditures for 1999-2001 are estimated to be $766 million.
Long-term fuel supply contracts contain clauses that provide
for periodic price adjustments. The contracts are for various
terms, the longest of which extends to 2006, and contain various
clauses that would release the Company from its obligation under
certain force majeure conditions.
Clean Air Act/Air Quality
The United States (US) Environmental Protection Agency (Federal
EPA) is required by the Clean Air Act Amendments of 1990 (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 the AEP System's and the Company'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. The Company's total capital costs to
meet the requirements of Phase II of CAAA are estimated to be
approximately $55 million of which $37 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 AEP System's and 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 Company and the other
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 could result in
required capital expenditures by the Company of approximately $325
million. 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 for the years 1991
to 1993 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 the Company 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 $79 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 and cash flows.
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. RELATED PARTY TRANSACTIONS:
Benefits and costs of the AEP System's generating plants are
shared by members of the AEP Power Pool of which the Company is a
member. Under terms of the System Interconnection Agreement,
capacity charges and credits are designed to allocate the cost of
the System's capacity among the AEP Power Pool members based on
their relative peak demands and generating reserves. AEP Power
Pool members are also compensated for the out-of-pocket costs of
energy delivered to the AEP Power Pool and charged for energy
received from the AEP Power Pool.
Operating revenues include $36.9 million in 1998, $40.1 million
in 1997 and $54.8 million in 1996 for energy supplied to the AEP
Power Pool.
Since the Company's internal peak demand exceeds its generating
capacity, charges for AEP Power Pool capacity reservation, which is
a charge for the right to receive power even if the power is not
taken, and charges for energy received from the AEP Power Pool were
included in purchased power expense as follows:
Year Ended December 31,
1998 1997 1996
(in thousands)
Capacity Charges $ 83,536 $128,680 $125,456
Energy Charges 97,226 149,113 187,754
Total $180,762 $277,793 $313,210
Power marketing and trading operations, which are described in
Note 1, are conducted by the AEP Power Pool and shared with the
Company. The Company's operating revenues, purchased power expense
and nonoperating income include amounts for power marketing and
trading allocated by the AEP Power Pool as follows:
Year Ended December 31,
1998 1997 1996
(in thousands)
Operating Revenues $193,441 $128,041 $126,971
Purchased Power Expense 111,909 27,330 14,700
Nonoperating Loss (11,179) (81) -
<PAGE>
Energy sold directly to Kingsport Power Company (KGPCo), an
affiliated distribution utility that is not a member of the AEP
Power Pool, was included in operating revenues in the amounts of
$56.8 million in 1998, $57.9 million in 1997 and $59.5 million in
1996.
Purchased power expense includes $10.4 million in 1998, $6.4
million in 1997 and $5.1 million in 1996 of energy bought from the
Ohio Valley Electric Corporation, an affiliated company that is not
a member of the AEP Power Pool.
AEP System electric operating utility companies including the
Company participate in the AEP Transmission Equalization Agreement.
This agreement combines certain AEP System companies' investments
in transmission facilities and shares the costs of ownership in
proportion to the System companies' respective peak demands.
Pursuant to the terms of the agreement since the Company's relative
investment in transmission facilities is greater than its relative
peak demands in 1998 and less than its relative peak demands in
1997 and 1996, other operation expense includes equalization
charges (credits) of $(2.4) million, $8.4 million and $6.5 million
in 1998, 1997 and 1996, respectively.
The Company and an affiliate, Ohio Power Company (OPCo),
jointly own two power plants. The costs of operating these
facilities are apportioned between the owners based on ownership
interests. The Company's share of these costs is included in the
appropriate expense accounts on the Consolidated Statements of
Income. The Company's investment in these plants is included in
electric utility plant on the Consolidated Balance Sheets.
American Electric Power Service Corporation (AEPSC) provides
certain managerial and professional services to AEP System
companies including the Company. The costs of the services are
billed to its affiliated clients by AEPSC on a direct-charge basis,
whenever possible, and on reasonable bases of proration for shared
services. The billings for services are made at cost and include
no compensation for the use of equity capital, which is furnished
to AEPSC by AEP Co., Inc. Billings from AEPSC are capitalized or
expensed depending on the nature of the services rendered. AEPSC
and its billings are subject to the regulation of the SEC under the
1935 Act.
6. SEGMENT INFORMATION:
Effective December 31, 1998 the Company adopted SFAS 131,
"Disclosures about Segments of an Enterprise and Related
Information". The Company has one reportable segment, a regulated
vertically integrated electricity generation and energy delivery
business. All other activities are insignificant. The Company's
operations are managed on an integrated basis because of the
substantial impact of bundled cost-based rates and regulatory
oversight on business processes, cost structures and operating
results. Included in the regulated electric utility business is
the power marketing and trading activities that are discussed in
Note 5. For the years ended December 31, 1998, 1997 and 1996, all
of the Company's revenues are derived from the generation, sale and
distribution of electricity in the United States.
