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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 ______________
COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER
FILE NUMBER ADDRESS AND TELEPHONE NUMBER IDENTIFICATION NO.
- ----------- ---------------------------- ------------------
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640
(A New York Corporation)
1 Riverside Plaza
Columbus, Ohio 43215
Telephone (614) 223-1000
0-18135 AEP GENERATING COMPANY 31-1033833
(An Ohio Corporation)
1 Riverside Plaza
Columbus, Ohio 43215
Telephone (614) 223-1000
1-3457 APPALACHIAN POWER COMPANY 54-0124790
(A Virginia Corporation)
40 Franklin Road, S.W.
Roanoke, Virginia 24011
Telephone (540) 985-2300
1-2680 COLUMBUS SOUTHERN POWER COMPANY 31-4154203
(An Ohio Corporation)
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
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.
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE
REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED
---------- ------------------- -------------------
AEP Generating Company None
American Electric Power Common Stock,
Company, Inc. $6.50 par value................................... New York Stock Exchange
Appalachian Power Cumulative Preferred Stock,
Company Voting, no par value:
4-1/2%........................................... Philadelphia Stock Exchange
8-1/4% Junior Subordinated Deferrable
Interest Debentures, Series A,
Due 2026........................................ New York Stock Exchange
8% Junior Subordinated Deferrable
Interest Debentures, Series B,
Due 2027........................................ New York Stock Exchange
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
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]
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SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
REGISTRANT TITLE OF EACH CLASS
---------- -------------------
AEP Generating Company None
American Electric Power Company, Inc None
Appalachian Power Company None
Columbus Southern Power Company None
Indiana Michigan Power Company 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
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
------------------------ ------------------
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)
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).
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DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K
INTO WHICH DOCUMENT
DESCRIPTION IS INCORPORATED
- ----------- ---------------
Portions of Annual Reports of the following companies for the fiscal year 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
------------------------------
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 OF CONTENTS
PAGE
NUMBER
------
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
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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.
TERM MEANING
---- -------
AEGCo................................ AEP Generating Company, an electric utility subsidiary of AEP.
AEP ................................. American Electric Power Company, Inc.
AEP System or the System............. The American Electric Power System, an integrated electric utility system,
owned and operated by AEP's electric utility subsidiaries.
AFUDC................................ Allowance for funds used during construction. Defined in regulatory systems
of accounts as the net cost of borrowed funds used for construction and a
reasonable rate of return on other funds when so used.
APCo................................. Appalachian Power Company, an electric utility subsidiary of AEP.
Buckeye.............................. Buckeye Power, Inc., an unaffiliated corporation.
CCD Group............................ CSPCo, CG&E and DP&L.
CG&E................................. The Cincinnati Gas & Electric Company, an unaffiliated utility company.
Cook Plant........................... The Donald C. Cook Nuclear Plant, owned by I&M.
CSPCo................................ Columbus Southern Power Company, an electric utility subsidiary of AEP.
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.
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[THIS PAGE INTENTIONALLY LEFT BLANK]
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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
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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
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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.
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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:
AEP
AEGCO APCO CSPCO I&M KEPCO OPCO SYSTEM (a)
-------- ---------- ---------- ---------- -------- ---------- ----------
(IN THOUSANDS)
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
======== ========== ========== ========== ======== ========== ==========
- ----------------------------
(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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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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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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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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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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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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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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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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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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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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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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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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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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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:
TOTAL AEP
SHORT-TERM DEBT AEP AEGCO APCO CSPCO I&M KEPCO OPCO SYSTEM(a)
--------------- --- ----- ---- ----- --- ----- ---- ---------
(IN MILLIONS)
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
==== === ==== ==== ==== ==== ==== ======
- ------------------
(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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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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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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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.