7. FINANCIAL INSTRUMENTS, CREDIT AND RISK MANAGEMENT
The Company is subject to market risk as a result of changes
in electricity commodity prices and interest rates. The Company
participates in a power marketing and trading operation that
manages the exposure to electricity 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 within the AEP
System's traditional market area are recorded as net operating
revenues in the month when the physical contract settles. The
Company's share of the net gains from these regulated transactions
for the year ended December 31, 1998 was $33 million. Physical
forward electricity contracts outside AEP's traditional economic
marketing area, and all financial electricity trading transactions
where the underlying physical commodity is outside AEP's
traditional market area are marked to market and recorded in
nonoperating income. The Company's share of the net losses from
these non-regulated trading transactions for the year ended
December 31, 1998 was $11 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.
The Company is exposed to risk from changes in interest rates
primarily due to short-term 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 six years at December 31, 1998. A near term
change in interest rates should not materially affect results of
operations or financial position since the Company would not expect
to liquidate its entire debt portfolio in a one year holding
period. Also since the Company's rates are still cost-based
regulated, the risk of interest rate changes on debt used to
finance regulated operations is mitigated.
Market Valuation
The book value 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 amounts and fair values of the Company's
significant financial instruments at December 31, 1998 and 1997 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. At December 31, 1997 the notional amounts
and fair valves of derivatives were not material.
Book Value Fair Value
(in thousands)
Non-Derivatives
1998
Long-term Debt $1,552,500 $1,638,700
Preferred Stock 22,300 23,400
1997
Long-term Debt 1,494,500 1,572,300
Preferred Stock 22,300 23,400
Derivatives
1998
Fair Value Average Fair Value
(in thousands)
Trading Assets
Electric
Physicals $13,700 $12,200
Options 10,100 24,300
Swaps 1,000 300
Trading Liabilities
Electric
Futures (2,100) (500)
Physicals (14,800) (13,900)
Options (8,900) (23,700)
Swaps (2,300) (600)
At December 31, 1998 the notional amounts of the Company's
non-regulated electric trading physical forward contract purchases and
sales are 3,024 Gigawatt hours (Gwh) and 3,234 Gwh, respectively;
the notional amounts for fixed priced swaps purchases and sales are
111 Gwh and 119 Gwh, respectively; and the notional amounts for
options to purchase and to sell are 2,184 Gwh and 1,570 Gwh,
respectively. The Company has a net long position of 117 Gwh for
electric future contracts.
At December 31, 1998 the fair value of the assets and
liabilities related to the wholesale electric forward contracts was
$110 million and $107 million, respectively. The related notional
amounts were 14,388 Gwh for purchases and 14,682 Gwh for sales.
The average fair value amounts outstanding during the period were
$277 million of assets and $265 million of liabilities.
Credit and Risk Management
In addition to market risk associated with electricity price
movements, the Company through the AEP Power Pool is also subject
to the credit risk inherent in the 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 AEP Power Pool has
established and enforced credit policies that minimize this risk.
The AEP Power Pool 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
Standards & 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 AEP Power Pool requires further credit
enhancements to mitigate risk. Since the formation of the power
marketing and trading business in July of 1997, the Company has
experienced no significant losses due to the credit risk associated
with 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.
8. STAFF REDUCTIONS:
During 1998 an internal evaluation of the power generation
organization was conducted with a goal of developing a better
organizational structure for a competitive generation market. The
study was completed in October 1998. In addition, a review of
energy delivery staffing levels was conducted in 1998. As a result
approximately 180 power generation and energy delivery positions
were identified for elimination.
Severance accruals totaling $7.6 million were recorded by the
Company 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 the first quarter of
1999 the power generation and energy delivery staff reductions were
made.
9. BENEFIT PLANS:
The Company and its subsidiaries participate in the AEP System
qualified pension plan, a defined benefit plan which covers all
employees. Net pension costs for the years ended December 31,
1998, 1997 and 1996 were $0.8 million, $1.9 million and $4.2
million, respectively.
Postretirement Benefits Other Than Pensions are provided for
retired employees for medical and death benefits under an AEP
System plan. The annual accrued costs were $16.6 million in 1998,
$17.3 million in 1997 and $19 million in 1996.
A defined contribution employee savings plan required that the
Company make contributions to the plan totaling $4.3 million in
1998, $4 million in 1997, and $4.1 million in 1996.
<TABLE>
10. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as
follows:
<CAPTION>
Year Ended December 31,
1998 1997 1996
(in thousands)
<S> <C> <C> <C>
Charged (Credited) to Operating Expenses (net):
Current $56,446 $66,810 $71,648
Deferred (143) (4,801) 1,283
Deferred Investment Tax Credits (2,671) (2,697) (2,716)
Total 53,632 59,312 70,215
Charged (Credited) to Nonoperating Income (net):
Current (4,902) (1,677) (837)
Deferred (2,195) (316) (691)
Deferred Investment Tax Credits (2,594) (2,484) (2,886)
Total (9,691) (4,477) (4,414)
Total Federal Income Taxes as Reported $43,941 $54,835 $65,801
The following is a reconciliation of the difference between
the amount of federal income taxes computed by multiplying book
income before federal income taxes by the statutory tax rate, and
the amount of federal income taxes reported.
Year Ended December 31,
1998 1997 1996
(in thousands)
Net Income $ 93,330 $120,514 $133,689
Federal Income Taxes 43,941 54,835 65,801
Pre-tax Book Income $137,271 $175,349 $199,490
Federal Income Taxes on Pre-tax Book Income at
Statutory Rate (35%) $48,045 $61,372 $69,822
Increase (Decrease) in Federal Income Taxes
Resulting From the Following Items:
Depreciation 11,667 10,945 11,932
Corporate Owned Life Insurance (4,212) (3,974) (2,298)
Removal Costs (4,200) (4,200) (5,460)
Investment Tax Credits (net) (5,265) (5,181) (5,602)
Other (2,094) (4,127) (2,593)
Total Federal Income Taxes as Reported $43,941 $54,835 $65,801
Effective Federal Income Tax Rate 32.0% 31.3% 33.0%
</TABLE>
The following tables show the elements of the net deferred tax
liability and the significant temporary differences giving rise to
such deferrals:
December 31,
1998 1997
(in thousands)
Deferred Tax Assets $ 168,898 $ 144,869
Deferred Tax Liabilities (812,609) (803,524)
Net Deferred Tax Liabilities $(643,711) $(658,655)
Property Related Temporary
Differences $(496,464) $(491,904)
Amounts Due From Customers For
Future Federal Income Taxes (106,436) (108,727)
Deferred State Income Taxes (70,644) (75,476)
All Other (net) 29,833 17,452
Net Deferred Tax Liabilities $(643,711) $(658,655)
The Company and its subsidiaries join in the filing of a
consolidated federal income tax return with their affiliated
companies in the AEP System. The allocation of the AEP System's
current consolidated federal income tax to the System companies is
in accordance with SEC rules under the 1935 Act. These rules
permit the allocation of the benefit of current tax losses to the
System companies giving rise to them in determining their current
tax expense. The tax loss of the System parent company, AEP Co.,
Inc., is allocated to its subsidiaries with taxable income. With
the exception of the loss of the parent company, the method of
allocation approximates a separate return result for each company
in the consolidated group.
The AEP System has settled with the 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 the
deductibility of interest deductions related to AEP's corporate
owned life insurance program, which is 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.
11. COMMON SHAREHOLDER'S EQUITY:
The Company received from AEP Co., Inc. cash capital
contributions of $50 million, $40 million and $50 million in 1998,
1997 and 1996, respectively, which were credited to paid-in
capital. In 1998, 1997 and 1996 net changes in paid-in capital of
$585,000, $(2,332,000) and $329,000, respectively, resulted from
gains and (expenses) associated with cumulative preferred stock
transactions. There were no other material transactions affecting
common stock and paid-in capital accounts in 1998, 1997 and 1996.
At December 31, 1998 there were no dividend restrictions on
retained earnings. To pay dividends out of paid-in capital, the
Company needs regulatory approval.
12. CUMULATIVE PREFERRED STOCK:
The authorized number of shares of no par value cumulative
preferred stock is 8,000,000. The aggregate involuntary
liquidation price for all shares of cumulative preferred stock may
not exceed $300 million. The unissued shares of the cumulative
preferred stock may or may not possess mandatory redemption
characteristics upon issuance.
The cumulative preferred stock is callable at the price
indicated plus accrued dividends. The involuntary liquidation
preference is $100 per share.
The Company redeemed and canceled 500,000 shares of the 7.80%
series and 2,348 shares of the 4.50% series subject to mandatory
redemption in 1997 and 1996, respectively. The Company redeemed
and canceled 250,000 shares of the 7.40% series not subject to
mandatory redemption in 1996.
Cumulative Preferred Stock Not Subject to Mandatory Redemption:
<TABLE>
<CAPTION>
Call Price Shares Amount
December 31, Number of Shares Redeemed Outstanding December 31,
Series 1998 Year Ended December 31, December 31, 1998 1998 1997
1998 1997 1996 (in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
4-1/2% $110.00 3,878 100,685 1,850 193,587 $19,359 $19,747
</TABLE>
<TABLE>
Cumulative Preferred Stock Subject to Mandatory Redemption:
<CAPTION>
Call Price
December 31, Number of Shares Redeemed Outstanding December 31,
Series(a) 1998 Year Ended December 31, December 31, 1998 1998 1997
1998 1997 1996 (in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
5.90% (b) $ (d) - 422,900 - 77,100 $ 7,710 $ 7,710
5.92% (b) (d) - 538,500 - 61,500 6,150 6,150
6.85% (c) (e) - 215,500 - 84,500 8,450 8,450
$22,310 $22,310
(a) The sinking fund provisions of each series have been met by
purchase of shares in advance of the due date.
(b) Commencing in 2003 and continuing through 2007 the Company may
redeem at $100 per share 25,000 shares of the 5.90% series and 30,000
shares of the 5.92% series outstanding under sinking fund provisions
at its option and all outstanding shares must be reacquired in 2008.
Shares redeemed in 1997 may be applied to meet the sinking fund
requirement.
(c) Commencing in 2000 and continuing through date of redemption, a
sinking fund for the 6.85% cumulative preferred stock will require the
redemption of 60,000 shares each year, in each case at $100 per share.
The Company has the non-cumulative option to redeem up to 60,000
additional shares on any sinking fund date at a redemption price of
$100 per share. Shares redeemed in 1997 may be applied to meet the
sinking fund requirement.
(d) Not callable until after 2002.
(e) Not callable until after 1999.
</TABLE>
<PAGE>
13. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1998 1997
(in thousands)
First Mortgage Bonds $ 960,597 $1,096,811
Installment Purchase
Contracts 234,262 234,217
Senior Unsecured Notes 193,959 -
Junior Debentures 161,087 160,948
Other Long-term Debt 2,550 2,559
1,552,455 1,494,535
Less Portion Due Within
One Year 80,004 79,509
Total $1,472,451 $1,415,026
First mortgage bonds outstanding were as follows:
December 31,
1998 1997
(in thousands)
% Rate Due
7.00 1999 - December 1 $ 30,000 $ 30,000
6.35 2000 - March 1 48,000 48,000
6.71 2000 - June 1 48,000 48,000
6-3/8 2001 - March 1 100,000 100,000
7.95 2002 - March 1 - 60,000
7.38 2002 - August 15 50,000 50,000
7.40 2002 - December 1 30,000 30,000
6.65 2003 - May 1 40,000 40,000
6.85 2003 - June 1 30,000 30,000
6.00 2003 - November 1 30,000 30,000
7.70 2004 - September 1 21,000 21,000
7.85 2004 - November 1 (a) 50,000 50,000
8.00 2005 - May 1 50,000 50,000
6.89 2005 - June 22 30,000 30,000
6.80 2006 - March 1 100,000 100,000
8.75 2022 - February 1 - 29,919
8.70 2022 - May 22 - 35,000
8.43 2022 - June 1 37,471 50,000
8.50 2022 - December 1 70,000 70,000
7.80 2023 - May 1 40,000 40,000
7.90 2023 - June 1 30,000 30,000
7.15 2023 - November 1 30,000 30,000
7.125 2024 - May 1 50,000 50,000
8.00 2025 - June 1 50,000 50,000
Unamortized Discount (3,874) (5,108)
960,597 1,096,811
Less Portion Due Within
One Year 80,000 60,000
Total $ 880,597 $1,036,811
(a) A one time put feature allows this series of bonds to be put
back to the Company on November 1, 1999. Consequently the
bonds are classified as due in 1999.
Certain indentures relating to the first mortgage bonds
contain improvement, maintenance and replacement provisions requiring
the deposit of cash or bonds with the trustee, or in lieu thereof,
certification of unfunded property additions.
Installment purchase contracts have been entered into, in
connection with the issuance of pollution control revenue bonds by
governmental authorities as follows:
December 31,
1998 1997
(in thousands)
% Rate Due
Industrial Development Authority of
Russell County, Virginia:
7-1/4 1998 - November 1 $ - $ 19,500
7.70 2007 - November 1 17,500 17,500
5.00 2021 - November 1 19,500 -
Putnam County, West Virginia:
5.45 2019 - June 1 40,000 40,000
6.60 2019 - July 1 30,000 30,000
Mason County, West Virginia:
7-7/8 2013 - November 1 10,000 10,000
7.40 2014 - January 1 30,000 30,000
6.85 2022 - June 1 40,000 40,000
6.60 2022 - October 1 50,000 50,000
Unamortized Discount (2,738) (2,783)
234,262 234,217
Less Portion Due Within
One Year - 19,500
Total $234,262 $214,717
Under the terms of the installment purchase contracts, the
Company is required to pay amounts sufficient to enable the payment
of interest on and the principal (at stated maturities and upon
mandatory redemptions) of related pollution control revenue bonds
issued to finance the construction of pollution control facilities at
certain plants.
<PAGE>
Senior unsecured notes outstanding were as follows:
December 31,
1998 1997
(in thousands)
% Rate Due
7.20 2038 - March 31 $100,000 $ -
7.30 2038 - June 30 100,000 -
Unamortized Discount (6,041) -
Total $193,959 $ -
Junior debentures outstanding were as follows:
December 31,
1998 1997
(in thousands)
8-1/4% Series A due 2026
- September 30 $ 75,000 $ 75,000
8% Series B due 2027
- March 31 90,000 90,000
Unamortized Discount (3,913) (4,052)
Total $161,087 $160,948
Interest may be deferred and payment of principal and interest
on the junior debentures is subordinated and subject in right to the
prior payment in full of all senior indebtedness of the Company.
At December 31, 1998, future annual long-term debt payments
are as follows:
Amount
(in thousands)
1999 $ 80,004
2000 96,005
2001 100,006
2002 80,006
2003 100,007
Later Years 1,112,993
Total Principal Amount 1,569,021
Unamortized Discount (16,566)
Total $1,552,455
Short-term debt borrowings are limited by provisions of the
1935 Act to $325 million. Lines of credit are shared with other AEP
System companies and at December 31, 1998 and 1997 were available in
the amounts of $763 million and $442 million, respectively. Facility
fees of approximately 1/10 of 1% of the short-term line of credit are
required to maintain the lines of credit. Outstanding short-term debt
consisted of:
<PAGE>
Year-end
Balance Weighted
Outstanding Average
(in thousands) Interest Rate
December 31, 1998:
Notes Payable $34,600 5.7%
Commercial Paper 41,800 6.2%
Total $76,400 6.0%
December 31, 1997:
Notes Payable $ 33,700 6.5%
Commercial Paper 96,600 6.8%
Total $130,300 6.7%
14. LEASES:
Leases of property, plant and equipment are for periods of up
to 30 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.
<PAGE>
Lease rentals for both operating and capital leases are
generally charged to operating expenses in accordance with rate-making
treatment. The components of rental costs are as follows:
Year Ended December 31,
1998 1997 1996
(in thousands)
Operating Leases $ 7,047 $ 8,016 $ 9,567
Amortization of
Capital Leases 13,561 11,771 12,175
Interest on Capital Leases 3,541 3,290 3,416
Total Rental Costs $24,149 $23,077 $25,158
Properties under capital leases and related obligations
recorded on the Consolidated Balance Sheets are as follows:
December 31,
1998 1997
(in thousands)
Electric Utility Plant Under Capital Leases:
Production Plant $ 9,463 $10,553
General Plant 87,776 77,980
Total Electric Utility Plant
Under Capital Leases 97,239 88,533
Accumulated Amortization 32,064 28,423
Net Properties Under Capital Leases $65,175 $60,110
Capital Lease Obligations*:
Noncurrent Liability $52,429 $48,552
Liability Due Within One Year 12,746 11,558
Total Capital Lease Obligations $65,175 $60,110
*Represents the present value of future minimum lease payments.
Capital lease obligations are included in other noncurrent and
other current liabilities on the Consolidated Balance Sheets.
Properties under operating leases and related obligations are not
included in the Consolidated Balance Sheets.
<PAGE>
Future minimum lease payments consisted of the following at
December 31, 1998:
Non-
Cancelable
Capital Operating
Leases Leases
(in thousands)
1999 $16,704 $2,227
2000 14,453 1,991
2001 12,235 932
2002 11,158 415
2003 8,222 413
Later Years 17,018 3,712
Total Future Minimum
Lease Rentals 79,790 $9,690
Less Estimated Interest
Element 14,615
Estimated Present Value
of Future Minimum
Lease Payments $65,175
15. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1998 1997 1996
(in thousands)
Cash was paid for:
Interest (net of
capitalized amounts) $124,027 $115,508 $104,156
Income Taxes $65,102 $71,749 $82,194
Noncash Acquisitions Under
Capital Leases $21,146 $15,266 $15,308
16. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
(in thousands)
1998
March 31 $415,366 $64,249 $33,199
June 30 403,080 46,192 15,124
September 30 474,476 70,951 33,446
December 31 379,322 47,151 11,561
1997
March 31 416,450 64,334 36,484
June 30 373,084 45,397 15,378
September 30 413,532 64,780 34,753
December 31 425,449 65,483 33,899
Fourth quarter 1998 net income declined primarily as a result of
unseasonably mild weather, provisions for rate refunds recorded for
the Virginia retail jurisdiction and severance accruals for staff
reductions.
See "Reclassification" section in Note 1 regarding reclassification
of prior period amounts.
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Appalachian Power Company:
We have audited the accompanying consolidated balance sheets of
Appalachian Power Company 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 Appalachian Power
Company 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>
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
333-20305 and 333-42593 of Appalachian Power Company 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 Appalachian Power Company for the year ended
December 31, 1998.
Deloitte & Touche LLP
Columbus, Ohio
March 29, 1999
<PAGE>
Exhibit 24
POWER OF ATTORNEY
APPALACHIAN POWER COMPANY
Annual Report on Form lO-K for the Fiscal Year
Ended
December 31, 1998
The undersigned directors of APPALACHIAN POWER COMPANY, a Virginia
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/ E. Linn Draper, Jr. /s/ James J. Markowsky
E. Linn Draper, Jr. James J. Markowsky
/s/ Henry W. Fayne /s/ Armando A. Pena
Henry W. Fayne Armando A. Pena
/s/ Wm. J. Lhota /s/ J. H. Vipperman
Wm. J. Lhota J. H. Vipperman
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000006879
<NAME> APPALACHIAN POWER COMPANY
<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> 3,102,503
<OTHER-PROPERTY-AND-INVEST> 111,020
<TOTAL-CURRENT-ASSETS> 359,479
<TOTAL-DEFERRED-CHARGES> 47,843
<OTHER-ASSETS> 426,193
<TOTAL-ASSETS> 4,047,038
<COMMON> 260,458
<CAPITAL-SURPLUS-PAID-IN> 663,633
<RETAINED-EARNINGS> 179,461
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,103,552
22,310
19,359
<LONG-TERM-DEBT-NET> 1,472,451
<SHORT-TERM-NOTES> 34,600
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 41,800
<LONG-TERM-DEBT-CURRENT-PORT> 80,004
0
<CAPITAL-LEASE-OBLIGATIONS> 52,429
<LEASES-CURRENT> 12,746
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,207,787
<TOT-CAPITALIZATION-AND-LIAB> 4,047,038
<GROSS-OPERATING-REVENUE> 1,672,244
<INCOME-TAX-EXPENSE> 60,477
<OTHER-OPERATING-EXPENSES> 1,383,224
<TOTAL-OPERATING-EXPENSES> 1,443,701
<OPERATING-INCOME-LOSS> 228,543
<OTHER-INCOME-NET> (8,301)
<INCOME-BEFORE-INTEREST-EXPEN> 220,242
<TOTAL-INTEREST-EXPENSE> 126,912
<NET-INCOME> 93,330
2,497
<EARNINGS-AVAILABLE-FOR-COMM> 90,833
<COMMON-STOCK-DIVIDENDS> 118,916
<TOTAL-INTEREST-ON-BONDS> 72,057
<CASH-FLOW-OPERATIONS> 274,164
<EPS-PRIMARY> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1> All common stock owned by parent company; no EPS required.
</FN>
</TABLE>
